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                             June 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 August 12, 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, Six and
                Twelve Months Ended June 30, 1998, and 1997                   2

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

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

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

             Consolidated Statements of Retained Earnings --
                Three, Six and Twelve Months Ended
                June 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                                45




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



                                              ARTHUR ANDERSEN LLP
                                              ARTHUR ANDERSEN LLP



Los Angeles, California
August 5, 1998




                                       1
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME
In thousands
<TABLE>
<CAPTION>

                                          3 Months Ended             6 Months Ended              12 Months Ended
                                             June 30,                   June 30,                    June 30,
-------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-------------------------------------------------------------------------------------------------------------------

<S>                                <C>           <C>           <C>          <C>           <C>           <C>       
Sales to ultimate consumers        $1,531,452    $1,763,003    $3,077,286   $3,391,417    $7,325,286    $7,438,311
Sales to power exchange               303,685            --       303,685           --       303,685            --
Other                                  87,330        80,992       164,187      148,016       330,138       313,096
------------------------------------------------------------------------------------------------------------------
Operating revenue                   1,922,467     1,843,995     3,545,158    3,539,433     7,959,109     7,751,407
-------------------------------------------------------------------------------------------------------------------

Fuel                                   59,184       146,190       177,868      290,806       768,534       679,964
Purchased power-- contracts           525,355       587,660     1,101,862    1,216,335     2,739,529     2,834,041
Purchased power-- power exchange      343,784            --       343,784           --       343,784            --
Provisions for regulatory
   adjustment clauses-- net           485,492        (3,850)      247,474      (92,023)      (71,438)     (214,249)
Other operating expenses              400,055       294,670       687,629      535,398     1,368,546     1,102,402
Maintenance                            98,492       116,699       200,362      212,576       393,330       391,258
Depreciation, decommissioning and
   amortization                       375,919       311,485       758,898      617,068     1,381,705     1,163,688
Income taxes                           99,158       133,585       224,762      228,881       577,913       565,255
Property and other taxes               31,246        31,344        70,763       70,220       129,582       157,939
Gains on sale of utility plant       (708,154)       (3,065)     (708,149)      (2,836)     (709,163)       (4,810)
-------------------------------------------------------------------------------------------------------------------
Total operating expenses            1,710,531     1,614,718     3,105,253    3,076,425     6,922,322     6,675,488
-------------------------------------------------------------------------------------------------------------------
Operating income                      211,936       229,277       439,905      463,008     1,036,787     1,075,919
-------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan           --       (11,381)           --      (22,690)      (25,796)      (59,033)
Allowance for equity funds
   used during construction             2,908         1,897         5,690        3,900         9,440        12,012
Interest and dividend income           15,411         9,303        33,723       16,159        62,200        36,384
Other nonoperating income
   (deductions)-- net                  (4,310)        5,849        (7,900)      10,498       (41,434)        2,132
-------------------------------------------------------------------------------------------------------------------
Total other income (deductions)-- net  14,009         5,668        31,513        7,867         4,410        (8,505)
-------------------------------------------------------------------------------------------------------------------
Income before interest expense        225,945       234,945       471,418      470,875     1,041,197     1,067,414
-------------------------------------------------------------------------------------------------------------------
Interest on long-term debt             91,511        90,556       215,868      181,744       379,716       370,691
Other interest expense                 16,090        18,283        34,109       45,774        89,414        82,957
Allowance for borrowed funds used
   during construction                 (1,979)       (2,284)       (3,871)      (4,696)       (8,388)       (9,796)
Capitalized interest                     (125)         (735)         (282)      (2,055)         (626)       (3,597)
-------------------------------------------------------------------------------------------------------------------
Total interest expense-- net          105,497       105,820       245,824      220,767       460,116       440,255
-------------------------------------------------------------------------------------------------------------------
Net income                            120,448       129,125       225,594      250,108       581,081       627,159
Dividends on preferred stock            6,648         7,372        13,407       15,971        26,925        33,168
-------------------------------------------------------------------------------------------------------------------
Earnings available for common stock $ 113,800    $  121,753    $  212,187   $  234,137    $  554,156    $  593,991
-------------------------------------------------------------------------------------------------------------------




CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands

                                          3 Months Ended             6 Months Ended              12 Months Ended
                                             June 30,                   June 30,                    June 30,
-------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-------------------------------------------------------------------------------------------------------------------
Net income                          $120,448       $129,125     $225,594      $250,108      $581,081      $627,159
Unrealized gains on securities-- net   1,332          7,205       12,442        14,448        12,635        18,550
-------------------------------------------------------------------------------------------------------------------
Comprehensive income                $121,780       $136,330     $238,036      $264,556      $593,716      $645,709
-------------------------------------------------------------------------------------------------------------------

</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>

                                                               June 30,         December 31,          June 30,
                                                                 1998               1997                1997
-------------------------------------------------------------------------------------------------------------------

ASSETS

Transmission and distribution:
<S>                                                           <C>                 <C>               <C>    
   Utility plant, at original cost, subject to
      cost-based rate regulation                              $11,454,066         $11,213,352        $11,001,103
   Accumulated provision for depreciation                      (5,796,847)         (5,573,742)        (5,297,441)
   Construction work in progress                                  481,192             492,614            442,489
-------------------------------------------------------------------------------------------------------------------
                                                                6,138,411           6,132,224          6,146,151
-------------------------------------------------------------------------------------------------------------------
Generation:
   Utility plant, at original cost,
      not subject to cost-based rate regulation                 2,021,636           9,522,127          9,485,713
   Accumulated provision for depreciation and
      decommissioning                                          (1,065,888)         (4,970,137)        (4,635,123)
   Construction work in progress                                   86,043             100,283             86,551
   Nuclear fuel, at amortized cost                                133,070             154,757            174,216
-------------------------------------------------------------------------------------------------------------------
                                                                1,174,861           4,807,030          5,111,357
-------------------------------------------------------------------------------------------------------------------
Total utility plant                                             7,313,272          10,939,254         11,257,508
-------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated
   provision for depreciation of $24,990, $24,730
   and $23,942 at respective dates                                 66,251              67,869             68,054
Nuclear decommissioning trusts                                  2,056,275           1,831,460          1,670,747
Other investments                                                 237,627             171,399            137,882
-------------------------------------------------------------------------------------------------------------------
Total other property and investments                            2,360,153           2,070,728          1,876,683
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents                                              830,942             962,272            239,381
Receivables, including unbilled revenue, less
   allowances of $20,754, $26,453 and $21,833
   for uncollectible accounts at respective dates               1,030,792             906,388            982,010
Fuel inventory                                                     50,965              58,059             63,046
Materials and supplies, at average cost                           116,678             132,980            151,986
Accumulated deferred income taxes-- net                           313,360             123,146            193,749
Regulatory balancing accounts-- net                                50,234             193,311                 --
Prepayments and other current assets                               15,140              93,098             17,278
-------------------------------------------------------------------------------------------------------------------
Total current assets                                            2,408,111           2,469,254          1,647,450
-------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net                            2,561,325                  --                 --
Unamortized debt issuance and reacquisition
   expense                                                        362,125             359,304            332,627
Rate phase-in plan                                                     --               3,777             29,119
Income tax-related deferred charges                             1,559,336           1,543,380          1,615,930
Other deferred charges                                            816,595             673,601            541,918
-------------------------------------------------------------------------------------------------------------------
Total deferred charges                                          5,299,381           2,580,062          2,519,594
-------------------------------------------------------------------------------------------------------------------
Total assets                                                  $17,380,917         $18,059,298        $17,301,235
-------------------------------------------------------------------------------------------------------------------
</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>

