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, 1998 
                               ------------------------------------------------
                                       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 Number 1-2313

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

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

         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 (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 October 30, 1998
--------------------------------------       -----------------------------------
       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, 1998, and 1997               2

           Consolidated Statements of Comprehensive Income --
             Three, Nine and Twelve Months Ended September 30, 1998,
             and 1997                                                       2

           Consolidated Balance Sheets -- September 30, 1998,
             December 31, 1997, and September 30, 1997                      3

           Consolidated Statements of Cash Flows --
             Three, Nine and Twelve Months Ended
             September 30, 1998, and 1997                                   5

           Consolidated Statements of Retained Earnings --
             Three, Nine and Twelve Months Ended
             September 30, 1998, and 1997                                   6

           Notes to Consolidated Financial Statements                       7

   Item 2. Management's Discussion and Analysis of Results
               of Operations and Financial Condition                       28

Part II.   Other Information:

   Item 1. Legal Proceedings                                               41

   Item 6. Exhibits and Reports on Form 8-K                                46




<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, 1998,  December 31, 1997,  and  September 30, 1997,  and the
related  consolidated  statements  of  income,  comprehensive  income,  retained
earnings and cash flows for each of the three-,  nine- and twelve-month  periods
ended  September  30,  1998,  and  1997.  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, 1998,  December 31, 1997,  and September 30, 1997, and the results
of their  operations  and their  cash  flows for each of the  three-,  nine- and
twelve-month  periods  ended  September 30, 1998,  and 1997, in conformity  with
generally accepted accounting principles.



                                                     ARTHUR ANDERSEN LLP
                                                     ARTHUR ANDERSEN LLP



Los Angeles, California
October 29, 1998


                                       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,
-----------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-----------------------------------------------------------------------------------------------------------------------
<S>                                <C>           <C>           <C>          <C>           <C>           <C>       
Sales to ultimate consumers        $2,258,782    $2,349,316    $5,336,067   $5,740,733    $7,234,752    $7,533,218
Sales to power exchange               687,171            --       990,856           --       990,856            --
Other                                 110,716        84,273       274,903      232,291       356,582       305,548
------------------------------------------------------------------------------------------------------------------
Operating revenue                   3,056,669     2,433,589     6,601,826    5,973,024     8,582,190     7,838,766
-----------------------------------------------------------------------------------------------------------------------
Fuel                                   64,621       423,272       242,489      714,078       409,882       882,673
Purchased power - contracts           908,407       900,781     2,010,269    2,117,116     2,747,155     2,796,234
Purchased power - power exchange    1,080,910            --     1,424,694           --     1,424,694            --
Provisions for regulatory
   adjustment clauses -- net         (447,676)     (185,416)     (289,314)    (277,439)     (422,811)     (333,133)
Other operating expenses              437,065       303,511     1,124,693      838,907     1,502,105     1,142,266
Maintenance                           104,265        89,679       304,627      302,255       407,916       414,004
Depreciation, decommissioning and
   amortization                       378,189       313,377     1,137,087      930,445     1,446,518     1,198,882
Income taxes                          172,015       208,492       396,777      437,373       541,434       555,468
Property and other taxes               31,642        31,169       102,406      101,388       130,055       143,925
Loss (gain) on sale of utility plant   89,939          (271)     (529,099)      (3,106)     (529,840)       (4,855)
-----------------------------------------------------------------------------------------------------------------------
Total operating expenses            2,819,377     2,084,594     5,924,629    5,161,017     7,657,108     6,795,464
-----------------------------------------------------------------------------------------------------------------------
Operating income                      237,292       348,995       677,197      812,007       925,082     1,043,302
-----------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan           --       (13,218)           --      (35,908)      (12,578)      (50,230)
Allowance for equity funds
   used during construction             3,051         1,691         8,740        5,591        10,800        10,236
Interest and dividend income           18,031        10,875        51,754       27,034        69,356        38,200
Other nonoperating income
   (deductions) -- net                 27,672       (12,527)       19,774       (2,032)       (1,234)       (3,864)
-----------------------------------------------------------------------------------------------------------------------
Total other income (deductions) -- net 48,754       (13,179)       80,268       (5,315)       66,344        (5,658)
-----------------------------------------------------------------------------------------------------------------------
Income before interest expense        286,046       335,816       757,465      806,692       991,426     1,037,644
-----------------------------------------------------------------------------------------------------------------------
Interest on long-term debt            103,916        77,758       319,784      259,503       405,873       354,062
Other interest expense                 16,032        27,104        50,142       72,879        78,342        91,783
Allowance for borrowed funds used
   during construction                 (2,076)       (2,036)       (5,947)      (6,733)       (8,427)       (9,653)
Capitalized interest                     (330)         (265)         (612)      (2,320)         (691)       (3,383)
-----------------------------------------------------------------------------------------------------------------------
Total interest expense -- net         117,542       102,561       363,367      323,329       475,097       432,809
-----------------------------------------------------------------------------------------------------------------------
Net income                            168,504       233,255       394,098      483,363       516,329       604,835
Dividends on preferred stock            5,612         6,758        19,019       22,729        25,778        31,328
-----------------------------------------------------------------------------------------------------------------------
Earnings available for common stock $ 162,892     $ 226,497     $ 375,079    $ 460,634     $ 490,551     $ 573,507
-----------------------------------------------------------------------------------------------------------------------

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands

                                          3 Months Ended             9 Months Ended              12 Months Ended
                                           September 30,              September 30,               September 30,
-----------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-----------------------------------------------------------------------------------------------------------------------
Net income                          $168,504       $233,255    $ 394,098      $483,363      $516,329      $604,835
Unrealized gain (loss) on 
  securities -- net                  (21,631)       (10,940)      (9,189)        3,508         1,944         7,162
-----------------------------------------------------------------------------------------------------------------------
Comprehensive income                $146,873       $222,315     $384,909      $486,871      $518,273      $611,997
-----------------------------------------------------------------------------------------------------------------------
</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,
                                                                 1998                1997               1997
----------------------------------------------------------------------------------------------------------------------
ASSETS
Transmission and distribution:
   Utility plant, at original cost, subject to
<S>                                                           <C>                 <C>                <C>        
      cost-based rate regulation                              $11,591,649         $11,213,352        $11,087,199
   Accumulated provision for depreciation                      (5,841,948)         (5,573,742)        (5,294,706)
   Construction work in progress                                  504,388             492,614            461,850
----------------------------------------------------------------------------------------------------------------------
                                                                6,254,089           6,132,224          6,254,343
----------------------------------------------------------------------------------------------------------------------
Generation:
   Utility plant, at original cost,
      not subject to cost-based rate regulation                 1,728,929           9,522,127          9,502,679
   Accumulated provision for depreciation,
      decommissioning and amortization                           (923,158)         (4,970,137)        (4,800,890)
   Construction work in progress                                   78,181             100,283             71,598
   Nuclear fuel, at amortized cost                                141,569             154,757            167,682
----------------------------------------------------------------------------------------------------------------------
                                                                1,025,521           4,807,030          4,941,069
----------------------------------------------------------------------------------------------------------------------
Total utility plant                                             7,279,610          10,939,254         11,195,412
----------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision
   for depreciation of $25,381, $24,730
   and $24,450 at respective dates                                 74,940              67,869             67,192
Nuclear decommissioning trusts                                  2,013,293           1,831,460          1,608,465
Other investments                                                 210,116             171,399            124,093
----------------------------------------------------------------------------------------------------------------------
Total other property and investments                            2,298,349           2,070,728          1,799,750
----------------------------------------------------------------------------------------------------------------------
Cash and equivalents                                              284,312             962,272             96,051
Receivables, including unbilled revenue, less
   allowances of $20,235, $26,453 and $21,981
   for uncollectible accounts at respective dates               1,266,361             906,388          1,208,001
Fuel inventory                                                     50,561              58,059             57,027
Materials and supplies, at average cost                           121,408             132,980            148,762
Accumulated deferred income taxes -- net                          269,277             123,146            191,563
Regulatory balancing accounts -- net                              407,536             193,311            100,935
Prepayments and other current assets                              127,168              93,098            126,174
----------------------------------------------------------------------------------------------------------------------
Total current assets                                            2,526,623           2,469,254          1,928,513
----------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment -- net                           2,387,998                  --                 --
Unamortized debt issuance and reacquisition
   expense                                                        356,018             359,304            353,060
Rate phase-in plan                                                     --               3,777             16,220
Income tax-related deferred charges                             1,454,606           1,543,380          1,581,243
Other deferred charges                                            915,612             673,601            684,958
----------------------------------------------------------------------------------------------------------------------
Total deferred charges                                          5,114,234           2,580,062          2,635,481
----------------------------------------------------------------------------------------------------------------------
Total assets                                                  $17,218,816         $18,059,298        $17,559,156
----------------------------------------------------------------------------------------------------------------------
</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,
                                                                1998               1997                  1997
----------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES

Common shareholder's equity:
   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                                     334,031             334,031            334,032
   Accumulated other comprehensive income                          38,834              48,023             36,890
   Retained earnings                                              819,941           1,407,834          2,559,319
----------------------------------------------------------------------------------------------------------------------
                                                                3,360,860           3,957,942          5,098,295
----------------------------------------------------------------------------------------------------------------------
Preferred stock:
   Not subject to mandatory redemption                            128,755             183,755            183,755
   Subject to mandatory redemption                                255,700             275,000            275,000
Long-term debt                                                  5,486,384           6,144,597          4,105,221
----------------------------------------------------------------------------------------------------------------------
Total capitalization                                            9,231,699          10,561,294          9,662,271
----------------------------------------------------------------------------------------------------------------------
Other long-term liabilities                                       515,930             479,637            504,734
----------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt                                 593,311             692,875            276,575
Short-term debt                                                   105,780             322,028            770,300
Accounts payable                                                  640,409             406,704            459,142
Accrued taxes                                                     832,331             509,270            803,253
Accrued interest                                                   70,506              85,406             81,707
Dividends payable                                                  91,943              95,146            101,136
Deferred unbilled revenue and other current
   liabilities                                                  1,162,644             931,856            923,167
----------------------------------------------------------------------------------------------------------------------
Total current liabilities                                       3,496,924           3,043,285          3,415,280
----------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes -- net                        2,880,334           2,939,471          2,957,710
Accumulated deferred investment tax credits                       302,539             326,728            331,890
Customer advances and other deferred credits                      791,081             708,745            687,271
----------------------------------------------------------------------------------------------------------------------
Total deferred credits                                          3,973,954           3,974,944          3,976,871
----------------------------------------------------------------------------------------------------------------------
Minority interest                                                     309                 138                 --
----------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
   (Notes 2, 8, 9 and 10)




Total capitalization and liabilities                          $17,218,816         $18,059,298        $17,559,156
----------------------------------------------------------------------------------------------------------------------
</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,
----------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
----------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
<S>                                    <C>         <C>          <C>          <C>            <C>           <C>     
Net income                             $168,504    $233,255     $394,098     $483,363       $516,329      $604,835
Adjustments for non-cash items:
  Depreciation, decommissioning and
     amortization                      378,189     313,377    1,137,087      930,445      1,446,518     1,198,882
  Other amortization                    45,059      23,088      117,631       55,069        143,925        67,983
  Rate phase-in plan                        --      12,899        3,777       34,483         16,220        49,692
  Deferred income taxes and
    investment tax credits              66,342     (11,481)    (140,683)     (19,500)       (57,804)      138,645
  Other long-term liabilities           20,227      (1,332)      36,293       80,809         11,196       156,968
  Regulatory asset related to sale of
    utility plant                     (111,310)         --     (219,301)          --       (219,301)           --
  Loss (gain) on sale of oil and 
    gas plant                           88,355          --     (551,984)          --       (551,984)           --
  Other -- net                         (35,613)   (120,958)     (89,946)    (188,315)      (110,251)     (350,191)
Changes in working capital:
  Receivables                         (235,569)   (225,991)    (359,973)    (286,918)       (58,360)      (85,753)
  Regulatory balancing accounts       (357,302)   (187,451)    (214,225)    (282,423)      (306,601)     (306,988)
  Fuel inventory, materials and 
    supplies                            (4,326)      9,243       19,070       20,957         33,820        24,233
  Prepayments and other current
    assets                            (112,028)   (108,896)     (34,070)     (21,037)          (994)       17,056
  Accrued interest and taxes           (87,083)    137,103      308,161      306,909         17,877      (131,220)
  Accounts payable and other
    current liabilities                357,382     226,626      464,493      164,213        420,744       (23,701)
----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating 
  activities                           180,827     299,482      870,428    1,278,055      1,301,334     1,360,441
----------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt repaid                    (1,575)   (716,090)    (606,030)    (916,145)      (606,030)     (916,068)
Rate reduction notes issued                  --          --           --           --      2,444,127            --
Rate reduction notes repaid             (78,605)         --     (161,070)          --       (155,908)           --
Preferred stock redeemed                 (1,000)         --      (74,300)    (100,000)       (74,300)     (100,000)
Nuclear fuel financing -- net             7,393      (5,567)     (11,478)     (12,628)       (18,990)        8,665
Short-term debt financing -- net        (15,775)    625,056     (216,248)     540,151       (664,520)      494,958
Capital transferred                          --     153,000           --      153,000             --       153,000
Dividends paid                         (429,124)   (297,306)    (982,146)    (595,448)    (2,258,643)     (802,524)
----------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities  (518,686)   (240,907)  (2,051,272)    (931,070)    (1,334,264)   (1,161,969)
----------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant        (211,272)   (160,142)    (548,319)    (443,788)      (789,850)     (572,542)
Proceeds from sale of plant              43,000          --    1,188,039           --      1,188,039            --
Funding of nuclear decommissioning 
   trusts                               (41,315)    (34,629)    (118,196)    (109,202)      (162,750)     (147,119)
Unrealized gain (loss) on 
   securities -- net                    (21,631)    (10,940)      (9,189)       3,508          1,944         7,162
Other -- net                             22,447       3,806       (9,451)     (21,394)       (16,192)      (39,372)
----------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by
   investing activities                (208,771)   (201,905)     502,884     (570,876)       221,191      (751,871)
----------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash
   and equivalents                     (546,630)   (143,330)    (677,960)    (223,891)       188,261      (553,399)
Cash and equivalents, beginning
   of period                            830,942     239,381      962,272      319,942         96,051       649,450
----------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period    $284,312    $ 96,051     $284,312     $ 96,051       $284,312      $ 96,051
----------------------------------------------------------------------------------------------------------------------
Cash payments for interest and taxes:
Interest -- net of amounts capitalized $ 91,821    $ 74,261     $217,488     $250,561       $309,063      $341,635
Taxes                                   325,666     198,494      326,092      215,966        548,129       535,679