                                                              June 30,         December 31,            June 30,
                                                                1998               1997                  1997
-------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES

Common shareholder's equity:
<S>                                                            <C>                 <C>                <C>               
   Common stock (434,888,104 shares
      outstanding at each date)                             $2,168,054          $2,168,054         $2,168,054
   Additional paid-in capital                                  334,032             334,031            177,873
   Accumulated other comprehensive income                       60,465              48,023             47,830
   Retained earnings                                         1,078,982           1,407,834          2,554,389
----------------------------------------------------------------------------------------------------------------
                                                             3,641,533           3,957,942          4,948,146
----------------------------------------------------------------------------------------------------------------
Preferred stock:
   Not subject to mandatory redemption                         128,755             183,755            183,755
   Subject to mandatory redemption                             256,700             275,000            275,000
Long-term debt                                               5,540,461           6,144,597          4,498,782
----------------------------------------------------------------------------------------------------------------
Total capitalization                                         9,567,449          10,561,294          9,905,683
----------------------------------------------------------------------------------------------------------------
Other long-term liabilities                                    495,703             479,637            506,066
----------------------------------------------------------------------------------------------------------------
Current portion of long-term debt                              610,332             692,875            576,470
Short-term debt                                                121,555             322,028            145,244
Accounts payable                                               396,363             406,704            382,952
Accrued taxes                                                  895,472             509,270            650,332
Accrued interest                                                94,448              85,406             97,525
Dividends payable                                               92,893              95,146            171,752
Regulatory balancing accounts-- net                                 --                  --             86,516
Deferred unbilled revenue and other
   current liabilities                                       1,049,308             931,856            772,731
----------------------------------------------------------------------------------------------------------------
Total current liabilities                                    3,260,371           3,043,285          2,883,522
----------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net                      2,956,964           2,939,471          3,000,988
Accumulated deferred investment tax credits                    308,380             326,728            336,966
Customer advances and other deferred credits                   790,980             708,745            668,010
----------------------------------------------------------------------------------------------------------------
Total deferred credits                                       4,056,324           3,974,944          4,005,964
----------------------------------------------------------------------------------------------------------------
Minority interest                                                1,070                 138                 --
----------------------------------------------------------------------------------------------------------------

Commitments and contingencies
   (Notes 2, 8, 9 and 10)




Total capitalization and liabilities                       $17,380,917         $18,059,298        $17,301,235
----------------------------------------------------------------------------------------------------------------
</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             6 Months Ended              12 Months Ended
                                             June 30,                   June 30,                    June 30,
-------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-------------------------------------------------------------------------------------------------------------------

Cash flows from operating activities:
<S>                                   <C>         <C>           <C>         <C>            <C>           <C>       
Net income                            $  120,448  $  129,125    $ 225,594   $  250,108     $  581,081    $  627,159
Adjustments for non-cash items:
  Depreciation, decommissioning and
      amortization                       375,919     311,485      758,898      617,068      1,381,705     1,163,686
  Other amortization                      46,416      19,817       72,572       31,981        121,954        69,323
  Rate phase-in plan                         --       10,894        3,777       21,584         29,119        54,590
  Deferred income taxes and
     investment tax credits             (308,917)    (51,573)    (207,025)      (8,019)      (135,627)       (5,939)
  Other long-term liabilities              1,333      54,018       16,066       82,141        (10,363)      172,159
  Regulatory asset related to sale of
     utility plant                        (9,950)         --     (107,991)          --       (107,991)           --
  Net gains on sale of utility plant    (702,972)         --     (640,339)          --       (640,339)           --
  Other-- net                            (36,211)    (46,314)     (54,333)     (67,357)      (195,596)     (225,899)
Changes in working capital:
  Receivables                           (279,473)   (149,887)    (124,404)     (60,927)       (48,782)     (327,955)
  Regulatory balancing accounts          444,844     (19,989)     143,077      (94,972)      (136,750)     (140,312)
  Fuel inventory, materials and supplies  17,099      (2,948)      23,396       11,714         47,389        42,042
  Prepayments and other current assets    39,299      42,516       77,958       87,859          2,138        12,207
  Accrued interest and taxes             348,291      82,414      395,244      169,806        242,063       176,946
  Accounts payable and other
     current liabilities                 226,755      40,673      107,111      (62,413)       289,988        63,188
-------------------------------------------------------------------------------------------------------------------
Net cash provided by operating 
   activities                            282,881     420,231      689,601      978,573      1,419,989     1,681,195
-------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt repaid                   (150,014)        (50)    (604,455)    (200,055)    (1,320,545)     (198,938)
Rate reduction notes issued                   --          --           --           --      2,444,127            --
Rate reduction notes repaid              (65,354)         --      (82,465)          --        (77,303)           --
Preferred stock redeemed                 (73,300)   (100,000)     (73,300)    (100,000)       (73,300)     (100,000)
Nuclear fuel financing-- net             (10,248)    (13,092)     (18,871)      (7,061)       (31,950)       40,199
Short-term debt financing-- net         (223,686)     10,418     (200,473)     (84,905)       (23,689)     (247,096)
Capital transferred                           --          --           --           --        153,000            --
Dividends paid                          (451,938)   (112,525)    (553,022)    (298,142)    (2,126,825)     (693,725)
-------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities   (974,540)   (215,249)  (1,532,586)    (690,163)    (1,056,485)   (1,199,560)
-------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant         (169,068)   (132,239)    (337,046)    (283,646)      (738,720)     (559,151)
Proceeds from sale of plant            1,115,238          --    1,145,039           --      1,145,039            --
Funding of nuclear decommissioning
   trusts                                (37,198)    (46,684)     (76,881)     (74,573)      (156,064)     (150,100)
Unrealized gain on securities-- net        1,332       7,205       12,442       14,448         12,635        18,550
Other-- net                               (1,178)    (17,166)     (31,899)     (25,200)       (34,833)      (66,598)
-------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by
   investing activities                  909,126    (188,884)     711,655     (368,971)       228,057      (757,299)
-------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash
   and equivalents                       217,467      16,098     (131,330)     (80,561)       591,561      (275,664)
Cash and equivalents, beginning
   of period                             613,475     223,283      962,272      319,942        239,381       515,045
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period   $  830,942  $  239,381   $  830,942   $  239,381     $  830,942    $  239,381
-------------------------------------------------------------------------------------------------------------------