</TABLE>


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


                                       5
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
In thousands
<TABLE>
<CAPTION>

                                          3 Months Ended             9 Months Ended              12 Months Ended
                                           September 30,              September 30,               September 30,
-----------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-----------------------------------------------------------------------------------------------------------------------

<S>                                  <C>          <C>          <C>           <C>           <C>           <C>       
Balance at beginning of period       $1,078,982   $2,554,389   $1,407,834    $2,665,612    $2,559,319    $2,748,983
Net income                              168,504      233,255      394,098       483,363       516,329       604,835
Dividends declared on common stock     (421,765)    (216,738)    (959,633)     (562,099)   (2,226,574)     (758,342)
Dividends declared on preferred stock    (5,612)      (6,758)     (19,019)      (22,729)      (25,778)      (31,328)
Stock option appreciation                  (168)          --       (3,339)           --        (3,339)           --
Reacquired capital stock expense and other   --       (4,829)          --        (4,828)          (16)       (4,829)
-----------------------------------------------------------------------------------------------------------------------
Balance at end of period             $  819,941   $2,559,319   $  819,941    $2,559,319    $  819,941    $2,559,319
-----------------------------------------------------------------------------------------------------------------------

</TABLE>















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




                                       6
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.    Summary of Significant Accounting Policies

Accounting Principles

Southern  California  Edison  Company's (SCE)  accounting  policies conform with
generally accepted accounting  principles,  including the accounting  principles
for  rate-regulated  enterprises  which reflect the rate-making  policies of the
California Public Utilities  Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring  legislation enacted by
the State of California  and a related  change in the  application of accounting
principles for rate-regulated  enterprises  adopted by the Financial  Accounting
Standards Board's Emerging Issues Task Force,  during the third quarter of 1997,
SCE began  accounting for its investment in generation  facilities in accordance
with  accounting  principles  applicable to  enterprises  in general,  and SCE's
balance  sheets  display a separate  caption for its  investments in generation.
Application of such  accounting  principles to SCE's  generation  assets did not
result  in any  adjustment  of their  carrying  value;  however,  SCE's  nuclear
investments were reclassified as a regulatory asset in second quarter 1998.

Competition Transition Charge (CTC)

Beginning  January  1,  1998,  a  non-bypassable  charge is being  billed to all
customers, which provides SCE the opportunity to recover its costs to transition
to a competitive market.

Consolidation Policy

The  consolidated   financial  statements  include  SCE  and  its  subsidiaries.
Intercompany transactions have been eliminated.

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 electric utility restructuring, decommissioning and contingencies are
further discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements,
respectively.

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.

Nature of Operations

SCE's outstanding  common stock is owned entirely by its parent company,  Edison
International.  SCE is a public  utility  which  produces and supplies  electric
energy  for its 4.3  million  customers  in  Central  and  Southern  California.
Effective  April 1, 1998,  SCE sells all electric  energy  produced to the power
exchange (PX), as mandated by state legislation.  SCE also purchases electricity
from the PX to supply  to its  customers.  SCE  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 further discussed in Note 2 to the
Consolidated Financial Statements.


                                       7
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nuclear

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

Under  federal  law,  SCE is  liable  for its  share of the  estimated  costs to
decommission three federal nuclear  enrichment  facilities (based on purchases).
These costs,  which will be paid over 15 years,  are recorded as a fuel cost and
recovered through non-bypassable customer rates.

In April  1996,  the  CPUC  authorized  acceleration  of the  recovery  of SCE's
remaining  investment of $2.6 billion in San Onofre Nuclear  Generating  Station
Units 2 and 3. The  accelerated  recovery will continue  through  December 2001,
earning a 7.35% fixed rate of return.  Operating costs,  including  nuclear fuel
and nuclear fuel financing  costs, and incremental  capital  expenditures at San
Onofre  Units 2 and 3 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.  Beginning January 1, 1998, the accelerated plant recovery and the
incentive pricing plan became part of the CTC mechanism.  Beginning in 2004, SCE
will be required to share equally with ratepayers the net benefits received from
operation of the units.

In January 1997, the CPUC  authorized an  acceleration  of the recovery of SCE's
remaining  investment  of $1.2  billion  in Palo  Verde  Units  1, 2 and 3.  The
accelerated  recovery will continue through December 2001, earning a 7.35% fixed
rate of return.  The  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, the balancing  account  became part of the CTC  mechanism.  The
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.  Beginning in 2002, SCE will be required to share equally with
ratepayers the net benefits received from operation of Palo Verde.

In second  quarter  1998,  SCE's  nuclear  investments  were  reclassified  as a
regulatory  asset.  See  discussion  under  "Accounting  for  Generation-Related
Assets" in Note 2 to the Consolidated Financial Statements.

Reclassifications

Certain  prior-period  amounts were reclassified to conform to the September 30,
1998, financial statement presentation.

Regulatory Balancing Accounts

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 a transition cost balancing account.  Also,  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
divestiture  of the gas- and oil-fueled  generation  plants 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. For further details,  see discussion under California
Electric Utility Industry  Restructuring in Note 2 to the Consolidated Financial
Statements. Income tax effects on all balancing account changes are deferred.


                                       8
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In  January   1997,   in   compliance   with  the   restructuring   legislation,
overcollections in the kilowatt-hour sales and energy cost balancing accounts at
December 31, 1996,  were  transferred to an interim  balancing  account and were
credited to the transition cost balancing account beginning in January 1998.

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.  RD&D expenses
were $0.4 million,  $1.2 million and $21 million for the three,  nine and twelve
months ended September 30, 1998,  respectively,  and $7 million, $19 million and
$25 million for the three,  nine and twelve  months  ended  September  30, 1997,
respectively.

Revenue

Operating revenue includes amounts for services rendered but unbilled at the end
of each period. Effective April 1, 1998, operating revenue also includes amounts
for sales to the PX.

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%,  4.6% and 5.1%
for the three,  nine and twelve months ended  September 30, 1998,  respectively,
and 5.2%,  5.2% and 5.1% for the three,  nine and twelve months ended  September
30, 1997, respectively.

During the third quarter of 1997, SCE discontinued accounting for its investment
in   generation   facilities   using   accounting   principles   applicable   to
rate-regulated  enterprises  and  began  accounting  for such  investment  using
accounting  principles  applicable to enterprises in general. The carrying value
of SCE's  generation  investment  was  unaffected by this change.  However,  the
nuclear  investments  were  reclassified as a regulatory asset in second quarter
1998.

Note 2.    Regulatory Matters

California Electric Utility Industry Restructuring

Restructuring  Decision -- The CPUC's  December 1995  decision on  restructuring
California's  electric  utility  industry started the transition to a new market
structure;  competition and customer choice began on April 1, 1998. Key elements
of  the  CPUC's  restructuring  decision  included:   creation  of  the  PX  and
independent   system  operator  (ISO);   availability  of  customer  choice  for
electricity supply and certain billing and metering services;  performance-based
ratemaking  (PBR)  for  those  utility  services  not  subject  to  competition;
voluntary divestiture of at least 50% of utilities' gas-fueled  generation;  and
implementation of the CTC.

Restructuring  Statute -- In September  1996,  the State of  California  enacted
legislation  to provide a transition  to a  competitive  market  structure.  The
Statute substantially adopted the CPUC's December 1995 restructuring decision by
addressing   stranded-cost  recovery  for  utilities  and  providing  a  certain
cost-recovery time period for the transition costs associated with utility-owned
generation-related assets.

                                       9
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 included a
rate freeze for all other  customers,  including large commercial and industrial
customers,  as well as 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 that provides  utilities the opportunity to recover costs made uneconomic by
electric utility  restructuring.  Finally,  the Statute 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.  A voter  initiative,  known as  California
Proposition 9, seeks to overturn major portions of the Statute.  A more detailed
discussion  of  Proposition  9 is in  Note  10  to  the  Consolidated  Financial
Statements.

Rate Reduction Notes -- In December 1997, after receiving approval from both the
CPUC and the California  Infrastructure and Economic Development Bank, a limited
liability  company  created by SCE  issued  approximately  $2.5  billion of rate
reduction  notes.  Residential and small  commercial  customers,  whose 10% rate
reduction  began  January  1, 1998,  are  repaying  the notes over the  expected
10-year term through  non-bypassable  charges based on electricity  consumption.
Proposition 9 seeks to prohibit the collection of these non-bypassable  charges,
or if the charges are found  enforceable by a court,  require SCE to offset such
charges  with an equal  credit  to  customers.  See Note 10 to the  Consolidated
Financial Statements.

Rate-setting  -- In August  1997,  the CPUC  issued a decision  which  adopted a
methodology  for determining  CTC residually  (see "CTC"  discussion  below) and
adopted SCE's revenue  requirement  components for public  benefit  programs and
nuclear decommissioning.  The decision also adjusted SCE's proposed distribution
revenue  requirement (see "PBR" discussion below) by reallocating $76 million of
it annually to other  functions such as generation and  transmission.  Under the
decision,  SCE will be able to recover most of the  reallocated  amount  through
market  revenue,  other  rate-making  mechanisms  or operation  and  maintenance
contracts  with the new  owners of the  divested  generation  plants.  Beginning
January 1, 1998,  SCE's rates were unbundled  into separate  charges for energy,
transmission,  distribution,  the  CTC,  public  benefit  programs  and  nuclear
decommissioning.   The  transmission   component  is  being  collected   through
FERC-approved rates, subject to refund.

PX and ISO -- On March 31, 1998,  both the PX and ISO began  accepting  bids and
schedules for April 1, 1998, when the ISO took over  operational  control of the
transmission  system. The hardware and software systems being utilized by the PX
and ISO in their bidding and scheduling  activities were financed  through loans
of $300 million (backed by utility guarantees)  obtained by restructuring trusts
established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans
through  charges for service to future PX and ISO customers.  The  restructuring
implementation  costs related to the start-up and  development  of the PX, which
are paid by the utilities,  will 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.

Direct  Customer  Access -- Effective  April 1, 1998,  customers are now able to
choose to remain utility  customers with either bundled  electric  service or an
hourly PX pricing  option from SCE (which is  purchasing  its power  through the
PX), or choose  direct  access,  which means the customer can contract  directly
with either  independent power producers or energy service providers (ESPs) such
as   power   brokers,    marketers   and    aggregators.    Additionally,    all
investor-owned-utility  customers  are paying the CTC whether or not they choose
to buy power through SCE. Electric  utilities are continuing to provide the core
distribution  service of delivering  energy  through their  distribution  system
regardless of a



                                       10
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

customer's  choice of electricity  supplier.  The CPUC is continuing to regulate
the prices and service obligations related to distribution services.

Revenue  Cycle  Services --  Effective  April 1, 1998,  customers  have  options
regarding  metering,  billing and related services (referred to as revenue cycle
services) that have been provided by California's  investor-owned utilities. Now
ESPs can provide their customers with one  consolidated  bill for their services
and the utility's  services,  request the utility to provide a consolidated bill
to the  customer or elect to have both the ESP and the utility bill the customer
for their respective charges.  In addition,  customers with maximum demand above
20 kW (primarily  industrial and medium and large  commercial) can choose SCE or
any other supplier to provide their metering  service.  All other customers will
have this option beginning in January 1999. In September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they elect
to obtain  revenue  cycle  services  from someone  other than SCE.  Although the
decision  adopted  SCE's  recommendation  of using the net avoided cost, it also
adopted a methodology  which results in higher credits to customers but requires
ESPs to pay  service  fees to SCE for the costs  that SCE  incurs as a result of
dealing with the ESP.

PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D)
PBR mechanism  for SCE which began on January 1, 1997.  Beginning in April 1998,
the transmission  portion was separated from PBR and subject to ratemaking under
the rules of the FERC. The  distribution-only  PBR will extend through  December
2001. Key elements of PBR include:  T&D rates indexed for inflation based on the
Consumer   Price  Index  less  a   productivity   factor;   elimination  of  the
kilowatt-hour sales adjustment; 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 service  reliability and safety; and a net revenue-sharing
mechanism that  determines how customers and  shareholders  will share gains and
losses from T&D operations.

The CPUC is considering  unbundling SCE's cost of capital based on major utility
function.  In May 1998,  SCE filed an application on this issue. A CPUC decision
is expected in early 1999.

Beginning in 1998,  SCE's  hydroelectric  plants are operating  under a PBR-type
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 (see "CTC" discussion below).

Divestiture  -- In  November  1996,  SCE filed an  application  with the CPUC to
voluntarily  divest,  by auction,  all 12 of its gas- and oil-fueled  generation
plants.  Under this  proposal,  SCE would  continue to operate and  maintain the
divested power plants for at least two years  following  their sale, as mandated
by the  restructuring  legislation  enacted in September 1996. In addition,  SCE
would offer workforce transition programs to those employees who may be impacted
by  divestiture-related  job  reductions.  In September  1997, the CPUC approved
SCE's proposal to auction the 12 plants.

SCE has  sold and  transferred  ownership  of all 12 of its gas- and  oil-fueled
generation plants. The total sales price of the 12 plants was $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.

CTC -- The costs to  transition  to a  competitive  market  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 20, 1995,
decision date. The CTC is being determined  residually by subtracting other rate
components for the PX, T&D, nuclear  decommissioning and public benefit programs
from the frozen rate levels. SCE currently  estimates its transition costs to be
approximately  $10.6  billion  (1998 net present  value) from 1998 through 2030.
This estimate is based on incurred costs,  forecasts of future costs and assumed
market prices.  However,  changes in the assumed market prices could  materially
affect


                                       11
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

these  estimates.  The potential  transition costs are comprised of $6.4 billion
from SCE's qualifying facilities (QF) contracts,  which are the direct result of
prior  legislative  and  regulatory  mandates,   and  $4.2  billion  from  costs
pertaining to certain  generating assets  (successful  completion of the sale of
SCE's gas-fired  generating plants has reduced this estimate of transition costs
for  SCE-owned  generation)  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 (as
discussed in  "Regulatory  Matters"),  and certain  other costs.  This issue was
separated into two phases;  Phase 1 addressed the rate-making issues and Phase 2
the quantification issues.