Cash payments for interest and taxes:
Interest-- net of amounts capitalized $   50,859  $   96,673   $  125,667   $  176,300     $  291,503    $  351,595
Taxes                                        416      17,217          426       17,472        420,956       379,376
</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             6 Months Ended              12 Months Ended
                                             June 30,                   June 30,                    June 30,
-------------------------------------------------------------------------------------------------------------------
                                        1998         1997          1998         1997           1998         1997
-------------------------------------------------------------------------------------------------------------------

<S>                                  <C>          <C>          <C>           <C>           <C>           <C>       
Balance at beginning of period       $1,408,330   $2,603,439   $1,407,834    $2,665,612    $2,554,389    $2,680,388
Net income                              120,448      129,125      225,594       250,108       581,081       627,159
Dividends declared on common stock     (442,304)    (170,803)    (537,868)     (345,360)   (2,021,547)     (719,989)
Dividends declared on preferred stock    (6,648)      (7,372)     (13,407)      (15,971)      (26,925)      (33,168)
Stock option appreciation                  (844)          --       (3,171)           --        (3,171)           --
Reacquired capital stock expense and other   --           --           --            --        (4,845)           (1)
-------------------------------------------------------------------------------------------------------------------

Balance at end of period             $1,078,982   $2,554,389   $1,078,982    $2,554,389    $1,078,982    $2,554,389
-------------------------------------------------------------------------------------------------------------------

</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  accounting  principles  for  enterprises  in  general  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  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 June 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.  These  transition  costs  are being
recovered from utility customers (with interest) through the CTC mechanism.  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  new  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 $0.5  million,  $0.9 million and $28 million for the three,  six and twelve
months ended June 30, 1998,  respectively,  and $7 million,  $12 million and $24
million for the three, six and twelve months ended June 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 3.5%,  5.5% and 5.9%
for the three,  six and twelve  months  ended June 30, 1998,  respectively,  and
5.3%,  5.3% and 4.9% for the three,  six and twelve  months ended June 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 the  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. 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



                                       9
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.
For further  details,  see the discussion  under Long-Term Debt in Note 3 to the
Consolidated  Financial  Statements.  A voter  initiative  on the November  1998
ballot 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  --  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. 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.

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.




                                       10
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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  determining  whether any credit
should be provided by the utility to  customers  who elect to have ESPs  provide
them with revenue cycle  services,  and the amount of any such credit,  the CPUC
has  indicated  that it is  appropriate  to  provide  such  customers  with  the
utility's  avoided costs net of costs  incurred by the utility to facilitate the
provision of such services by a firm other than the utility.

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.  On May 8,  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 all 12 of its gas- and oil-fueled  generation  plants.  Transfer of
ownership of 11 plants was completed by June 30, 1998, and transfer of ownership
of the 12th plant took place on July 8, 1998.  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



                                       11
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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  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
Note 1 to the Consolidated Financial Statements),  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 a  consensus  reached  by  the
Financial  Accounting  Standards Board's Emerging Issues Task Force (EITF).  The
financial  reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the EITF consensus did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
EITF 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 consensus reached by the
EITF 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 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
generation-related  regulatory assets no longer probable,  SCE would be required
to write off the remaining balance of such assets  (approximately  $2.4 billion,
after tax, at June 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.





                                       12
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3.  Financial Instruments

Cash Equivalents

Cash and equivalents  include  tax-exempt  investments ($632 million at June 30,
1998, $936 million at December 31, 1997, and $215 million at June 30, 1997), and
time deposits and other  investments ($199 million at June 30, 1998, $26 million
at December 31, 1997, and $24 million at June 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 and caps are used to reduce the potential impact of interest
rate fluctuations on floating-rate long-term debt. At the balance sheet dates of
June 30, 1998,  December 31, 1997,  and June 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 June 30,  1998,  SCE had  pledged  $22  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.  At June 30,
1997, SCE had an interest rate cap agreement which fixed the interest rate at 6%
for $30 million of debt due 2027; it expired July 1, 1997.

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>

                                        June 30,                     December 31,                June 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          $1,448       $2,056            $1,371       $1,831         $1,292        $1,671
Equity investments                   9          110                 9           90             11            91
Gas call options                    44           56                34           34             --            --

Financial liabilities:
DOE decommissioning and
  decontamination fees              50           44                50           43             54            45
Interest rate hedges                --           25                --           24             --            17
Long-term debt                   5,540        5,708             6,145        6,456          4,499         4,672
Preferred stock subject to
  mandatory redemption             257          273               275          293            275           288
-------------------------------------------------------------------------------------------------------------------
</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,  preferred stock and the interest rate
cap;  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>

                                                                 June 30,         December 31,        June 30,
In millions                                                        1998               1997              1997
-------------------------------------------------------------------------------------------------------------------
Decommissioning trusts:
<S>                                                                <C>                <C>              <C>  
  Municipal bonds                                                  $163               $131             $ 108
  Stocks                                                            311                190               198
  U.S. government issues                                            129                 91                68
  Short-term and other                                                5                 48                 5
-------------------------------------------------------------------------------------------------------------------
                                                                    608                460               379
Equity investments                                                  101                 81                80
Gas call options                                                     12                 --                --
-------------------------------------------------------------------------------------------------------------------
Total                                                              $721               $541              $459
-------------------------------------------------------------------------------------------------------------------
</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 June 30, 1998, are: 1999 -- $610 million; 2000 --
$569  million;  2001 -- $648  million;  2002 -- $246  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
<TABLE>
<CAPTION>

Long-term debt consisted of:
                                                       June 30,                December 31,            June 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                 $2,525
Rate reduction notes:
   1998 - 2007 (5.98% to 6.42%)                          2,385                    2,463                     --
Pollution-control bonds:
   1999 - 2027 (5.4% to 7.2% and variable)               1,202                    1,202                  1,204
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                           73                       92                    105
Long-term debt due within one year                        (610)                    (693)                  (576)
Unamortized debt discount-- net                            (28)                     (37)                   (52)
-------------------------------------------------------------------------------------------------------------------
Total                                                   $5,540                   $6,145                 $4,499
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Short-Term Debt

SCE has lines of credit it can use at  negotiated  or bank index rates.  At June
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,
balancing account  undercollections  and general cash  requirements.  Commercial
paper  outstanding  at June 30, 1998,  December 31, 1997, and June 30, 1997, was
$196 million,  $415 million and $251  million,  respectively.  Commercial  paper
intended to finance  nuclear fuel  scheduled to be used more than one year after
the balance  sheet date is  classified  as  long-term  debt in  connection  with
refinancing  terms under five-year term lines of credit with  commercial  banks.
Weighted-average  interest  rates  were  5.6%,  6.0% and 5.7% at June 30,  1998,
December 31, 1997, and June 30, 1997, respectively.

Note 4.  Equity

The CPUC regulates  SCE's capital  structure,  limiting the dividends it may pay
Edison International. At June 30, 1998, SCE had the capacity to pay $1.1 billion
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 June 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>
                                                                            June 30,      December 31,     June 30,
Dollars in millions, except per share amounts                                 1998            1997           1997
-------------------------------------------------------------------------------------------------------------------

                                               June 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                                      817,000          100.00               82            100            100
-------------------------------------------------------------------------------------------------------------------
Total                                                                         $257           $275           $275
-------------------------------------------------------------------------------------------------------------------
</TABLE>

In the second quarter of 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             6 Months Ended          12 Months Ended
                                                 June 30,                   June 30,                June 30,
-------------------------------------------------------------------------------------------------------------------
In millions                                 1998          1997         1998         1997      1998         1997
-------------------------------------------------------------------------------------------------------------------

<S>                                        <C>           <C>          <C>          <C>       <C>          <C>  
Beginning balance                          $  59         $  41        $  48        $  33     $  48        $  29
Unrealized gains on securities                 1            17           20           24        20           31
Tax effect                                    --           (10)          (8)          (9)       (8)         (12)
-------------------------------------------------------------------------------------------------------------------
Ending balance                             $  60         $  48        $  60        $  48     $  60        $  48
-------------------------------------------------------------------------------------------------------------------
</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>

                                                                June 30,         December 31,          June 30,
In millions                                                       1998               1997                1997
-------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
<S>                                                            <C>                 <C>                <C>    
Property-related                                               $   203             $   227            $   238
Unrealized gains or losses                                         326                 273                191
Investment tax credits                                             156                 192                198
Regulatory balancing accounts                                       77                 180                123
Decommissioning-related                                            118                 114                107
Other                                                              412                 335                342
-------------------------------------------------------------------------------------------------------------------
Total                                                           $1,292              $1,321             $1,199
-------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related                                                $3,102              $3,272             $3,396
Capitalized software costs                                         156                 127                118
Other                                                              678                 738                492
-------------------------------------------------------------------------------------------------------------------
Total                                                           $3,936              $4,137             $4,006
-------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net                         $2,644              $2,816             $2,807
-------------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits                                    $2,957              $2,939             $3,001
Included in current assets                                         313                 123                194
</TABLE>

The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>

                                              3 Months Ended             6 Months Ended          12 Months Ended
In millions                                      June 30,                   June 30,                June 30,
-------------------------------------------------------------------------------------------------------------------
                                            1998          1997         1998         1997       1998        1997
-------------------------------------------------------------------------------------------------------------------
Current:
<S>                                        <C>           <C>          <C>           <C>       <C>          <C> 
Federal                                    $ 331         $ 151        $ 355         $176      $554         $441
State                                         74            36           78           55       123          132
-------------------------------------------------------------------------------------------------------------------
                                             405           187          433          231       677          573
-------------------------------------------------------------------------------------------------------------------
Deferred--federal and state:
Accrued charges                               17           (11)         (14)         (13)      (34)          (5)
CTC amortization                             (38)           --          (10)          --       (10)          --
Depreciation                                 (12)          (11)         (84)         (24)     (108)         (33)
Investment and energy tax credits-- net      (12)           (5)         (16)         (10)      (26)         (21)
Pension reserve                               (1)           (1)          (2)          (2)       (5)          49
Prior year state tax                         (24)          (12)           7           15        (8)          --
Regulatory balancing accounts               (225)           11         (116)          37       (12)          37
Unbilled revenue                             (12)          (16)           2           (8)       15          (56)
Other                                         (1)          (16)          17          (13)       35          (28)
-------------------------------------------------------------------------------------------------------------------
                                            (308)          (61)        (216)         (18)     (153)         (57)
Total income tax expense                  $   97          $126         $217         $213      $524         $516
-------------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income              $   99          $134         $225         $229      $578         $565
Included in other income                      (2)           (8)          (8)         (16)      (54)         (49)
</TABLE>

The composite  federal and state  statutory  income tax rate was 40.551% for the
three,  six and twelve  months  ended June 30, 1998,  and 40.551%,  for both the
three and six months  ended June 30,  1997,  and 40.798%  for the twelve  months
ended June 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             6 Months Ended          12 Months Ended
                                                 June 30,                   June 30,                June 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                          2.0         (0.7)         (1.0)       (0.8)      (1.0)       (0.8)
CTC amortization                            (17.4)          --          (2.2)         --       (0.9)         --
Depreciation and other                       18.6          9.8          12.0         6.4        9.3         5.5
Investment and energy tax credits            (2.0)        (2.0)         (2.0)       (2.2)      (1.7)       (1.9)
State tax-- net of federal deduction          8.2          7.3           6.7         7.6        6.6         7.3
-------------------------------------------------------------------------------------------------------------------
Effective tax rate                           44.4%        49.4%         48.5%       46.0%      47.3%       45.1%
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Note 6.  Employee Compensation and Benefit Plan

Stock Option Plans

On April  16,  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.

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



                                       19
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,  $2 million and $4 million for the
three, six and twelve months ended June 30, 1998, respectively,  and $8 million,
$15 million and $21 million for the three,  six and twelve months ended June 30,
1997, respectively.

Stock-based compensation expense under the fair-value method of accounting would
have  resulted in pro forma  earnings  of $114  million,  $212  million and $553
million for the three, six and twelve months ended June 30, 1998,  respectively,
and $123  million,  $236 million and $598 million for the three,  six and twelve
months ended June 30, 1997, respectively.