Major  elements  of the  CPUC's  CTC Phase 1 and  Phase 2  decisions  were:  the
establishment of a transition cost balancing  account and annual transition cost
proceedings;  the setting of a market rate forecast for 1998  transition  costs;
the requirement that  generation-related  regulatory assets be amortized ratably
over a 48-month  period;  the  establishment  of calculation  methodologies  and
procedures for SCE to collect its transition  costs from 1998 through the end of
the rate freeze; and the reduction of SCE's authorized rate of return on certain
assets   eligible  for   transition   cost  recovery   (primarily   fossil-  and
hydroelectric-generation  related  assets)  beginning  July  1997,  five  months
earlier than anticipated. SCE has filed an application for rehearing on the 1997
rate of return issue.

Accounting  for  Generation-Related  Assets -- If the CPUC's  electric  industry
restructuring plan continues as described above, SCE would be allowed to recover
its CTC 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).  During the third  quarter 1997,  SCE  discontinued
application of accounting  principles  for  rate-regulated  enterprises  for its
investment  in  generation  facilities  based on new  accounting  guidance.  The
financial  reporting effect of this discontinuance was to segregate these assets
on the balance  sheet;  the new guidance did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
new guidance did not  specifically  address the application of asset  impairment
standards to these  assets.  SCE has retained  these assets on its balance sheet
because the legislation 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 relating to
the  application  of asset  impairment  standards  to these  assets.  Using this
guidance has 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  $2.5
billion,  after tax,  at  September  30,  1998) as a one-time,  non-cash  charge
against earnings.

If events occur during the restructuring process that result in all or a portion
of the CTC being  improbable of recovery,  SCE could have additional  write-offs
associated with these costs if they are not recovered through another regulatory
mechanism. At this time, SCE cannot predict what other revisions will ultimately
be  made  during  the  restructuring   process  in  subsequent   proceedings  or
implementation 



                                       12
<PAGE>




SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

phases, or the effect,  after the transition period,  that competition will have
on its results of operations or financial position.

Note 3.    Financial Instruments

Cash Equivalents

Cash and equivalents  include tax-exempt  investments ($278 million at September
30, 1998,  $936 million at December 31, 1997,  and $87 million at September  30,
1997),  and time  deposits and other  investments  ($6 million at September  30,
1998,  $26 million at December 31, 1997,  and $9 million at September  30, 1997)
with maturities of three months or less.

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.  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 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
recovered  through the  transition  cost  balancing  account.  As a result,  the
mark-to-market gains or losses have no effect on earnings.

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  purchased from the PX. The options cover various  periods from 1998
through 2001.

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, 1998,  December  31, 1997,  and  September  30, 1997,  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, 1998, SCE had pledged $24 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 obligations.

In June 1998, a new accounting  standard for derivative  instruments and hedging
activities  was issued.  The new  standard,  which will be effective  January 1,
2000,  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 


                                       13
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Fair Value of Financial Instruments

Fair values of financial instruments were:
<TABLE>
<CAPTION>

                                      September 30,                  December 31,              September 30,
In millions                               1998                           1997                      1997
---------------------------------------------------------------------------------------------------------------------
                                    Cost        Fair             Cost          Fair          Cost         Fair
                                    Basis       Value            Basis         Value         Basis        Value
---------------------------------------------------------------------------------------------------------------------

Financial assets:
<S>                               <C>         <C>                <C>          <C>          <C>           <C>   
Decommissioning trusts            $1,489      $2,013             $1,371       $1,831       $1,327        $1,609
Equity investments                     9          88                  9           90            9            85
Gas call options                      42          50                 34           34           --            --

Financial liabilities:
DOE decommissioning and
  decontamination fees                50          44                 50           43           54            45
Interest rate hedges                  --          28                 --           24           --            18
Long-term debt                     5,486       5,756              6,145        6,456        4,105         4,353
Preferred stock subject to
  mandatory redemption               256         276                275          293          275           293
---------------------------------------------------------------------------------------------------------------------
</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 on financial assets were:
<TABLE>
<CAPTION>

                                                               September 30,      December 31,      September 30,
In millions                                                        1998               1997              1997
-------------------------------------------------------------------------------------------------------------------

Decommissioning trusts:
<S>                                                                <C>                <C>               <C> 
  Municipal bonds                                                  $162               $131              $ 79
  Stocks                                                            245                190               118
  U.S. government issues                                            107                 91                55
  Short-term and other                                               10                 48                30
-------------------------------------------------------------------------------------------------------------------
                                                                    524                460               282
Equity investments                                                   79                 81                76
Gas call options                                                      8                 --                --
-------------------------------------------------------------------------------------------------------------------
Total                                                              $611               $541              $358
-------------------------------------------------------------------------------------------------------------------
</TABLE>


There were no  unrealized  holding  losses on  financial  assets for the periods
presented.

Investments

Net unrealized  gains (losses) on equity  investments are recorded as a separate
component  of  shareholder's  equity  under  the  caption  "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.


                                       14
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt

California  law  prohibits  SCE  from  incurring  or  guaranteeing  debt for its
nonutility affiliates.

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
uses 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.

Long-term  debt   maturities  and   sinking-fund   requirements   for  the  five
twelve-month  periods  following  September 30, 1998, are: 1999 -- $593 million;
2000 -- $568 million;  2001 -- $647 million;  2002 -- $247 million;  and 2003 --
$572 million.

In December 1997, SCE Funding LLC, a special  purpose entity (SPE), 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
the SPE 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
tariff levied on residential and small commercial customers. Notwithstanding the
legal sale of the transition  property by SCE to the SPE, the amounts  reflected
as assets on SCE's  balance  sheet  have not been  reduced  by the amount of the
transition property sold to the SPE, and the liabilities of the SPE 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 rate reduction
notes are secured solely by the transition  property and certain other assets of
the SPE, and there is no recourse to SCE or Edison International.

Although  the SPE is  consolidated  with  SCE in the  financial  statements,  as
required  by  generally  accepted  accounting  principles,  the  SPE is  legally
separate  from SCE, the assets of the SPE are not  available to creditors of SCE
or Edison International,  and the transition property is legally not an asset of
SCE or Edison International.

A voter  initiative,  known as  California  Proposition  9 on the November  1998
ballot,  proposes to, among other things, prohibit the collection of any charges
in  connection  with the financing  order for the purpose of making  payments on
rate reduction  notes. If Proposition 9 is voted into law and is not immediately
overturned  or is  not  stayed  pending  judicial  review  of  its  merits,  the
collection of charges necessary to pay the certificates  while the litigation is
pending could be precluded,  which would adversely  affect the  certificates and
the secondary  market for the  certificates,  including the pricing,  liquidity,
dates of maturity, and weighted-average lives of the certificates.  In addition,
if Proposition 9 were to be voted into law and be upheld by the courts, it could
have a further  material  adverse effect on the  certificates and the holders of
the  certificates  could  incur  a loss on  their  investment.  A more  detailed
discussion is in Note 10 to the Consolidated Financial Statements.


                                       15
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-term debt consisted of:
<TABLE>
<CAPTION>
                                                    September 30,              December 31,          September 30,
In millions                                              1998                      1997                  1997
--------------------------------------------------------------------------------------------------------------------

First and refunding mortgage bonds:
<S>                                                     <C>                      <C>                    <C>   
   1999 - 2026 (5.625% to 7.5%)                         $1,550                   $1,825                 $1,825
Rate reduction notes:
   1998 - 2007 (5.98% to 6.42%)                          2,307                    2,463                     --
Pollution-control bonds:
   1999 - 2027 (5.4% to 7.2% and variable)               1,201                    1,202                  1,203
Funds held by trustees                                      (2)                      (2)                    (2)
Debentures and notes:
   1998 - 2006 (5.6% to 8.25%)                             870                    1,195                  1,195
Subordinated debentures:
   2044 (8.375%)                                           100                      100                    100
Commercial paper for nuclear fuel                           80                       92                     99
Long-term debt due within one year                        (593)                    (693)                  (277)
Unamortized debt discount -- net                           (27)                     (37)                   (38)
--------------------------------------------------------------------------------------------------------------------
Total                                                   $5,486                   $6,145                 $4,105
--------------------------------------------------------------------------------------------------------------------
</TABLE>

Short-Term Debt

SCE has  lines of  credit  it can use at  negotiated  or bank  index  rates.  At
September  30,  1998,  these  lines  totaled  $1.3  billion,  with $735  million
available  for  short-term  debt and $515 million  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,
1998, December 31, 1997, and September 30, 1997, was $187 million,  $415 million
and $873 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
commercial  bank lines of credit  expiring  in 2002.  Weighted-average  interest
rates were 5.6%,  6.0% and 5.6% at September  30, 1998,  December 31, 1997,  and
September 30, 1997, respectively.

Note 4.    Equity

The CPUC regulates  SCE's capital  structure,  limiting the dividends it may pay
Edison  International.  At September 30, 1998,  SCE had the capacity to pay $800
million in additional  dividends and continue to maintain its authorized capital
structure.

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, 1998,  are:  1999  through 2001 -- zero;  2002 -- $105
million; and 2003 -- $9 million.


                                       16
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
                                                                        September 30,     December 31,     September 30,
Dollars in millions, except per share amounts                               1998              1997             1997
--------------------------------------------------------------------------------------------------------------------------

                                            September 30, 1998 
                                          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
5.80                                            --            --                --             55             55
--------------------------------------------------------------------------------------------------------------------------
Total                                                                         $129           $184           $184
--------------------------------------------------------------------------------------------------------------------------

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            100            100
--------------------------------------------------------------------------------------------------------------------------
Total                                                                         $256           $275           $275
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

In third  quarter  1998,  10,000  shares of Series  7.23%  preferred  stock were
redeemed.  In second  quarter 1998,  2.2 million shares of Series 5.8% preferred
stock and 183,000 shares of Series 7.23% were redeemed. In the second quarter of
1997, 4 million shares of Series 7.36% preferred stock were redeemed. There were
no preferred stock issuances for the periods presented.

A recently issued accounting standard requires companies to report comprehensive
income  starting in 1998. SCE  implemented  the new  accounting  standard in the
first quarter of 1998. Implementation of the new standard had no effect on SCE's
results of operations or financial position.

Accumulated other comprehensive income balances were:
<TABLE>
<CAPTION>

                                              3 Months Ended             9 Months Ended          12 Months Ended
In millions                                    September 30,              September 30,           September 30,
--------------------------------------------------------------------------------------------------------------------
                                            1998          1997         1998         1997      1998         1997
--------------------------------------------------------------------------------------------------------------------
<S>                                          <C>           <C>          <C>          <C>       <C>          <C>
Beginning balance                            $60           $48          $48          $33       $37          $30
Unrealized gain (loss) on securities         (22)           (6)          (2)          18         4           24
Tax effect                                     1            (5)          (7)         (14)       (2)         (17)
--------------------------------------------------------------------------------------------------------------------

Ending balance                               $39           $37          $39          $37       $39          $37
--------------------------------------------------------------------------------------------------------------------
</TABLE>

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.


                                       17
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net accumulated deferred income tax liability were:
<TABLE>
<CAPTION>

                                                              September 30,      December 31,       September 30,
In millions                                                       1998               1997                1997
--------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>                 <C>                <C>    
Deferred tax assets:
Property-related                                               $   208             $   227            $   239
Unrealized gains or losses                                          --                 273                 --
Investment tax credits                                             153                 192                195
Regulatory balancing accounts                                       84                 180                125
Decommissioning-related                                            801                 114                110
Other                                                              181                 335                604
--------------------------------------------------------------------------------------------------------------------
Total                                                           $1,427              $1,321             $1,273
--------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related                                                $3,046              $3,272             $3,341
Capitalized software costs                                          --                 127                 --
Other                                                              992                 738                698
--------------------------------------------------------------------------------------------------------------------
Total                                                           $4,038              $4,137             $4,039
--------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes -- net                        $2,611              $2,816             $2,766
--------------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits                                    $2,880              $2,939             $2,958
Included in current assets                                         269                 123                192

The current and deferred components of income tax expense were:

                                              3 Months Ended             9 Months Ended          12 Months Ended
In millions                                    September 30,              September 30,           September 30,
--------------------------------------------------------------------------------------------------------------------
                                            1998          1997         1998         1997       1998        1997
--------------------------------------------------------------------------------------------------------------------

Current:
Federal                                     $ 96          $165         $452         $340      $486         $327
State                                         22            40          100           95       105           96
--------------------------------------------------------------------------------------------------------------------
                                             118           205          552          435       591          423
--------------------------------------------------------------------------------------------------------------------
Deferred--federal and state:
Accrued charges                              (10)          (11)         (24)         (24)      (33)         (19)
CTC amortization                              63            --           53           --        53           --
Depreciation                                 (22)          (15)        (106)         (38)     (115)         (43)
Investment and energy tax credits -- net      (6)           (5)         (22)         (15)      (27)         (20)
Pension reserve                               --            (1)          --           (3)       (3)          49
Prior-year state tax                          (7)          (13)          --            2        (2)          12
Regulatory balancing accounts                152            74           36          112        66          131
Unbilled revenue                            (100)          (34)         (98)         (41)      (51)           5
Other                                         (2)          (13)          15          (27)       46          (34)
--------------------------------------------------------------------------------------------------------------------
                                              68           (18)        (146)         (34)      (66)          81
--------------------------------------------------------------------------------------------------------------------
Total income tax expense                    $186          $187         $406         $401      $525         $504
--------------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income                $172          $208         $397         $437      $541         $555
Included in other income                      14           (21)           9          (36)      (16)         (51)
</TABLE>

The composite  federal and state  statutory  income tax rate was 40.551% for the
three,  nine and twelve months ended  September 30, 1998, and 40.551%,  for both
the three and nine months ended  September 30, 1997,  and 40.675% for the twelve
months ended September 30, 1997.