The  weighted-average  fair value of options  granted  during the twelve  months
ended June 30, 1998, and June 30, 1997, was $6.44 per share option and $7.66 per
share  option,  respectively.  The  weighted-average  remaining  life of options
outstanding  as of June 30, 1998,  December 31, 1997,  and June 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
                                                          June 30,
                                           ------------------------------------
                                                1998                1997
-------------------------------------------------------------------------------

Expected life                                  7 years             7 years
Risk-free interest rate                          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>

                                                         6 Months Ended         Year Ended         6 Months Ended
                                                            June 30,           December 31,           June 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                                                    28                    44                     22
Interest cost                                                   70                   138                     70
Actuarial gain                                                  --                   198                     --
Benefits paid                                                  (68)                 (288)                  (206)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                         $2,124                $2,094                 $1,888
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period            $2,298                $2,165                 $2,165
Actual return on plan assets                                   287                   369                    232
Employer contributions                                          30                    52                     30
Benefits paid                                                  (68)                 (288)                  (206)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                  $2,547                $2,298                 $2,221
-------------------------------------------------------------------------------------------------------------------
Funded status                                              $   423               $   204                $   333
Unrecognized net gain                                         (498)                 (304)                  (454)
Unrecognized net obligation (17-year amortization)              36                    38                     41
Unrecognized prior service cost                                174                   184                    191
-------------------------------------------------------------------------------------------------------------------
Pension asset (liability)                                  $   135               $   122                $   111
-------------------------------------------------------------------------------------------------------------------
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             6 Months Ended          12 Months Ended
                                                 June 30,                   June 30,                June 30,
-------------------------------------------------------------------------------------------------------------------
In millions                                 1998          1997         1998         1997      1998         1997
-------------------------------------------------------------------------------------------------------------------
<S>                                          <C>           <C>          <C>          <C>       <C>         <C>
Service cost                                 $14           $11          $28          $22       $50         $38
Interest cost                                 35            35           70           70       139         161
Expected return on plan assets               (45)          (40)         (90)         (80)     (170)       (180)
Net amortization and deferral                  4             4            8            8        13          11
-------------------------------------------------------------------------------------------------------------------
Pension expense under
   accounting standards                        8            10           16           20        32          30
Regulatory adjustment-- deferred               5             3           10            6        20          19
-------------------------------------------------------------------------------------------------------------------
Net pension expense recognized                13            13           26           26        52          49
Settlement gain                               --            --           --           --        --         (43)
-------------------------------------------------------------------------------------------------------------------
Total expense                                $13           $13          $26          $26       $52        $  6
-------------------------------------------------------------------------------------------------------------------
</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>

                                                         6 Months Ended         Year Ended         6 Months Ended
                                                            June 30,           December 31,           June 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                                                       18                 30                    14
Interest cost                                                      52                 99                    50
Actuarial loss                                                     --                114                    --
Benefits paid                                                     (32)               (59)                  (29)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                           $ 1,571             $1,533                $1,384
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period              $   815            $   617               $   617
Actual return on plan assets                                       32                147                    26
Employer contributions                                             54                110                    54
Benefits paid                                                     (32)               (59)                  (29)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                    $   869            $   815               $   668
-------------------------------------------------------------------------------------------------------------------
Funded status                                                 $  (702)           $  (718)              $  (716)
Unrecognized net loss                                             242                244                   228
Unrecognized transition obligation (20-year
   amortization)                                                  389                403                   417
-------------------------------------------------------------------------------------------------------------------
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%
</TABLE>

The components of postretirement benefits other than pensions expense were:
<TABLE>
<CAPTION>

                                              3 Months Ended             6 Months Ended          12 Months Ended
                                                 June 30,                   June 30,                June 30,
-------------------------------------------------------------------------------------------------------------------
In millions                                 1998          1997         1998         1997      1998         1997
-------------------------------------------------------------------------------------------------------------------
<S>                                         <C>          <C>           <C>          <C>      <C>          <C>  
Service cost                                $  9         $   7         $ 18         $ 14     $  34        $  27
Interest cost                                 26            25           52           50       101          102
Expected return on plan assets               (16)          (13)         (32)         (26)      (56)         (51)
Amortization of loss                           1             2            2            4         2            6
Amortization of transition obligation          7             7           14           14        27           27
-------------------------------------------------------------------------------------------------------------------
Net expense                                   27            28           54           56       108          111
Special termination expense                   --            --           --           --        --           23
-------------------------------------------------------------------------------------------------------------------
Total expense                               $ 27          $ 28         $ 54         $ 56      $108         $134
-------------------------------------------------------------------------------------------------------------------
</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 June 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 June 30, 1998, by $218 million and annual aggregate
service and interest costs by $23 million.

Employee Savings Plan

SCE has a 401(k)  defined  contribution  savings  plan  designed  to  supplement
employees'  retirement  income.  The plan received employer  contributions of $5
million,  $8 million and $15 million for the three,  six and twelve months ended
June 30, 1998, respectively,  and $4 million, $7 million and $22 million for the
three, six and twelve months ended June 30, 1997, respectively.




                                       22
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 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              $  1               50
Generating stations:
  Four Corners Units 4 and 5 (coal)                      460              259                 1               48
  Mohave (coal)                                          311              156                 6               56
  Palo Verde (nuclear)(1)                              1,604              787                10               16
  San Onofre (nuclear)(1)                              4,215            2,481                35               75
-------------------------------------------------------------------------------------------------------------------
Total                                                 $6,864           $3,766               $53
-------------------------------------------------------------------------------------------------------------------
</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 June 30, 1998,
were:

Year ended December 31,                                             In millions
-------------------------------------------------------------------------------
1998                                                                 $ 7
1999                                                                  13
2000                                                                  11
2001                                                                   8
2002                                                                   4
Thereafter                                                             6
-------------------------------------------------------------------------------
Total                                                                $49
-------------------------------------------------------------------------------

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
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 1999, 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 $37
million, $77 million and $157 million for the three, six and twelve months ended
June 30, 1998,  respectively,  and $39 million, $75 million and $150 million for
the  three,  six and  twelve  months  ended  June 30,  1997,  respectively.  The
accumulated provision for



                                       23
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

decommissioning  was $1.1 billion at June 30, 1998, $1.1 billion at December 31,
1997, and $1.0 billion at June 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            June 30,         December 31,          June 30,
In millions                                   Dates               1998               1997                1997
-------------------------------------------------------------------------------------------------------------------
<S>                                         <C>                <C>               <C>                   <C>   
Municipal bonds                             1998-2029           $   486           $  459                $  439
Stocks                                          --                  535              392                   544
U.S. government issues                      1999-2027               425              357                   300
Short-term and other                        2002-2028                 2              163                     9
-------------------------------------------------------------------------------------------------------------------
Total                                                            $1,448           $1,371                $1,292
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Trust fund earnings (based on specific  identification)  increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $12
million,  $27 million and $57 million for the three, six and twelve months ended
June 30, 1998,  respectively,  and $11 million,  $23 million and $51 million for
the three,  six and twelve  months ended June 30, 1997,  respectively.  Proceeds
from sales of securities (which are reinvested) were $362 million,  $569 million
and $903  million  for the three,  six and twelve  months  ended June 30,  1998,
respectively, and $114 million, $261 million and $628 million for the three, six
and twelve  months  ended  June 30,  1997.  Approximately  89% of the trust fund
contributions were tax-deductible.

The Financial Accounting Standards Board has issued an exposure draft related to
accounting  practices for removal costs,  including  decommissioning  of nuclear
power  plants.  The  exposure  draft would  require SCE to report its  estimated
decommissioning  costs as a liability,  rather than recognizing these costs over
the term of each facility's  operating license (current industry practice).  SCE
does not believe that the changes  proposed in the exposure  draft would have an
adverse effect on its results of operations even after  deregulation  due to its
current and expected  future  ability to recover  these costs  through  customer
rates.

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.

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                              $841       $704      $685       $684       $656
Fuel supply contracts                                             241        146       166        154        162
Purchased-power capacity payments                                 703        706       707        706        703
Unconditional purchase obligations                                  9          9        10          9         10
-------------------------------------------------------------------------------------------------------------------
</TABLE>




                                       24
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Proposition 9 -- November 1998 Voter Initiative

In November 1997, individuals  representing The Utilities Reform Network, Public
Media Center and the  Coalition  Against  Utility  Taxes filed a proposed  voter
initiative  that seeks to  overturn  major  portions  of the  electric  industry
restructuring legislation enacted in California in September 1996 (Statute). The
voter initiative proposes,  among other things, to: (i) impose an additional 10%
rate reduction for residential  and small  commercial  customers  beyond the 10%
reduction  that went into  effect on January 1, 1998;  (ii) block  stranded-cost
recovery  of nuclear  investments;  (iii)  restrict  stranded-cost  recovery  of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the  opportunity  to earn a fair  rate  of  return;  and  (iv)  prohibit  the
collection of any charges in connection  with a financing  order for the purpose
of making  payments on rate reduction  notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.

On June 24, 1998, the California  Secretary of State announced that the proposed
voter initiative  qualified for the November 1998 ballot.  On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.

On May 22, 1998,  Californians  for  Affordable  and Reliable  Electric  Service
(CARES), a coalition of California business organizations and utilities, filed a
petition  for  writ of  mandate  with  the  Court  of  Appeal  of the  State  of
California.  CARES is  sponsored  by the  California  Business  Roundtable,  the
California Chamber of Commerce, San Diego Gas & Electric Company, the California
Manufacturers  Association,  Pacific  Gas &  Electric  Company,  the  California
Retailers  Association,   and  SCE,  among  other  groups.  The  CARES  petition
challenged  the  initiative  as illegal and  unconstitutional  on its face,  and
sought to remove the initiative from the November 1998 ballot.  On July 2, 1998,
the Court of Appeal denied the CARES petition.  On July 6, 1998, CARES filed its
appeal of the denial with the California  Supreme  Court.  On July 15, 1998, the
California Supreme Court denied the CARES petition.  In these rulings, the Court
of Appeal of the State of  California  and the  California  Supreme  Court  both
decided,  in effect,  not to consider  the  legality  and  constitutionality  of
Proposition 9 prior to the November 1998 election.

If Proposition 9 is voted into law, further  litigation  would ensue.  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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property  right  authorized by the Statute
and  the  financing  order  by  legislative   enactment,   voter  initiative  or
constitutional  amendment that would be adverse to holders of the rate reduction
notes.  The costs of such  actions  would be payable out of  collections  of the
non-bypassable  charges  established  by the  financing  order  and the  related
issuance  advice letter as an operating  expense  related to the rate  reduction
notes.  However,  SCE may be  required  to advance  its own funds to satisfy its
obligations as servicer to take such legal and administrative actions.

SCE is unable to predict the outcome of this matter,  but if  Proposition 9 were
to be 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
operation  and  financial  position.  Upon voter  approval of  Proposition  9, a
write-down



                                       25
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of a  portion  of  SCE's  generation-related  assets  might  be  required  under
applicable  accounting  principles,  depending on SCE's  assessment  of both the
probability that Proposition 9 would be struck down by the courts and the manner
in which it would  be  interpreted  and  applied  to SCE.  The  meaning  of many
provisions of  Proposition 9 is unclear and, if the courts uphold it in whole or
part,  will be subject to judicial and regulatory  interpretation.  Depending on
how  Proposition  9 is  interpreted  and  implemented  with  respect to SCE, the
potential write-down of SCE's generation-related  assets could amount to as much
as $1.9 billion after tax.

Additionally,  if Proposition 9 passes and survives legal challenges,  SCE could
suffer  impacts on its  annual  earnings,  including  the  possibility  of being
required to offset customer charges  necessary to pay the principal and interest
on  the  rate  reduction  notes.  Depending  on how  this  provision  and  other
provisions of Proposition 9 are  interpreted  and applied,  the annual  earnings
reductions could be as large as $210 million in 1999,  gradually declining to as
much as $10 million in 2007, and immaterial amounts thereafter.

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 $178 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 $246 million. The upper limit of this range of costs
was  estimated  using  assumptions  least  favorable  to SCE  among a  range  of
reasonably possible outcomes.  SCE has sold all of its gas- and oil-fueled power
plants and has retained some liability associated with the divested properties.

The CPUC allows SCE to recover  environmental-cleanup  costs at 41 of its sites,
representing  $91  million  of its  recorded  liability,  through  an  incentive
mechanism (SCE may request to include additional  sites).  Under this mechanism,
SCE will recover 90% of cleanup costs through customer rates;  shareholders fund
the remaining  10%, with the  opportunity  to recover these costs from insurance
carriers and other third parties.  SCE has successfully settled insurance claims
with all  responsible  carriers.  Costs  incurred at SCE's  remaining  sites are
expected to be recovered  through  customer rates. SCE has recorded a regulatory
asset of $148  million for its  estimated  minimum  environmental-cleanup  costs
expected to be recovered through customer rates.





                                       26
<PAGE>





SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 30,
1998, were $6 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 $8.9
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 $79 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 $158  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 $26 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,  six and
twelve  months ended June 30,  1998,  were $114  million,  $212 million and $554
million, respectively, compared with $122 million, $234 million and $594 million
for the same  periods in 1997.  Earnings  from the twelve  months ended June 30,
1997,  include a net one-time  gain of $14 million in 1996 for an  adjustment to
workforce  management costs and reserves.  Excluding the one-time gain, earnings
decreased $8 million, $22 million and $26 million,  respectively, for the three,
six and twelve months ended June 30, 1998, compared to the year-earlier periods.
The decreases were the result of lower authorized  revenue,  which was driven by
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 decreases were partially  offset by San
Onofre  Nuclear  Generating  Station's  greater  number of operating days in the
current period.