                                       18
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
--------------------------------------------------------------------------------------------------------------------
                                             1998         1997          1998        1997       1998        1997
--------------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>           <C>         <C>        <C>         <C>  
Federal statutory rate                       35.0%        35.0%         35.0%       35.0%      35.0%       35.0%
Capitalized software                          1.0         (0.4)         (0.1)       (0.6)      (0.5)       (0.7)
CTC amortization                             17.7           --           6.6          --        5.0          --
Depreciation and other                       (5.8)         4.5           4.1         5.5        6.0         5.9
Investment and energy tax credits            (1.2)        (1.2)         (1.6)       (1.7)      (1.7)       (1.8)
State tax -- net of federal deduction         5.8          6.7           6.3         7.1        6.3         7.1
--------------------------------------------------------------------------------------------------------------------
Effective tax rate                           52.5%        44.6%         50.3%       45.3%      50.1%       45.5%
--------------------------------------------------------------------------------------------------------------------
</TABLE>

Note 6.    Employee Compensation and Benefit Plans

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.

The  prior  program  participated  in the use of 8.2  million  shares  of parent
company  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 3.1 million
shares  of  Edison  International  common  stock are  currently  outstanding  to
officers and senior managers of SCE.

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  will  carry  over to  subsequent  years  until  plan
termination.  One  percent of the issued and  outstanding  Edison  International
common stock on December 31, 1997, was 3.8 million  shares.  Under the new plan,
options on 1.4 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. Edison International stock options
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.

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.


                                       19
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unvested  options  of any  person  who has  served  in the  past  on the  Edison
International or SCE Management  Committee 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 $1  million,  $8 million and $9 million for the
three,  nine and twelve months ended  September 30, 1998,  respectively,  and $3
million, $18 million and $23 million for the three, nine and twelve months ended
September 30, 1997, respectively.

Stock-based compensation expense under the fair-value method of accounting would
have  resulted in pro forma  earnings  of $163  million,  $377  million and $492
million  for the  three,  nine and  twelve  months  ended  September  30,  1998,
respectively,  and $227  million,  $463  million and $578 million for the three,
nine and twelve months ended September 30, 1997, respectively.

The  weighted-average  fair value of options  granted  during the twelve  months
ended September 30, 1998, and September 30, 1997, was $6.44 per share option and
$7.68 per share option,  respectively.  The  weighted-average  remaining life of
options  outstanding as of September 30, 1998,  December 31, 1997, and September
30, 1997, was 7 years at each date.

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,
                                         --------------------------------------
                                              1998                1997
-------------------------------------------------------------------------------

Expected life                                7 years             7 years
Risk-free interest rate                   4.7% - 5.6%           6.5% - 6.8%
Expected volatility                              17%                 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.

Pension Plan

SCE has a  noncontributory,  defined-benefit  pension plan that covers employees
meeting  minimum  service  requirements.   SCE  recognizes  pension  expense  as
calculated by the actuarial  method used for  ratemaking.  In 1996, SCE recorded
pension gains from a special  voluntary early retirement  program.  In 1998, SCE
adopted a new accounting  standard that revises the disclosure  requirements for
pension plans. Prior periods have been restated.


                                       20
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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                                                   1998                 1997                 1997
--------------------------------------------------------------------------------------------------------------------

Change in benefit obligation
<S>                                                         <C>                   <C>                    <C>   
Benefit obligation at beginning of period                   $2,094                $2,002                 $2,002
Service cost                                                    42                    44                     33
Interest cost                                                  105                   138                    105
Actuarial gain                                                  --                   198                     --
Benefits paid                                                 (103)                 (288)                  (244)
--------------------------------------------------------------------------------------------------------------------

Benefit obligation at end of period                         $2,138                $2,094                 $1,896
--------------------------------------------------------------------------------------------------------------------

Change in plan assets
Fair value of plan assets at beginning of period            $2,298                $2,165                 $2,165
Actual return on plan assets                                    63                   369                    384
Employer contributions                                          43                    52                     43
Benefits paid                                                 (103)                 (288)                  (244)
--------------------------------------------------------------------------------------------------------------------

Fair value of plan assets at end of period                  $2,301                $2,298                 $2,348
--------------------------------------------------------------------------------------------------------------------

Funded status                                              $   163               $   204                $   452
Unrecognized net gain                                         (227)                 (304)                  (569)
Unrecognized net obligation (17-year amortization)              35                    38                     40
Unrecognized prior service cost                                169                   184                    187
--------------------------------------------------------------------------------------------------------------------

Pension asset (liability)                                  $   140               $   122                $   110
--------------------------------------------------------------------------------------------------------------------

Discount rate                                                 7.0%                  7.0%                   7.75%
Rate of compensation increase                                 5.0%                  5.0%                   5.0%
Expected return on plan assets                                8.0%                  8.0%                   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                                 1998          1997         1998         1997      1998         1997
--------------------------------------------------------------------------------------------------------------------
<S>                                        <C>           <C>          <C>          <C>       <C>         <C>  
Service cost                               $  14         $  11        $  42        $  33     $  53       $  38
Interest cost                                 35            35          105          105       139         150
Expected return on plan assets               (45)          (40)        (135)        (120)     (175)       (170)
Net amortization and deferral                  4             4           12           12        13          15
--------------------------------------------------------------------------------------------------------------------
Pension expense under
   accounting standards                        8            10           24           30        30          33
Regulatory adjustment -- deferred              5             3           15            9        22          18
--------------------------------------------------------------------------------------------------------------------
Net pension expense recognized                13            13           39           39        52          51
Settlement gain                               --            --           --           --        --         (35)
--------------------------------------------------------------------------------------------------------------------
Total expense                              $  13         $  13        $  39        $  39     $  52       $  16
--------------------------------------------------------------------------------------------------------------------
</TABLE>

Postretirement Benefits Other Than Pensions

Employees  retiring  at or after  age 55 with at least 10 years of  service  (or
those eligible under a 1996 special  voluntary early  retirement  program),  are
eligible for  postretirement  health and dental care,  life  insurance and other
benefits.  In 1996,  SCE recorded  special  termination  expenses from a special
voluntary  early  retirement  program.  In 1998,  SCE  adopted a new  accounting
standard that revises the disclosure  requirements  for  postretirement  benefit
plans. Prior periods have been restated.


                                       21
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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                                                   1998                 1997                 1997
--------------------------------------------------------------------------------------------------------------------

Change in benefit obligation
<S>                                                           <C>                 <C>                   <C>   
Benefit obligation at beginning of period                     $ 1,533             $1,349                $1,349
Service cost                                                       27                 30                    21
Interest cost                                                      78                 99                    75
Actuarial loss                                                     --                114                    --
Benefits paid                                                     (48)               (59)                  (44)
--------------------------------------------------------------------------------------------------------------------

Benefit obligation at end of period                           $ 1,590             $1,533                $1,401
--------------------------------------------------------------------------------------------------------------------

Change in plan assets
Fair value of plan assets at beginning of period              $   815             $  617                $  617
Actual return on plan assets                                       48                147                    40
Employer contributions                                             81                110                    81
Benefits paid                                                     (48)               (59)                  (44)
--------------------------------------------------------------------------------------------------------------------

Fair value of plan assets at end of period                    $   896             $  815                $  694
--------------------------------------------------------------------------------------------------------------------

Funded status                                                 $  (694)            $ (718)               $ (707)
Unrecognized net loss                                             241                244                   226
Unrecognized transition obligation (20-year
   amortization)                                                  382                403                   410
--------------------------------------------------------------------------------------------------------------------

Recorded asset (liability)                                    $   (71)            $  (71)               $  (71)
--------------------------------------------------------------------------------------------------------------------

Discount rate                                                    7.0%                7.0%                 7.75%
Expected return on plan assets                                   8.0%                8.0%                  8.5%

The components of postretirement benefits other than pensions expense were:

                                              3 Months Ended             9 Months Ended          12 Months Ended
                                               September 30,              September 30,           September 30,
--------------------------------------------------------------------------------------------------------------------
In millions                                 1998          1997         1998         1997      1998         1997
--------------------------------------------------------------------------------------------------------------------

Service cost                               $   9        $    7        $  27         $ 22      $ 36        $  25
Interest cost                                 26            25           78           77       102          108
Expected return on plan assets               (16)          (13)         (48)         (40)      (59)         (55)
Amortization of loss                           1             2            3            5         1            6
Amortization of transition obligation          7             7           21           20        27           27
--------------------------------------------------------------------------------------------------------------------
Net expense                                   27            28           81           84       107          111
Special termination expense                   --            --           --           --        --           12
--------------------------------------------------------------------------------------------------------------------
Total expense                              $  27        $   28        $  81         $ 84      $107        $ 123
--------------------------------------------------------------------------------------------------------------------
</TABLE>

The  assumed  rate of future  increases  in the  per-capita  cost of health care
benefits is 8.5% for 1998,  gradually  decreasing  to 5.25% for 2004 and beyond.
Increasing  the  health  care cost  trend  rate by one  percentage  point  would
increase the  accumulated  obligation  as of September 30, 1998, by $255 million
and annual aggregate  service and interest costs by $28 million.  Decreasing the
health  care  cost  trend  rate  by one  percentage  point  would  decrease  the
accumulated  obligation  as of September  30,  1998,  by $218 million and annual
aggregate service and interest costs by $23 million.



                                       22
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Employee Savings Plan

SCE has a 401(k)  defined  contribution  savings  plan  designed  to  supplement
employees'  retirement  income.  The plan received employer  contributions of $4
million, $12 million and $16 million for the three, nine and twelve months ended
September 30, 1998,  respectively,  and $3 million,  $11 million and $22 million
for the three, nine and twelve months ended September 30, 1997, respectively.

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, 1998, 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                                           $    31        $       6              $ --               60%
  Pacific Intertie                                       243               77                --               50
Generating stations:
  Four Corners Units 4 and 5 (coal)                      460              272                 1               48
  Mohave (coal)                                          313              167                 5               56
  Palo Verde (nuclear)(1)                              1,605              848                12               16
  San Onofre (nuclear)(1)                              4,219            2,590                33               75
---------------------------------------------------------------------------------------------------------------------
Total                                                 $6,871           $3,960               $51
---------------------------------------------------------------------------------------------------------------------
</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 noncancellable leases at September 30, 1998,
were:

Year ended December 31,                                In millions
-------------------------------------------------------------------------------
1998                                                       $  4
1999                                                         13
2000                                                         11
2001                                                          8
2002                                                          4
Thereafter                                                    7
-------------------------------------------------------------------------------
Total                                                       $47
-------------------------------------------------------------------------------

Note 9.    Commitments

Nuclear Decommissioning

Decommissioning is estimated to cost $2.2 billion in current-year dollars, based
on  site-specific  studies  performed  in 1993 for San  Onofre and 1992 for Palo
Verde.  Changes  in the  estimated  costs,  timing  of  decommissioning,  or the
assumptions underlying these estimates could cause material revisions to the


                                       23
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

estimated  total  cost  to  decommission  in  the  near  term.  SCE  planned  to
decommission  its nuclear  generating  facilities at the end of each  facility's
operating  license  by  a  prompt  removal  method  authorized  by  the  Nuclear
Regulatory  Commission.  Decommissioning  is  scheduled to begin in 2013 for San
Onofre Units 2 and 3, and 2027 at Palo Verde. San Onofre Unit 1, which shut down
in 1992,  is currently  being  evaluated for  decommissioning  and may begin the
process as early as 2000, rather than delaying it to 2013 as previously planned.

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. Decommissioning expense was $41
million,  $119  million and $155 million for the three,  nine and twelve  months
ended September 30, 1998,  respectively,  and $43 million, $118 million and $155
million  for the  three,  nine and  twelve  months  ended  September  30,  1997,
respectively.  The accumulated provision for decommissioning was $1.2 billion at
September  30, 1998,  and $1.1 billion at December 31, 1997,  and  September 30,
1997. The estimated costs to  decommission  San Onofre Unit 1 ($280 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 include:
<TABLE>
<CAPTION>

                                            Maturity           September,        December 31,       September 30,
In millions                                   Dates               1998               1997                1997
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------
<S>                                         <C>  <C>           <C>               <C>                   <C>    
Municipal bonds                             2000-2034            $  537           $  459                $  448
Stocks                                         --                   543              392                   390
U.S. government issues                      1999-2028               396              357                   341
Short-term and other                        2003-2030                13              163                   148
-------------------------------------------------------------------------------------------------------------------
Total                                                            $1,489           $1,371                $1,327
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Trust fund earnings (based on specific  identification)  increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $17
million, $44 million and $55 million for the three, nine and twelve months ended
September 30, 1998,  respectively,  and $18 million, $43 million and $57 million
for the three,  nine and twelve months ended  September 30, 1997,  respectively.
Proceeds from sales of securities (which are reinvested) were $342 million, $911
million and $1.1 billion for the three,  nine and twelve months ended  September
30, 1998, respectively,  and $110 million, $371 million and $549 million for the
three, six and twelve months ended September 30, 1997.  Approximately 89% of the
trust fund contributions were tax-deductible.

Other Commitments

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

SCE has power-purchase  contracts with certain QFs (cogenerators and small power
producers) and other utilities.  The QF 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.

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.  The
purchased-power  contract is not  expected to provide more than 5% of current or
estimated  future  operating  capacity.  SCE's  minimum  commitment  under  both
contracts is approximately $193 million through 2017.



                                       24
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Certain commitments for the years 1998 through 2002 are estimated below:
<TABLE>
<CAPTION>

In millions                                                      1998       1999      2000       2001       2002
----------------------------------------------------------------------------------------------------------------------

<S>                                                              <C>        <C>       <C>        <C>        <C> 
Projected construction expenditures                              $846       $790      $674       $680       $655
Fuel supply contracts                                             172        122       141        129        146
Purchased-power capacity payments                                 699        702       703        702        698
Unconditional purchase obligations                                  9          9        10          9         10
----------------------------------------------------------------------------------------------------------------------
</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.

California Voter Initiative

On November 3, 1998, California voters will vote on Proposition 9, an initiative
supported by various consumer groups.

Proposition 9 would overturn major provisions of California's  electric industry
restructuring  legislation.  Proposition  9 purports to: (1) require SCE and the
other  California  investor-owned  utilities  to  provide  at  least a 20%  rate
reduction to their  residential  and small  commercial  customers to be achieved
through  cutting  payments  for nuclear and other fossil  generation  transition
costs;  (2) eliminate  cost recovery for nuclear  generation  plants and related
assets and obligations (other than reasonable  decommissioning costs), except to
the extent such costs are recovered from competitive market sales through the PX
or  contracts  with  the  ISO;  (3)  eliminate  cost  recovery  for  non-nuclear
generation  plants  and  related  assets  and  obligations   (other  than  costs
associated  with  QFs),  except to the  extent  such  costs are  recovered  from
competitive  market sales through the PX or contracts  with the ISO,  unless the
CPUC finds that the  utilities  would be deprived of the  opportunity  to earn a
fair rate of return;  and (4) prohibit the  collection  of any customer  charges
necessary to pay principal, interest and other costs on the rate reduction bonds
(Fixed  Transition  Amounts or FTAs) or, if a court  finds that the CPUC  orders
authorizing  the collection of FTAs are  nevertheless  enforceable,  require the
FTAs to be offset with a concurrent equal credit. Proposition 9's purported rate
reduction  would be in lieu of the 10% rate reduction for  residential and small
commercial customers that went into effect on January 1, 1998.