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 -- PX and
ISO." Excluding the sales to the PX, operating revenue decreased 12%, 8% and 1%,
respectively, for the three, six and twelve months ended June 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  also  includes a  decrease  in sales  volume due to milder  weather in
second  quarter  1998.  The  twelve-months-ended  decrease  also  reflects  a 1%
decrease in sales volume.  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 60% and 39%,  respectively,  for the three and six months
ended June 30, 1998,  respectively,  compared to the same  periods in 1997.  The
quarterly  and  year-to-date  decreases  resulted  from the sale of the gas- and
oil-fueled  plants.  In  addition,   the  year-to-date  decrease  also  reflects
significantly  lower gas  prices in the first  quarter  of 1998.  For the twelve
months  ended  June 30,  1998,  fuel  expense  increased  13%,  compared  to the
year-earlier period, reflecting the effects of the extended refueling outages at
San  Onofre  Units 2 and 3 during the third  quarter of 1997,  as well as a $174
million gas contract termination payment during third quarter 1997.

Since April 1, 1998,  SCE is  required to purchase  all of its power from the PX
for distribution to its customers.  The new competitive market has caused SCE to
only make federally  required  purchases or purchases  required under  long-term
contracts and to discontinue making economy power purchases. Excluding the power
purchased  from  the  PX,   purchased-power   expense   decreased  11%  and  9%,
respectively,  for the three and six months ended June 30, 1998, compared to the
year-earlier  periods. The decreases are the result of SCE discontinuing economy
purchases.  SCE is required  under  federal law to purchase  power from  certain
nonutility  generators  even though  energy  prices  under these  contracts  are
generally higher than other sources.  For the twelve months ended June 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.




                                       28
<PAGE>





Provisions for regulatory  adjustment  clauses  increased  substantially for the
quarter,  six months and twelve months ended June 30, 1998, compared to the same
periods  in  1997,  primarily  due to  overcollections  in the  transition  cost
balancing  account  resulting  from the gain on sales of the gas- and oil-fueled
plants in second quarter 1998.  The  overcollections  were  partially  offset by
undercollections related to direct access activities,  the delay in the start-up
of the PX and  independent  system  operator  (ISO) and the issuance of the rate
reduction  notes in December  1997.  Beginning in January 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  in the  administration  of
public-purpose funds.

Other operating  expenses  increased for the three,  six and twelve months ended
June 30,  1998,  compared to the same periods in 1997,  primarily  due to direct
access activities,  must-run reliability services and PX and ISO activities. The
year-to-date increase also reflects storm damage resulting from a harsher winter
in 1998. In addition, the twelve-months-ended  increase includes higher costs at
San Onofre related to the Unit 2 and 3 outages.

Maintenance  expense decreased 16% for the quarter ended June 30, 1998, compared
to the year-earlier  period,  reflecting the extended  refueling  outages at San
Onofre during the second quarter of 1997.

Depreciation,  decommissioning  and amortization  expense increased 21%, 23% and
19%, respectively,  for the quarter, six months and twelve months ended June 30,
1998,  compared to the same periods in 1997.  The increases are primarily due to
the accelerated  recovery of the gas- and oil-fueled  generation  plants and the
further acceleration of the San Onofre and Palo Verde Nuclear Generating Station
units.  The  accelerated   recoveries  implemented  in  1998  are  part  of  the
competition  transition  charge (CTC)  mechanism (see further  discussion  under
"California Electric Utility Industry  Restructuring").  The twelve-months-ended
increase also reflects the initial accelerated recovery of the Palo Verde units,
which began in January 1997.

Income taxes decreased 26% for the quarter ended June 30, 1998,  compared to the
year-earlier  period,  primarily  due  to  lower  pre-tax  income,  as  well  as
additional  amortization  related to the CTC  mechanism.  Also,  the  additional
amortization  related to the CTC mechanism will continue to cause an increase in
the effective tax rate.

Property  and other taxes  decreased  18% for the twelve  months  ended June 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.

Gains  on sale of  utility  plant  are  from the sale of 11 of SCE's 12 gas- and
oil-fueled generation plants in the first half of 1998.

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%, 109% and 71%, respectively,  for the
three,  six and twelve months ended June 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. The year-to-date and  twelve-months-ended
increases   also   reflect   interest   earned  on  higher   balancing   account
undercollections.

Other nonoperating income decreased  substantially for the three, six and twelve
months ended June 30, 1998, compared to the year-earlier periods,  mostly due to
additional  accruals for regulatory matters associated with the restructuring of
California's electric utility industry.




                                       29
<PAGE>





Interest Expense

Interest on long-term debt increased 19% for the six months ended June 30, 1998,
compared to the same period in 1997,  primarily  due to the issuance of the rate
reduction  notes in December 1997.  Interest on the rate reduction notes was $38
million,  $77  million and $86  million,  respectively,  for the three,  six and
twelve months ended June 30, 1998.

Other  interest  expense  decreased  25% for the six months ended June 30, 1998,
compared  to the same  period in 1997.  The  year-to-date  decrease  reflects  a
reduction  in  balancing   account  interest  expense  as  a  result  of  higher
undercollections in first quarter 1998.

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 95.3 million shares
($2.3 billion) between January 1995 and August 5, 1998, funded by dividends from
its subsidiaries and the issuance of rate reduction notes.

SCE's cash flow coverage of dividends for the three, six and twelve months ended
June 30, 1998, was 0.6 times, 1.2 times and 0.7 times, respectively, compared to
3.7 times, 3.3 times and 2.4 times for the year-earlier periods. These decreases
reflect a $350  million  special  dividend SCE paid to Edison  International  in
second  quarter  1998 from the oil- and  gas-fueled  plant sales  proceeds.  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 $283 million, $690 million and
$1.4 billion,  respectively, for the three, six and twelve months ended June 30,
1998, compared with $420 million,  $979 million and $1.7 billion,  respectively,
for the same periods in 1997. Cash from operations exceeded capital requirements
for all periods presented.

Cash Flows from Financing Activities

At June 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 with various  expiration  dates;
the majority have five-year terms.

Short-term  debt  is  used  to  finance  fuel  inventories,   balancing  account
undercollections 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 June  30,  1998,  SCE  could  issue
approximately $12.0 billion of additional first and refunding mortgage bonds and
$4.4 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 June 30, 1998,  SCE
had the capacity to pay $1.1  billion 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



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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 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 Proposition 9 -- November 1998 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  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 ($2.1 billion), escalated using a 6.65% annual rate. These
costs are expected to be funded from independent  decommissioning  trusts, which
will  receive SCE  contributions  of  approximately  $100 million per year until
decommissioning begins. 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.

SCE has hedged a portion of its  exposure  to  increases  in natural gas prices.
Increases  in  natural  gas prices  tend to  increase  the price of  electricity
purchased from the PX. SCE's  exposure is also limited by regulatory  mechanisms
that protect SCE from much of the risk arising from high electricity prices.

A 10% increase in market interest rates would result in a $6 million increase in
the fair value of SCE's interest rate hedge agreements. A 10% decrease in market
interest rates would result in a $6 million  decline in the fair market value of
interest rate hedge agreements. A 10% increase in natural gas prices



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would  result in a $38 million  increase  in the fair  market  value of gas call
options.  A 10%  decrease  in natural gas prices  would  result in a $26 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--
$841 million; 1999-- $704 million; 2000-- $685 million; 2001-- $684 million; and
2002-- $656 million.