If Proposition 9 is approved and implemented, and if SCE were unable to conclude
that it is probable that Proposition 9 ultimately  would be found invalid,  then
under  applicable  accounting  principles  SCE  would be  required  to write off
generation-related   regulatory  assets  and  certain  investments  in  electric
generation  plant to the extent SCE were to  conclude  that such  assets were no
longer probable of recovery due to reductions in future revenue. SCE anticipates
that such a one-time  write-off would amount to as much as $3.4 billion pre-tax.
This pre-tax write-off would result in an after-tax write-off of as much as $1.9
billion, representing 50% of SCE's total shareholders' equity of $3.8 billion at
September 30, 1998.

Such an after-tax write-off,  which would exceed SCE's current retained earnings
($820 million as of September 30, 1998),  would severely impair SCE's ability to
pay dividends to its preferred shareholders and Edison  International's  ability
to pay dividends to its common  shareholders.  The potential earnings reductions
described  below also would impair the payment of  dividends.  In  addition,  an
after-tax  write-off  of $1.9 billion  would  reduce the common  equity ratio of
SCE's capital structure from approximately 49% to approximately 30%.

The duration and amount of the rate decrease  contemplated  by  Proposition 9 is
uncertain and, if Proposition 9 is approved,  will be subject to  interpretation
by the courts and regulatory agencies. If all

                                       25
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

provisions of Proposition 9 ultimately  are upheld  against legal  challenge and
interpreted in an adverse manner, the amount of the average earnings  reductions
to SCE could be as much as $210  million per year from 1999  through  2001,  and
gradually decreasing to as much as $10 million in 2007.

The earnings reduction and write-off estimates ultimately will depend on how the
courts  and  regulators  interpret  Proposition  9 and how future  rate  changes
unrelated to Proposition 9 affect SCE's electric revenue.

The financial  impacts described above,  either singly or in combination,  would
likely cause the rating  agencies that rate SCE's debt and preferred  securities
to lower those ratings substantially,  which would immediately reduce the market
value of SCE's  $4.2  billion  in  outstanding  debt and  preferred  securities,
increase  the cost of raising new  capital,  and  possibly  preclude  the use of
certain financial instruments for raising capital.

If the voters  approve  Proposition  9, then legal  challenges by the California
utilities,  including  SCE,  and others  will ensue.  SCE intends to  vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions  pending  court review of the merits of its  challenge.  Although SCE
believes the litigation arguments  challenging the enforceability of Proposition
9 would be compelling,  no assurances can be given whether or when Proposition 9
would be overturned.

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).

SCE's recorded  estimated minimum liability to remediate its 50 identified sites
is $177 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 $247 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  $90  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

                                       26
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

regulatory asset of $145 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
$4 million to $10 million.  Recorded costs for the twelve months ended September
30, 1998, were $5 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 $9.9
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.

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 $25 million per year. Insurance premiums are charged to operating expense.


                                       27
<PAGE>


SOUTHERN CALIFORNIA EDISON COMPANY

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, 1998, were $163 million, $375 million and $491
million, respectively, compared with $226 million, $461 million and $574 million
for the  same  periods  in  1997.  The  earnings  decreases  were  due to  lower
authorized revenue, which resulted from reduced authorized returns on generating
assets and a lower earning asset base resulting from the accelerated recovery of
investments  and  divestiture  of gas- and  oil-fueled  generation  assets.  The
quarterly  decrease  also reflects a higher  percentage of annual  operating and
maintenance  expenses  incurred during third quarter 1998,  compared to the same
period last year.

Operating Revenue

Since April 1, 1998,  SCE is required to sell all of its generated  power to the
power exchange (PX). For more details, see "Competitive  Environment." Excluding
the sales to the PX, operating  revenue  decreased 3%, 6% and 3%,  respectively,
for the three, nine and twelve months ended September 30, 1998,  compared to the
year-earlier  periods.  The decreases  reflect lower average  residential  rates
(mandated by legislation  enacted in September 1996). The quarterly decrease was
partially  offset by a 5% increase in retail sales  volume due to the  unusually
warm weather in third quarter  1998.  Over 99% of operating  revenue  (excluding
sales  to the PX) is 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).

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

Operating Expenses

Fuel expense decreased 85%, 66% and 54%,  respectively,  for the three, nine and
twelve  months  ended  September  30, 1998,  respectively,  compared to the same
periods in 1997. The decreases resulted from the sale of the gas- and oil-fueled
generation  plants.  In  addition,  the  year-to-date  and   twelve-months-ended
decreases  also reflect  significantly  lower gas prices in the first quarter of
1998.

Since April 1, 1998,  SCE is  required to purchase  all of its power from the PX
for  distribution to its retail  customers.  SCE is continuing to purchase power
from certain  nonutility  generators (known as qualifying  facilities) and under
existing inter-utility contracts. This purchased power is sold to the PX. SCE is
required under federal law to purchase power from certain qualifying  facilities
even though energy prices under these contracts are generally  higher than other
sources.  For the twelve months ended  September  30, 1998,  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.  The CPUC has mandated the
prices for these contracts.

Provisions for regulatory  adjustment  clauses  decreased for the quarter,  nine
months and twelve months ended September 30, 1998,  compared to the same periods
in 1997.  The  quarterly  decrease is primarily due to  undercollections  in the
transition  cost balancing  account  resulting from high  qualifying  facilities
energy costs. The year-to-date and twelve-months-ended decreases were mainly due
to  under-collections  related to the  issuance of the rate  reduction  notes in
December 1997. These  undercollections  were partially offset by overcollections
related to the gain on sales of the gas- and oil-fueled generation


                                       28
<PAGE>


plants in second  quarter  1998 and other  transition  costs.  The  year-to-date
decrease  in the  provision  was also offset by  overcollections  related to the
administration of public-purpose funds.

Other operating  expenses  increased for the three, nine and twelve months ended
September  30,  1998,  compared to the same  periods in 1997,  primarily  due to
must-run reliability services, direct access activities,  and PX and independent
system  operator (ISO)  activities.  The  year-to-date  and  twelve-months-ended
increases also reflect storm damage resulting from a harsher winter in 1998.

Maintenance  expense  increased  16% for the quarter  ended  September 30, 1998,
compared to the year-earlier period,  mainly due to additional expenses incurred
at the distribution facilities.

Depreciation,   decommissioning  and  amortization  expense  increased  for  the
quarter, nine months and twelve months ended September 30, 1998, compared to the
same periods in 1997,  primarily due to the further  acceleration  of San Onofre
Nuclear  Generating  Station Units 2 and 3 and the Palo Verde Nuclear Generating
Station units and the  amortization of the loss on plant sales. The year-to-date
and twelve-months-ended  increases also reflect accelerated recovery of the gas-
and oil-fueled  generation  plants. The amortization of the loss on plant sales,
as well as the  accelerated  recoveries  implemented  in  1998  are  part of the
competition  transition  charge (CTC)  mechanism (see further  discussion  under
"California Electric Utility Industry Restructuring").

Income  taxes  decreased  18% for the three  months  ended  September  30, 1998,
compared to the  year-earlier  period,  primarily due to lower  pre-tax  income,
partially offset by additional amortization related to the CTC mechanism.  Also,
this additional amortization related to the CTC mechanism will continue to cause
an increase in the effective tax rate.

Property and other taxes decreased 10% for the twelve months ended September 30,
1998,  compared to the same period in 1997, due to a reclassification of payroll
taxes to operation and maintenance expense, which began in January 1997.

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

Other Income and Deductions

The provision for rate  phase-in plan reflects 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.

Interest and dividend income increased 66%, 91% and 82%,  respectively,  for the
three,  nine and twelve months ended  September  30, 1998,  compared to the same
periods in 1997.  The increases  reflect higher  investment  balances due to the
sale of the gas- and  oil-fueled  generation  plants,  as well as  increases  in
interest earned on higher balancing account undercollections.

Other nonoperating  income increased for the three, nine and twelve months ended
September  30,  1998,  compared  to  the  year-earlier  periods,  mostly  due to
additional accruals in 1997 for regulatory matters.

Interest Expense

Interest on long-term  debt increased  34%, 23% and 15%,  respectively,  for the
three,  nine and twelve months ended  September  30, 1998,  compared to the same
periods in 1997,  primarily due to the issuance of the rate  reduction  notes in
December  1997.  Interest  on the rate  reduction  notes was $37  million,  $113
million and $122 million,  respectively,  for the three,  nine and twelve months
ended September 30, 1998.


                                       29
<PAGE>


Other interest expense decreased 41%, 31% and 15%, respectively,  for the three,
nine and twelve months ended September 30, 1998, compared to the same periods in
1997. The decreases are due to lower overall  short-term  debt balances in 1998,
particularly  short-term  debt used to  finance  fuel  inventories.  These  fuel
inventories  are no longer  needed  because of the  divestiture  of the gas- and
oil-fueled plants.

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 has repurchased 95.5 million shares
($2.2 billion)  between  January 1995 and October 30, 1998,  funded by dividends
from its subsidiaries and the issuance of rate reduction notes.

SCE's cash flow  coverage of  dividends  for the three,  nine and twelve  months
ended September 30, 1998, was 0.4 times, 0.9 times and 0.6 times,  respectively,
compared  to 1.0 times,  2.1 times and 1.7 times for the  year-earlier  periods.
These  decreases  reflect  special  dividends of $350 million and $330  million,
respectively,  SCE paid to Edison  International in the second quarter and third
quarter of 1998.  The  twelve-months-ended  decrease  reflects  the $1.2 billion
special  dividend SCE paid to Edison  International  in December  1997 from rate
reduction note proceeds.

Cash Flows from Operating Activities

Net cash provided by operating activities totaled $181 million, $870 million and
$1.3  billion,  respectively,  for the  three,  nine  and  twelve  months  ended
September 30, 1998,  compared with $299 million,  $1.3 billion and $1.4 billion,
respectively, for the same periods in 1997.

Cash Flows from Financing Activities

At September 30, 1998, SCE had available  lines of credit of $1.3 billion,  with
$735  million  for  general  purpose  short-term  debt and $515  million 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, 1998, SCE could issue approximately $12.0 billion
of additional  first and refunding  mortgage bonds and $4.5 billion of preferred
stock at current interest and dividend rates.

California  law  prohibits  SCE  from  incurring  or  guaranteeing  debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure,
limiting the dividends it may pay Edison  International.  At September 30, 1998,
SCE had the capacity to pay $800 million in additional dividends and continue to
maintain its authorized capital structure.

In December 1997, SCE Funding LLC, a special  purpose entity (SPE), 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
the SPE 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
tariff levied on residential and small commercial customers. Notwithstanding the
legal sale of the transition  property by SCE to the SPE, the amounts  reflected
as assets on SCE's  balance  sheet  have not been  reduced  by the amount of the
transition property sold to the SPE, and the liabilities of the SPE for the


                                       30
<PAGE>


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 rate reduction notes have maturities  ranging from one to 10 years, and bear
interest at rates  ranging  from 5.98% to 6.42%.  The rate  reduction  notes are
secured solely by the  transition  property and certain other assets of the SPE,
and there is no recourse to SCE or Edison International.

Although  the SPE is  consolidated  with  SCE in the  financial  statements,  as
required  by  generally  accepted  accounting  principles,  the  SPE is  legally
separate  from SCE, the assets of the SPE are not  available to creditors of SCE
or Edison International,  and the transition property is legally not an asset of
SCE or Edison International.

A voter  initiative,  known as  California  Proposition  9 on the November  1998
ballot,  proposes to, among other things, prohibit the collection of any charges
in connection  with a financing order for the purpose of making payments on rate
reduction  notes.  If  Proposition  9 is voted  into law and is not  immediately
overturned  or is  not  stayed  pending  judicial  review  of  its  merits,  the
collection of charges necessary to pay the certificates  while the litigation is
pending could be precluded,  which would adversely  affect the  certificates and
the secondary market for the certificates,  including pricing,  liquidity, dates
of maturity,  and weighted-average  lives of the certificates.  In addition,  if
Proposition  9 is voted  into law and  upheld  by the  courts,  it could  have a
further  material  adverse  effect on the  certificates  and the  holders of the
certificates could incur a loss on their investment.  A more detailed discussion
is in "California Voter Initiative."

Cash Flows from Investing Activities

Cash flows from  investing  activities are affected by additions to property and
plant,  proceeds  from  the  sale  of  plant  (see  discussion  in  "Competitive
Environment  --  Divestiture")  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 through charges to depreciation
expense.  SCE estimates that it will spend  approximately  $12.7 billion between
2013-2070 to  decommission  its nuclear  facilities.  This  estimate is based on
SCE's  current-dollar  decommissioning  costs ($2.2 billion),  escalated using a
6.65%  annual  rate.  These costs are  expected  to be funded  from  independent
decommissioning  trusts,  which receive SCE contributions of approximately  $100
million per year.  Any plan to  decommission  San Onofre Unit 1 prior to 2013 is
not expected to affect SCE's annual contributions to the decommissioning trusts.

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  statute,  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. Market prices in the PX and ISO to date have generally been
reasonable,  though  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 of $250/MW 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 of $250/MWh on its
market for  imbalance  energy while a software  problem  affecting the efficient
operation of that market  persists.  The caps in these markets mitigate the risk
of costly  price  spikes that would  reduce the revenue  available to SCE to pay
transition costs. During the upcoming year, the ISO will be considering removing
these price caps,  which could  increase the risk of high market  prices.  SCE's
exposure  to high  electricity  prices  is also  partially  mitigated  by hedges
against high natural

                                       31
<PAGE>


gas  prices,  since  increases  in natural gas prices tend to raise the price of
electricity purchased from the PX.

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 $25 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in a $17 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: 1998 --
$846 million;  1999 -- $790 million; 2000 -- $674 million; 2001 -- $680 million;
and 2002 -- $655 million.

Long-term  debt   maturities  and  sinking  fund   requirements   for  the  five
twelve-month  periods  following  September 30, 1998, are: 1999 -- $593 million;
2000 -- $568 million;  2001 -- $647 million;  2002 -- $247 million;  and 2003 --
$572 million.

Preferred  stock  redemption  requirements  for the  five  twelve-month  periods
following  September  30, 1998,  are:  1999  through 2001 -- zero;  2002 -- $105
million; and 2003 -- $9 million.

Regulatory Matters

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

In 1998,  revenue is determined by various  mechanisms  depending on the utility
operation.  Revenue related to distribution  operations is determined  through a
performance-based  rate-making  mechanism  (PBR) (see discussion in "Competitive
Environment -- PBR") and the distribution  assets have the opportunity to earn a
CPUC-authorized  9.49%  return.  Until  the ISO  began  operation,  transmission
revenue was determined by the same mechanism as distribution  operations.  After
March 31, 1998, transmission revenue is determined through FERC-authorized rates
and transmission assets earn a 9.43% return.  These rates are subject to refund.
See discussion in "Competitive Environment -- Rate-setting."

Revenue  from  generation-related  operations  is  determined  through  the  CTC
mechanism,  nuclear rate-making  agreements and the competitive market.  Revenue
related to fossil and hydroelectric  generation operations is recovered from two
sources. The portion that is made uneconomic by electric industry  restructuring
is  recovered  through  the CTC  mechanism.  The  portion  that is  economic  is
recovered  through  the market.  In 1998,  fossil and  hydroelectric  generation
assets  earn a 7.22%  return.  A more  detailed  discussion  is in  "Competitive
Environment -- CTC."

The CPUC has authorized revised  rate-making plans for SCE's nuclear facilities,
which call for the accelerated  recovery of its nuclear  investments 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.


                                       32
<PAGE>


The changes in revenue from the regulatory mechanisms discussed above, excluding
the effects of other rate actions, are expected to have a minimal impact on 1998
earnings.  However,  the issuance of the rate reduction  notes in December 1997,
which enabled the repurchase of debt and equity,  will have a negative impact on
1998 earnings of approximately $97 million.

Prior to the restructuring of the electric utility  industry,  SCE recovered its
non-nuclear  capital  additions  to utility  plant  through  depreciation  rates
authorized  in the general rate case.  As part of the CTC Phase 2 decision,  the
CPUC  authorized  recovery of the  December 31,  1995,  balances of  non-nuclear
generating  facilities  through  the CTC  mechanism.  The CPUC  stated that rate
recovery for capital additions to the non-nuclear  generating  facilities should
be sought through a separate  filing.  In October 1997, SCE filed an application
with the CPUC requesting rate recovery of $61 million of 1996 capital  additions
to its non-nuclear generating facilities.  Hearings were held in early 1998. The
CPUC's Office of Ratepayer  Advocates and The Utility Reform Network recommended
a combined  total  disallowance  of $37 million.  On September  21, 1998, a CPUC
administrative  law judge  proposed  a $4  million  disallowance.  A final  CPUC
decision is expected in fourth  quarter 1998. In fourth  quarter 1998, SCE plans
to file an  application  for rate  recovery of capital  additions  to these same
generating facilities for the period January 1, 1997, through March 31, 1998, or
the date of divestiture for divested facilities.

Competitive 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.
The  generation  sector  has  experienced   competition  from  nonutility  power
producers  and  regulators  are  restructuring   California's  electric  utility
industry.

California Electric Utility Industry Restructuring

Restructuring  Decision -- The CPUC's  December 1995  decision on  restructuring
California's  electric  utility  industry started the transition to a new market
structure;  competition and customer choice began on April 1, 1998. Key elements
of the  CPUC's  restructuring  decision  included:  creation  of the PX and ISO;
availability of customer  choice for electricity  supply and certain billing and
metering  services;  PBR for those utility  services not subject to competition;
voluntary divestiture of at least 50% of utilities' gas-fueled  generation;  and
implementation of the CTC.

Restructuring  Statute -- In September  1996,  the State of  California  enacted
legislation  to provide a transition  to a  competitive  market  structure.  The
Statute substantially adopted the CPUC's December 1995 restructuring decision by
addressing   stranded-cost  recovery  for  utilities  and  providing  a  certain
cost-recovery time period for the transition costs associated with utility-owned
generation-related  assets. 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 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  included a rate  freeze for all other  customers,
including large commercial and industrial  customers,  as well as 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 that  provides  utilities  the
opportunity to recover costs made uneconomic by electric utility  restructuring.
Finally,  the Statute  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. A
voter  initiative,  known as California  Proposition  9, seeks to overturn major
portions of the Statute.  A more  detailed  discussion  of  Proposition  9 is in
"California Voter Initiative."

Rate Reduction Notes -- In December 1997, after receiving approval from both the
CPUC and the California  Infrastructure and Economic Development Bank, a limited
liability  company  created by SCE  issued  approximately  $2.5  billion of rate
reduction  notes.  Residential and small  commercial  customers,  whose 10% rate
reduction  began  January  1, 1998,  are  repaying  the notes over the  expected
10-year term through  non-bypassable  charges based on electricity  consumption.
Proposition 9 seeks to prohibit

                                       33
<PAGE>


the  collection  of these  non-bypassable  charges,  or if the charges are found
enforceable by a court,  require SCE to offset such charges with an equal credit
to customers. See discussion in "Cash Flows from Financing Activities."

Rate-setting  -- In August  1997,  the CPUC  issued a decision  which  adopted a
methodology  for determining  CTC residually  (see "CTC"  discussion  below) and
adopted SCE's revenue  requirement  components for public  benefit  programs and
nuclear decommissioning.  The decision also adjusted SCE's proposed distribution
revenue  requirement (see "PBR" discussion below) by reallocating $76 million of
it annually to other  functions such as generation and  transmission.  Under the
decision,  SCE will be able to recover most of the  reallocated  amount  through
market  revenue,  other  rate-making  mechanisms  or operation  and  maintenance
contracts  with the new  owners of the  divested  generation  plants.  Beginning
January 1, 1998,  SCE's rates were unbundled  into separate  charges for energy,
transmission,  distribution,  the  CTC,  public  benefit  programs  and  nuclear
decommissioning.   The  transmission   component  is  being  collected   through
FERC-approved rates, subject to refund.

PX and ISO -- On March 31, 1998,  both the PX and ISO began  accepting  bids and
schedules for April 1, 1998, when the ISO took over  operational  control of the
transmission  system. The hardware and software systems being utilized by the PX
and ISO in their bidding and scheduling  activities were financed  through loans
of $300 million (backed by utility guarantees)  obtained by restructuring trusts
established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans
through  charges for service to future PX and ISO customers.  The  restructuring
implementation  costs related to the start-up and  development  of the PX, which
are paid by the utilities,  will 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.

Direct  Customer  Access -- Effective  April 1, 1998,  customers are now able to
choose to remain utility  customers with either bundled  electric  service or an
hourly PX pricing  option from SCE (which is  purchasing  its power  through the
PX), or choose  direct  access,  which means the customer can contract  directly
with either  independent power producers or energy service providers (ESPs) such
as   power   brokers,    marketers   and    aggregators.    Additionally,    all
investor-owned-utility  customers  are paying the CTC whether or not they choose
to buy power through SCE. Electric  utilities are continuing to provide the core
distribution  service of delivering  energy  through their  distribution  system
regardless  of  a  customer's  choice  of  electricity  supplier.  The  CPUC  is
continuing   to  regulate  the  prices  and  service   obligations   related  to
distribution services. As of October 1, 1998,  approximately 42,000 of SCE's 4.3
million customers have requested the direct access option.

Revenue  Cycle  Services --  Effective  April 1, 1998,  customers  have  options
regarding  metering,  billing and related services (referred to as revenue cycle
services) that have been provided by California's  investor-owned utilities. Now
ESPs can provide their customers with one  consolidated  bill for their services
and the utility's  services,  request the utility to provide a consolidated bill
to the  customer or elect to have both the ESP and the utility bill the customer
for their respective charges.  In addition,  customers with maximum demand above
20 kW (primarily  industrial and medium and large  commercial) can choose SCE or
any other supplier to provide their metering  service.  All other customers will
have this option beginning in January 1999. In September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they elect
to obtain  revenue  cycle  services  from someone  other than SCE.  Although the
decision  adopted  SCE's  recommendation  of using the net avoided cost, it also
adopted a methodology  which results in higher credits to customers but requires
ESPs to pay  service  fees to SCE for the costs  that SCE  incurs as a result of
dealing  with the ESP. SCE may  experience a reduction in revenue  security as a
result of this unbundling.

PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D)
PBR mechanism  for SCE which began on January 1, 1997.  Beginning in April 1998,
the transmission  portion was separated from PBR and subject to ratemaking under
the rules of the FERC. The  distribution-only  PBR will extend through  December
2001. Key elements of PBR include:  T&D rates indexed for inflation based on the
Consumer   Price  Index  less  a   productivity   factor;   elimination  of  the
kilowatt-hour sales adjustment; 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 service reliability and safety; and a net


                                       34
<PAGE>


revenue-sharing  mechanism that determines how customers and  shareholders  will
share gains and losses from T&D operations.

The CPUC is considering  unbundling SCE's cost of capital based on major utility
function.  In May 1998,  SCE filed an application on this issue. A CPUC decision
is expected in early 1999.

Beginning in 1998,  SCE's  hydroelectric  plants are operating  under a PBR-type
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 (see "CTC" discussion below).

Divestiture  -- In  November  1996,  SCE filed an  application  with the CPUC to
voluntarily  divest,  by auction,  all 12 of its gas- and oil-fueled  generation
plants.  Under this  proposal,  SCE would  continue to operate and  maintain the
divested power plants for at least two years  following  their sale, as mandated
by the  restructuring  legislation  enacted in September 1996. In addition,  SCE
would offer workforce transition programs to those employees who may be impacted
by  divestiture-related  job  reductions.  In September  1997, the CPUC approved
SCE's proposal to auction the 12 plants.

SCE has  sold and  transferred  ownership  of all 12 of its gas- and  oil-fueled
generation plants. The total sales price of the 12 plants was $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.

CTC -- The costs to  transition  to a  competitive  market  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 20, 1995,
decision date. The CTC is being determined  residually by subtracting other rate
components for the PX, T&D, nuclear  decommissioning and public benefit programs
from the frozen rate levels. SCE currently  estimates its transition costs to be
approximately  $10.6  billion  (1998 net present  value) from 1998 through 2030.
This estimate is based on incurred costs,  forecasts of future costs and assumed
market prices.  However,  changes in the assumed market prices could  materially
affect these  estimates.  The potential  transition  costs are comprised of $6.4
billion from SCE's qualifying facilities contracts,  which are the direct result
of prior  legislative  and  regulatory  mandates,  and $4.2  billion  from costs
pertaining to certain  generating assets  (successful  completion of the sale of
SCE's  oil- and  gas-fueled  generation  plants has  reduced  this  estimate  of
transition costs for SCE-owned generation) 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 (as  discussed in  "Regulatory  Matters"),  and certain other costs.
This issue was  separated  into two phases;  Phase 1 addressed  the  rate-making
issues and Phase 2 the quantification issues.

Major  elements  of the  CPUC's  CTC Phase 1 and  Phase 2  decisions  were:  the
establishment of a transition cost balancing  account and annual transition cost
proceedings;  the setting of a market rate forecast for 1998  transition  costs;
the requirement that  generation-related  regulatory assets be amortized ratably
over a 48-month  period;  the  establishment  of calculation  methodologies  and
procedures for SCE to collect its transition  costs from 1998 through the end of
the rate freeze; and the reduction of SCE's authorized rate of return on certain
assets   eligible  for   transition   cost  recovery   (primarily   fossil-  and
hydroelectric-generation  related  assets)  beginning  July  1997,  five  months
earlier than anticipated. SCE has filed an application for rehearing on the 1997
rate of return issue.

Accounting  for  Generation-Related  Assets -- If the CPUC's  electric  industry
restructuring plan continues as described above, SCE would be allowed to recover
its CTC 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).  During the third quarter of 1997, SCE  discontinued
application of accounting  principles  for  rate-regulated  enterprises  for its
investment  in  generation  facilities  based on new  accounting  guidance.  The
financial reporting effect of this discontinuance was to segregate these assets


                                       35
<PAGE>


on the balance  sheet;  the new guidance did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
new guidance did not  specifically  address the application of asset  impairment
standards to these  assets.  SCE has retained  these assets on its balance sheet
because the legislation 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 relating to
the  application  of asset  impairment  standards  to these  assets.  Using this
guidance has 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  $2.5
billion,  after tax,  at  September  30,  1998) as a one-time,  non-cash  charge
against earnings.

If events occur during the restructuring process that result in all or a portion
of the CTC being  improbable of recovery,  SCE could have additional  write-offs
associated with these costs if they are not recovered through another regulatory
mechanism. At this time, SCE cannot predict what other revisions will ultimately
be  made  during  the  restructuring   process  in  subsequent   proceedings  or
implementation  phases,  or  the  effect,  after  the  transition  period,  that
competition will have on its results of operations or financial position.

California Voter Initiative

On November 3, 1998, California voters will vote on Proposition 9, an initiative
supported by various consumer groups.

Proposition 9 would overturn major provisions of California's  electric industry
restructuring  legislation.  Proposition  9 purports to: (1) require SCE and the
other  California  investor-owned  utilities  to  provide  at  least a 20%  rate
reduction to their  residential  and small  commercial  customers to be achieved
through  cutting  payments  for nuclear and other fossil  generation  transition
costs;  (2) eliminate  cost recovery for nuclear  generation  plants and related
assets and obligations (other than reasonable  decommissioning costs), except to
the extent such costs are recovered from competitive market sales through the PX
or  contracts  with  the  ISO;  (3)  eliminate  cost  recovery  for  non-nuclear
generation  plants  and  related  assets  and  obligations   (other  than  costs
associated  with  QFs),  except to the  extent  such  costs are  recovered  from
competitive  market sales through the PX or contracts  with the ISO,  unless the
CPUC finds that the  utilities  would be deprived of the  opportunity  to earn a
fair rate of return;  and (4) prohibit the  collection  of any customer  charges
necessary to pay principal, interest and other costs on the rate reduction bonds
(Fixed  Transition  Amounts or FTAs) or, if a court  finds that the CPUC  orders
authorizing  the collection of FTAs are  nevertheless  enforceable,  require the
FTAs to be offset with a concurrent equal credit. Proposition 9's purported rate
reduction  would be in lieu of the 10% rate reduction for  residential and small
commercial customers that went into effect on January 1, 1998.

If Proposition 9 is approved and implemented, and if SCE were unable to conclude
that it is probable that Proposition 9 ultimately  would be found invalid,  then
under  applicable  accounting  principles  SCE  would be  required  to write off
generation-related   regulatory  assets  and  certain  investments  in  electric
generation  plant to the extent SCE were to  conclude  that such  assets were no
longer probable of recovery due to reductions in future revenue. SCE anticipates
that such a one-time  write-off would amount to as much as $3.4 billion pre-tax.
This pre-tax write-off would result in an after-tax write-off of as much as $1.9
billion, representing 50% of SCE's total shareholders' equity of $3.8 billion at
September 30, 1998.



                                       36
<PAGE>


Such an after-tax write-off,  which would exceed SCE's current retained earnings
($820 million as of September 30, 1998),  would severely impair SCE's ability to
pay dividends to its preferred shareholders and Edison  International's  ability
to pay dividends to its common  shareholders.  The potential earnings reductions
described  below also would impair the payment of  dividends.  In  addition,  an
after-tax  write-off  of $1.9 billion  would  reduce the common  equity ratio of
SCE's capital structure from approximately 49% to approximately 30%.

The duration and amount of the rate decrease  contemplated  by  Proposition 9 is
uncertain and, if Proposition 9 is approved,  will be subject to  interpretation
by the courts and  regulatory  agencies.  If all  provisions  of  Proposition  9
ultimately  are upheld  against legal  challenge and  interpreted  in an adverse
manner, the amount of the average earnings reductions to SCE could be as much as
$210 million per year from 1999 through  2001,  and  gradually  decreasing to as
much as $10 million in 2007.

The earnings reduction and write-off estimates ultimately will depend on how the
courts  and  regulators  interpret  Proposition  9 and how future  rate  changes
unrelated to Proposition 9 affect SCE's electric revenue.

The financial  impacts described above,  either singly or in combination,  would
likely cause the rating  agencies that rate SCE's debt and preferred  securities
to lower those ratings substantially,  which would immediately reduce the market
value of SCE's  $4.2  billion  in  outstanding  debt and  preferred  securities,
increase  the cost of raising new  capital,  and  possibly  preclude  the use of
certain financial instruments for raising capital.

If the voters  approve  Proposition  9, then legal  challenges by the California
utilities,  including  SCE,  and others  will ensue.  SCE intends to  vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions  pending  court review of the merits of its  challenge.  Although SCE
believes the litigation arguments  challenging the enforceability of Proposition
9 would be compelling,  no assurances can be given whether or when Proposition 9
would be overturned.

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 50 identified sites
is $177  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 $247
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  $90  million  of its  recorded  liability,  through  an  incentive
mechanism.  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 $145 million for its  estimated
minimum  environmental-cleanup  costs expected to be recovered  through customer
rates.


                                       37
<PAGE>


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
$4 million to $10  million.  Recorded  costs for the  twelve-month  period ended
September 30, 1998, were $5 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 is
in progress to determine the specific impact of air  contaminant  emissions from
the Mohave Coal Generating  Station on visibility in Grand Canyon National Park.
The potential  effect of these studies on sulfur dioxide  emissions  regulations
for Mohave is unknown.

SCE's  projected  environmental  capital  expenditures  are $935 million for the
1998-2002  period,  mainly for aesthetics  treatment,  including  undergrounding
certain transmission and distribution lines.

The  possibility  that exposure to electric and magnetic  fields (EMF) emanating
from power lines,  household appliances and other electric sources may result in
adverse health effects has been the subject of scientific  research.  After many
years of research, scientists have not found that exposure to EMF causes disease
in humans. Research on this topic is continuing.  However, the CPUC has issued a
decision which  provides for a  rate-recoverable  research and public  education
program  conducted  by  California  electric  utilities,  and  authorizes  these
utilities  to take  no-cost  or  low-cost  steps to reduce  EMF in new  electric
facilities. SCE is unable to predict when or if the scientific community will be
able to reach a consensus on any health  effects of EMF, or the effect that such
a consensus, if reached, could have on future electric operations.

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, which was completed in Spring 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. Monitoring of this degradation will occur at the next scheduled
refueling outage in January 1999. An additional  mid-cycle inspection outage may
be required early in 2000. With the results from the February 1998 outage, 7% of
the tubes have now been removed from service. In September 1998, San Onofre Unit
2 experienced a small amount of leakage from a steam  generator  tube plug which
required an 11-day outage to repair.

During Unit 3's refueling outage, which was completed in July 1997,  inspections
of structural  supports for steam generator tubes identified several areas where
the  thickness of the supports had been reduced,  apparently  by erosion  during
normal plant  operation.  A follow-up  mid-cycle  inspection  indicated that the
erosion  had been  stabilized.  Additional  monitoring  inspections  are planned
during the next  scheduled  refueling  outage in 1999.  To date,  5% of Unit 3's
tubes have been removed from service. During


                                       38
<PAGE>


Unit 2's  February  1998  mid-cycle  outage,  similar  tube  supports  showed no
significant levels of such erosion.

New Accounting Rules

A recently  issued  accounting  rule  requires  that costs  related to  start-up
activities  be expensed as  incurred,  effective  January 1, 1999.  SCE does not
expect this new accounting  rule to materially  affect its results of operations
or financial position.

In June 1998, a new accounting  standard for derivative  instruments and hedging
activities  was issued.  The new  standard,  which will be effective  January 1,
2000,  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 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.
SCE  divides  its Year 2000  activities  into  five  phases:  inventory,  impact
assessment,  remediation,  testing and  implementation.  SCE's plan for the Year
2000  readiness of critical  systems is to be 75% complete by year-end 1998, and
100% complete by July 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 revenue  stream,
regulatory compliance, or the health and safety of personnel.

The  scope of this  program  includes  three  categories:  mainframe  computing,
distributed  computing and physical assets (also known as embedded  processors).
For mainframe  financial  systems,  Year 2000  remediation  was completed in the
fourth  quarter of 1997.  Remediation  for the  material  management  system was
completed in the second  quarter of 1998. The customer  information  and billing
system is  scheduled  to be replaced by the first  quarter of 1999 with a system
designed to be Year 2000-ready.  Distributed computing assets include operations
and business information  systems.  The critical operations  information systems
include outage  management,  power  management,  and plant monitoring and access
retrieval  systems.  Business  information  systems  include a data  acquisition
system for billing, the computer call center support system,  credit support and
maintenance  management.  The physical asset portfolio  includes  systems in the
generation, transmission, distribution, telecommunications and facilities areas.
SCE has  completed  the inventory  and impact  assessment  phases.  Remediation,
testing and  implementation  activities  are in  progress  for each of the three
categories.  SCE is on schedule  to have its  mainframe  computing,  distributed
computing and physical  assets Year  2000-ready  within the timeframe  discussed
above.

The other  essential  component  of the SCE Year 2000  readiness  program  is to
identify and assess vendor products and business partners (external parties) for
Year 2000 readiness,  as these external parties may have the potential to impact
SCE's Year 2000  readiness.  SCE has a process in place to identify  and contact
vendors  and  business  partners to  determine  their Year 2000  status,  and is
evaluating the responses. SCE's general policy requires that all newly purchased
products be Year  2000-ready  or  otherwise  designed to allow SCE to  determine
whether such products  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  also  intends  to  exchange  Year  2000  readiness
information (including, but not limited to,



                                       39
<PAGE>


test results and related  data) with certain  external  parties as part of SCE's
internal Year 2000 readiness efforts.

The current estimate of the costs to complete these modifications, including the
cost of new  hardware  and software  application  modification,  is $80 million,
about  half of which is  expected  to be  capital  costs.  SCE's Year 2000 costs
expended through September 30, 1998, were $20 million.  SCE expects current rate
levels for providing  electric  service to be sufficient to provide  funding for
these modifications.

Although  SCE is  confident  that  its  critical  systems  will  be  fully  Year
2000-ready prior to year-end 1999, SCE believes that prudent business  practices
call for the  development of contingency  plans.  Such  contingency  plans shall
include developing  strategies for dealing with the most reasonably likely worst
case scenario  concerning Year 2000-related  processing failures or malfunctions
due to SCE's internal systems or from external  parties.  As noted above, SCE is
currently in the remediation and testing phases for many of its internal systems
and is assessing  risks posed by external  parties.  SCE is working with certain
industry groups,  including the North American Electric  Reliability Council and
the Electric Power Research Institute,  in an effort to help define a reasonably
likely worst case scenario and in the  development of contingency  plans.  SCE's
contingency plans are expected to be completed by March 1999;  therefore,  these
risk factors are not yet fully  known,  and SCE's  reasonably  likely worst case
scenario  also is unknown at this time.  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,  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.

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,  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;  changes in market interest rates;  new or
increased  environmental  liabilities;  the effects of the Year 2000 Issue;  the
passage and  implementation  of California  Proposition 9; and other  unforeseen
events.


                                       40
<PAGE>


PART II       OTHER INFORMATION

Item 1.       Legal Proceedings

                           Wind Generators' Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998,  and June 30, 1998,  between
January 1994 and October 1994, SCE was named as a defendant in a series of eight
lawsuits brought by independent power producers of wind generation. Seven of the
lawsuits were filed in Los Angeles  County  Superior  Court and one was filed in
Kern County Superior  Court.  The lawsuits  alleged SCE incorrectly  interpreted
contracts  with the  plaintiffs  by limiting  fixed energy  payments to a single
10-year  period  rather  than  beginning a new  10-year  period of fixed  energy
payments for each stage of development.  In its responses to the complaints, SCE
denied the  plaintiffs'  allegations.  In each of the lawsuits,  the  plaintiffs
sought declaratory relief regarding the proper  interpretation of the contracts.
Plaintiffs  alleged a combined total of  approximately  $189 million in damages,
which included  consequential  damages  claimed in seven of the eight  lawsuits.
Following the March 1 ruling,  a ninth  lawsuit was filed in Los Angeles  County
raising  claims  similar to those alleged in the first eight.  SCE  subsequently
responded  to  the  complaint  in  the  new  lawsuit  by  denying  its  material
allegations.

After  receiving a favorable  decision in the liability  phase of the lead case,
SCE  agreed to settle  with the  plaintiffs  in seven of the  lawsuits  on terms
whereby  SCE waived  its rights to recover  costs  against  such  plaintiffs  in
exchange  for their  agreement  that there is only one fixed price  period under
each of their power  purchase  contracts  with SCE and a mutual  dismissal  with
prejudice  of claims.  SCE also entered  into a  settlement  agreement  with the
plaintiff in another of the lawsuits  which resolved the issue of multiple fixed
price  periods on the same terms and which also  resolved a related issue unique
to that plaintiff in exchange for a nominal  payment by SCE. This settlement was
subject to bankruptcy  court  approval in bankruptcy  proceedings  involving the
plaintiff. On April 24, 1998, the bankruptcy court issued an order approving the
settlement.  Although  the  court  has  not  yet  set a date  for  trial  of the
outstanding  issues in the lead case related to SCE's cross-claim for damages, a
trial setting conference has been set for December 3, 1998.

                        Geothermal Generators' Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the quarters  ended March 31, 1998,  and June 30, 1998, 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.

The Coso parties have also asserted  various  claims against SCE, as well as The
Mission   Group  and  Mission   Power   Engineering   (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.  Following a hearing on November 20,  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.

As a result of motion practice by SCE and the Mission parties,  the Coso parties
filed a second amended cross-complaint on December 29, 1997, and a third amended
cross-complaint on August 21, 1998. 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

                                       41
<PAGE>


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 equitable  indemnity.  The third
amended  cross-complaint  seeks restitution,  compensatory  damages in excess of
$115,000,000,  punitive  damages  in  an  amount  not  less  than  $400,000,000,
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.  At this time,
the Coso parties have not filed a response to SCE's cross-complaint.

SCE has also filed a motion for summary  adjudication with respect to the fourth
cause of action of the third  amended  cross-complaint  for  inducing  breach of
employment  agreements.  The hearing on the motion is  currently  scheduled  for
November 4, 1998.

The  Mission  parties and Edison  International  demurred to and moved to strike
portions of the third amended  cross-complaint.  These matters were heard by the
court on October  22,  1998.  On October  27,  1998,  the court  issued an order
continuing the hearing on Edison International's  demurrer to December 17, 1998,
and stayed discovery with respect to Edison  International  until that time. The
Mission parties' demurrer and motion to strike are still under  submission.  The
court's further disposition of these matters may result in the filing of further
amended pleadings with respect to Edison International and/or SCE.

On  October  19,  1998,  the  Coso  parties  purported  to file a first  amended
cross-complaint  against Edison International only. In the amended pleading, the
Coso parties assert,  among other things, that SCE and Edison  International are
alter egos; that SCE engaged in anticompetitive  conduct;  and that SCE violated
rules of the  California  Public  Utilities  Commission  governing  transactions
between SCE and its affiliates. These allegations are similar to those set forth
in the second amended  complaint  filed by three of the Coso parties,  described
below.  In its reply  brief in support  of its  demurrer  and at the  October 22
hearing, described in the preceding paragraph,  Edison International objected to
the filing of the first amended cross-complaint on the grounds that it was filed
without leave of court and has no legal effect.  On October 27, 1998,  the court
issued an order  striking the  purported  first amended  cross-complaint  in its
entirety.

On August  21,  1998,  the  court  granted  SCE's  motion to set aside a default
entered with respect to the first amended  complaint  filed by three of the Coso
parties in the separately filed (now  consolidated)  action. SCE filed an answer
to the first  amended  complaint on September  21, 1998,  generally  denying its
allegations  and asserting  affirmative  defenses.  Since then, the parties have
agreed to  stipulate  to the  filing of a second  amended  complaint,  and it is
likely that the court will  approve the filing of the  amended  pleading,  which
names SCE and Edison International.  The proposed second amended complaint seeks
injunctive relief and restitution for unfair competition with respect to a broad
range  of  purported   anticompetitive  conduct  by  SCE  with  respect  to  its
administration  and  interpretation of standard offer contracts and with respect
to implementation  and operation of the restructured  power market. In addition,
the  proposed  second  amended  complaint  alleges  that  SCE  engaged  in false
advertising  with  respect to the cost and  reliability  of power  generated  by
qualifying  facilities,  such as the facilities  owned by the Coso parties.  The
proposed amended  pleading also alleges  violations of Public Utilities Code ss.
2106.  The proposed  amended  pleading  seeks  restitution,  injunctive  relief,
unspecified compensatory damages and punitive damages in an amount not less than
$500,000,000.  Assuming that the court grants the Coso parties leave to file the
second  amended  complaint in its current  form,  Edison  International  and SCE
intend to file a demurrer and a motion to strike.

On June 29, 1998, the Court adopted a revised  discovery plan which provides for
approximately  eighteen  months of discovery  and periodic  status  conferences.
Discovery and motion practice related to


                                       42
<PAGE>


discovery is active,  except that the court has stayed discovery with respect to
Edison  International  through at least  December 17, 1998.  On August 28, 1998,
following  the first status  conference,  the court set a trial date of March 1,
2000. The court reserved jurisdiction to advance or continue the trial date. The
materiality of net final judgments against Edison  International or 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.

                  Electric and Magnetic Fields (EMF) Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the quarters  ended March 31, 1998,  and June 30, 1998,  SCE is
involved in three lawsuits alleging that various plaintiffs  developed cancer as
a result  of  exposure  to EMF from SCE  facilities.  SCE  denied  the  material
allegations in its responses to each of these lawsuits.

In December  1995,  the court granted  SCE's motion for summary  judgment in the
first lawsuit and dismissed the case.  Plaintiffs have filed a Notice of Appeal.
Briefs have been submitted but no date for oral argument has been set.

The second lawsuit has been  dismissed by the  plaintiffs.  However,  one of the
named  plaintiffs  is now deceased and a wrongful  death action was filed by her
husband and  children on May 7, 1998.  This  action was  dismissed  by the court
without leave to amend on September 16, 1998.

On July 23, 1998,  the court  granted  SCE's motion for summary  judgment in the
third lawsuit and dismissed this case.

A California Court of Appeal decision,  Cynthia Jill Ford, et al. v. Pacific Gas
and  Electric  Co.  (Ford),  has  held  that  the  Superior  Courts  do not have
jurisdiction to decide issues, such as those concerning EMF, which are regulated
by the CPUC.  The  California  Supreme  Court  recently  denied the  plaintiffs'
petition  for review in Ford and it is now binding  throughout  California.  SCE
intends  to seek  dismissal  of the  remaining  case in  light  of the  Court of
Appeal's decision.

                      San Onofre Personal Injury Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the quarters  ended March 31, 1998,  and June 30, 1998,  SCE is
involved in six lawsuits alleging personal injuries relating to San Onofre.

An SCE engineer  employed at San Onofre died in 1991 from cancer of the abdomen.
On February 6, 1995, his children sued SCE and San Diego Gas & Electric  Company
(SDG&E),  as well as Combustion  Engineering,  the manufacturer of the fuel rods
for the  plant,  in the  U.S.  District  Court  for  the  Southern  District  of
California in the first  lawsuit.  On December 7, 1995,  the court granted SCE's
motion for summary judgment on the sole outstanding claim against it, basing the
ruling on the worker's  compensation  system being the exclusive  remedy for the
claim. Plaintiffs appealed this ruling to the Ninth Circuit Court of Appeals. On
May 28, 1998,  the Ninth  Circuit Court  affirmed the lower court's  judgment in
favor of SCE.

On July 5, 1995,  a former SCE reactor  operator and his wife sued SCE and SDG&E
in the U.S.  District Court for the Southern  District of California in a second
lawsuit.  Plaintiffs  also named  Combustion  Engineering  and the  Institute of
Nuclear Power Operations as defendants. On December 22, 1995, SCE filed a motion
to dismiss  or, in the  alternative,  for  summary  judgment  based on  worker's
compensation exclusivity.  On March 25, 1996, the court granted SCE's motion for
summary judgment.  Plaintiffs appealed this ruling to the Ninth Circuit Court of
Appeals.  On May 28, 1998,  the Ninth Circuit  Court  affirmed the lower court's
judgment in favor of SCE.

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 in the third lawsuit.  Plaintiffs  also named  Combustion
Engineering  and the Institute of Nuclear Power  Operations as  defendants.  All
trial  court  proceedings  have been  stayed  pending the ruling of the Court of
Appeals, issued by the Ninth


                                       43
<PAGE>


Circuit on May 28, 1998 affirming the lower court's judgment in favor of SCE, in
the cases described in the above two  paragraphs.  A trial date has not yet been
set.

On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California in the fourth lawsuit.  Plaintiffs
also  named  Combustion  Engineering.  The trial in this case  took  place  over
approximately  22 days  between  January  and March 1998 and  resulted in a jury
verdict for both  defendants.  On March 19, 1998, the plaintiffs  filed a motion
for a new  trial.  That  motion  was  denied on June 9,  1998.  On July 6, 1998,
plaintiffs  filed a notice of appeal  stating  that they will  appeal  the trial
court's judgment to the Ninth Circuit Court of Appeals.

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 in the fifth lawsuit.  Plaintiffs also named Combustion  Engineering.
On August 12, 1996, the Court  dismissed the claims of the former worker and her
husband with prejudice.  This case, with only the son as plaintiff,  is expected
to go to trial in early 1999.

On November 20, 1997, a former  contract  worker at San Onofre and his wife sued
SCE in the  Superior  Court of  California,  County  of San  Diego in the  sixth
lawsuit.  The case was  removed  to the U.S.  District  Court  for the  Southern
District of California.  SCE filed a motion to dismiss the complaint for failure
to state a claim.  In April 1998, the  plaintiffs and SCE stipulated  that SCE's
motion to dismiss be granted and that the  plaintiffs  be given leave to file an
amended  complaint on or before May 11, 1998.  On May 11, 1998,  the  plaintiffs
filed a first amended  complaint.  On May 22, 1998,  SCE filed an answer denying
the material allegations of the first amended complaint.  A pre-trial conference
is scheduled for May 17, 1999.

                           False Claims Act Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the  quarters  ended  March 31,  1998,  and June 30,  1998,  in
September 1997, SCE became aware of a complaint  filed in the Southern  District
of the U.S. District Court of California by a former San Onofre employee, acting
at his own initiative on behalf of the United States under the False Claims Act,
against SCE and SDG&E.  SCE and SDG&E  filed  separate  motions to dismiss  this
lawsuit on November 6, 1997.  The former  employee  responded to both motions on
December 20, 1997. SCE and SDG&E replied to the former  employee's  responses on
January 13,  1998.  Oral  argument on the motion to dismiss was heard on January
20, 1998.  On July 1, 1998,  the U.S.  District  Court  granted  SCE's motion to
dismiss.  The court  found  that the  filed  rate  doctrine  barred  the  former
employee's  federal claims, but declined to rule on whether the state law claims
would be likewise barred.  Instead, the court declined to exercise  jurisdiction
over the state law claims in the wake of the  dismissal  of the federal  claims.
The period for appeal of the U.S.  District  Court's  decision  has passed.  Mr.
Rubaii did not file an appeal. As a result, this litigation at the U.S. District
court is now dismissed with prejudice.

               Mohave Generating Station Environmental Litigation

As previously reported in Part II, Item 1 of the Registrant's  quarterly Reports
on Form 10-Q for the  quarters  ended  March 31,  1998,  and June 30,  1998,  on
February 19, 1998,  the Sierra Club and the Grand Canyon Trust filed suit in the
U.S. District Court of Nevada against SCE, which operates Mohave,  and the other
three co-owners of Mohave  Generating  Station.  The lawsuit alleges that Mohave
has been  violating  various  provisions  of the Clean Air Act, 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 Clean Air Act, 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  and on April 10,  1998,  a
motion to dismiss was filed. The plaintiffs filed an opposition to the motion to
dismiss and a motion for  partial  summary  judgment on May 8, 1998.  On May 29,
1998,  SCE  and  the  co-owners  filed  their  reply  brief  to the  plaintiffs'
opposition.  On June 15, 1998, the plaintiffs filed their final reply brief. SCE
and the co-owners filed their final reply to plaintiffs'  opposition on June 25,
1998.  The  initial  ruling by the court on these  motions is  expected in early
1999.



                                       44
<PAGE>


In addition, on June 4, 1998, the plaintiffs served SCE and its 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 October 9,
1998,  plaintiffs  filed a  motion  to  extend  time to add a  party  and  amend
complaint.   Notwithstanding   their  supplemental  notice  of  intent  to  sue,
plaintiffs  missed the  deadline  pursuant  to the  court's  Discovery  Plan and
Scheduling  Order  to file an  amended  complaint.  On  October  26,  1998,  the
co-owners  filed a combined  opposition to plaintiffs'  motion to extend time to
add a party and amend the complaint.  Various  discovery motions have been filed
by  both  parties.  It is  not  expected  that  these  additional  filings  will
substantially change the timetable for the court's initial ruling on the pending
motions to dismiss and for partial summary judgment.

                       California Proposition 9 Litigation

As previously  reported in Part II, Item 1 of the Registrant's  quarterly Report
on Form 10-Q for the quarter ended June 30, 1998, California voters will vote on
Proposition  9,  an  initiative   supported  by  various  consumer  groups,   in
California's  November 3, 1998,  general election.  Proposition 9 would overturn
major portions of  California's  electric  industry  restructuring  legislation.
Proposition   9  purports   to:  (1)  require  SCE  and  the  other   California
investor-owned  utilities  to  provide  at least a 20% rate  reduction  to their
residential  and small  commercial  customers  to be  achieved  through  cutting
payments for nuclear and other fossil generation transition costs; (2) eliminate
cost recovery for nuclear  generation  plants and related assets and obligations
(other than reasonable  decommissioning  costs), except to the extent such costs
are  recovered  from  competitive  market  sales  through the Power  Exchange or
contracts with the Independent System Operator;  (3) eliminate cost recovery for
non-nuclear  generation  plants and related assets and  obligations  (other than
costs  associated with qualifying  facilities),  except to the extent such costs
are  recovered  from  competitive  market  sales  through the Power  Exchange or
contracts with the Independent  System Operator,  unless the CPUC finds that the
utilities  would be deprived of the  opportunity  to earn a fair rate of return;
and (4)  prohibit  the  collection  of any  customer  charges  necessary  to pay
principal,  interest and other costs on the rate reduction  bonds or, if a court
finds that the CPUC  orders  authorizing  the  collection  of such  charges  are
nevertheless  enforceable,  require the  charges to be offset with a  concurrent
equal credit.  Proposition  9's purported rate reduction would be in lieu of the
10% rate reduction for residential and small commercial customers that went into
effect on January 1, 1998.

In May 1998, a coalition of  California  business  organizations  and  utilities
filed a petition for writ of mandate  challenging  Proposition  9 as illegal and
unconstitutional  on its face and seeking to have it removed  from the  November
1998 ballot.  In July 1998, the petition was denied by the  California  Court of
Appeal and an appeal was denied by the California Supreme Court.

Under the terms of a servicing  agreement  relating to the rate reduction notes,
SCE (acting as the  servicer)  is required to take such legal or  administrative
actions as may be  reasonably  necessary  to block or overturn  any  attempts to
cause a repeal of,  modification  of, or  supplement  to the  electric  industry
restructuring legislation, the financing order issued by the CPUC, or the rights
of holders of the property right authorized by the legislation and the financing
order, by legislative  enactment,  voter initiative or constitutional  amendment
that would be adverse to holders of the rate reduction certificates.

Bankers Trust Company of California,  N.A., acting as trustee for the holders of
rate  reduction  certificates,  has sent a letter  to the  holders  of record on
October 14, 1998,  notifying  them about  certain  actions the trustee is taking
related to Proposition  9. The letter states that  Proposition 9, if approved by
the voters and upheld by the courts,  would impair the rights of the holders and
would lead to a default in the payment of  principal  and  interest.  The letter
also states that  Proposition  9, if approved,  would breach the  statutory  and
contractual  pledge by the State of California  not to limit or alter payment of
principal and interest on the rate reduction certificates,  and that such breach
would constitute an event of default under the agreements  pursuant to which the
certificates  were  issued.   Therefore,  the  letter  states,  the  trustee  is
requesting  authorization  from the  holders to  commence  litigation  to enjoin
Proposition 9 if it passes,  to collect damages on behalf of the holders for the
breach  of  the  State's  statutory  and  contractual   pledge,  and  for  other
appropriate relief. The trustee's letter also attached letters from SCE, Pacific
Gas and  Electric  Company,  and San  Diego  Gas &  Electric  Company,  in their
capacities  as  servicers,  restating  their  intention  to  comply  with  their
obligations under the related  agreements to take reasonable and necessary legal
actions to overturn Proposition 9 if it is approved by the voters.


                                       45
<PAGE>


If California  voters approve  Proposition 9, legal challenges by the California
utilities,  including  SCE,  and others  will ensue.  SCE intends to  vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions  pending court review of the merits of SCE's challenge.  Although SCE
believes the litigation arguments  challenging the enforceability of Proposition
9 would be compelling,  no assurances can be given whether or when Proposition 9
would be overturned.

SCE is unable to predict the outcome of this  matter,  but if  Proposition  9 is
voted into law, and not  immediately  stayed and  ultimately  invalidated by the
courts,  it could have a material  adverse effect on SCE's results of operations
and  financial  position as more  specifically  described in  "California  Voter
Initiative"  in Item 2 of Part 1 of  this  quarterly  Report,  which  is  hereby
incorporated by reference.

Item 6.       Exhibits and Reports on Form 8-K

(a)      Exhibits

         3.1  Restated Articles of Incorporation as amended through 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 Southern California Edison Company as amended
              through  June 1,  1993  (File  No.  1-2313,  Form 10-Q for the
              quarterly period ended September 30, 1997)*

         3.3  Bylaws as adopted by the Board of Directors effective 
              September 17, 1998

         23.  Consent of Independent Public Accountants

         27.  Financial Data Schedule

(b)      Reports on Form 8-K:

         July 13, 1998  Item 5:  Other Events:    California Voter Initiative

         July 27, 1998  Item 5:  Other Events:    Proposition 9

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

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



                                       46
<PAGE>





                                   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       R. K. BUSHEY
                                    -------------------------------------------
                                    R. K. BUSHEY
                                    Vice President and Controller



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


October 30, 1998