Long-term  debt   maturities  and  sinking  fund   requirements   for  the  five
twelve-month periods following June 30, 1998, are: 1999 -- $610 million; 2000 --
$569  million;  2001 -- $648  million;  2002 -- $246  million;  and 2003 -- $572
million.

Preferred  stock  redemption  requirements  for the  five  twelve-month  periods
following June 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.

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 enables 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



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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 Utilities
Reform Network  recommended a combined total disallowance of $37 million. A CPUC
decision is expected in third quarter 1998. In third 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  the date of
divestiture.

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 Proposition 9 -- November 1998 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.  A
voter initiative on the November 1998 ballot 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
discussion in "Cash Flows from Financing Activities."

Rate-setting  --  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. In



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<PAGE>





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.

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 July 1, 1998,  approximately  47,000 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  determining  whether any credit
should be provided by the utility to  customers  who elect to have ESPs  provide
them with revenue cycle  services,  and the amount of any such credit,  the CPUC
has  indicated  that it is  appropriate  to  provide  such  customers  with  the
utility's  avoided costs net of costs  incurred by the utility to facilitate the
provision of such services by a firm other than the utility.  The  unbundling of
revenue  cycle  services  will expose SCE to the possible  loss of revenue and a
reduction in revenue security.

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.  On May 8,  1998,  SCE  filed an  application  on this  issue.  A CPUC
decision is expected in early 1999.




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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 all 12 of its gas- and oil-fueled  generation  plants.  Transfer of
ownership of 11 plants was completed by June 30, 1998, and transfer of ownership
of the 12th plant took place on July 8, 1998.  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 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 of 1997, SCE  discontinued
application of accounting  principles  for  rate-regulated  enterprises  for its
investment  in  generation  facilities  based  on a  consensus  reached  by  the
Financial  Accounting  Standards Board's Emerging Issues Task Force (EITF).  The
financial  reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the EITF consensus did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
EITF 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



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<PAGE>





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 consensus reached by the EITF 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 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  $2.4
billion,  after tax, at June 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 Proposition 9 -- November 1998 Voter Initiative

In November 1997, individuals  representing The Utilities Reform Network, Public
Media Center and the  Coalition  Against  Utility  Taxes filed a proposed  voter
initiative  that seeks to  overturn  major  portions  of the  electric  industry
restructuring legislation enacted in California in September 1996 (Statute). The
voter initiative proposes,  among other things, to: (i) impose an additional 10%
rate reduction for residential  and small  commercial  customers  beyond the 10%
reduction  that went into  effect on January 1, 1998;  (ii) block  stranded-cost
recovery  of nuclear  investments;  (iii)  restrict  stranded-cost  recovery  of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the  opportunity  to earn a fair  rate  of  return;  and  (iv)  prohibit  the
collection of any charges in connection  with a financing  order for the purpose
of making  payments on rate reduction  notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.

On June 24, 1998, the California  Secretary of State announced that the proposed
voter initiative  qualified for the November 1998 ballot.  On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.

On May 22, 1998,  Californians  for  Affordable  and Reliable  Electric  Service
(CARES), a coalition of California business organizations and utilities, filed a
petition  for  writ of  mandate  with  the  Court  of  Appeal  of the  State  of
California.  CARES is  sponsored  by the  California  Business  Roundtable,  the
California Chamber of Commerce, San Diego Gas & Electric Company, the California
Manufacturers  Association,  Pacific  Gas &  Electric  Company,  the  California
Retailers  Association,   and  SCE,  among  other  groups.  The  CARES  petition
challenged  the  initiative  as illegal and  unconstitutional  on its face,  and
sought to remove the initiative from the November 1998 ballot.  On July 2, 1998,
the Court of Appeal denied the CARES petition.  On July 6, 1998, CARES filed its
appeal of the denial with the California  Supreme  Court.  On July 15, 1998, the
California Supreme Court denied the CARES petition.  In these rulings, the Court
of Appeal of the State of  California  and the  California  Supreme  Court  both
decided,  in effect,  not to consider  the  legality  and  constitutionality  of
Proposition 9 prior to the November 1998 election.

If Proposition 9 is voted into law, further  litigation  would ensue.  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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property  right  authorized by the Statute
and the financing order by legislative



                                       36
<PAGE>





enactment, voter initiative or constitutional amendment that would be adverse to
holders of the rate reduction  notes. The costs of such actions would be payable
out of collections of the  non-bypassable  charges  established by the financing
order and the related issuance advice letter as an operating  expense related to
the rate reduction notes.  However, SCE may be required to advance its own funds
to satisfy its  obligations  as  servicer to take such legal and  administrative
actions.

SCE is unable to predict the outcome of this matter,  but if  Proposition 9 were
to be 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
operation  and  financial  position.  Upon voter  approval of  Proposition  9, a
write-down  of a portion of SCE's  generation-related  assets  might be required
under applicable  accounting  principles,  depending on SCE's assessment of both
the  probability  that  Proposition 9 would be struck down by the courts and the
manner in which it would be interpreted  and applied to SCE. The meaning of many
provisions of  Proposition 9 is unclear and, if the courts uphold it in whole or
part,  will be subject to judicial and regulatory  interpretation.  Depending on
how  Proposition  9 is  interpreted  and  implemented  with  respect to SCE, the
potential write-down of SCE's generation-related  assets could amount to as much
as $1.9 billion after tax.

Additionally,  if Proposition 9 passes and survives legal challenges,  SCE could
suffer  impacts on its  annual  earnings,  including  the  possibility  of being
required to offset customer charges  necessary to pay the principal and interest
on  the  rate  reduction  notes.  Depending  on how  this  provision  and  other
provisions of Proposition 9 are  interpreted  and applied,  the annual  earnings
reductions could be as large as $210 million in 1999,  gradually declining to as
much as $10 million in 2007, and immaterial amounts thereafter.

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 $178  million.  One of SCE's  sites,  a  former  pole-treating  facility,  is
considered  a  federal  Superfund  site  and  represents  41%  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 $246
million.  The upper limit of this range of costs was estimated using assumptions
least favorable to SCE among a range of reasonably  possible  outcomes.  SCE has
sold all of its gas- and oil-fueled power plants and has retained some liability
associated with the divested properties.

The CPUC allows SCE to recover  environmental-cleanup  costs at 41 of its sites,
representing  $91  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 $148 million for its  estimated
minimum  environmental-cleanup  costs expected to be recovered  through customer
rates.

SCE's  identified  sites  include  several  sites for  which  there is a lack of
currently  available   information,   including  the  nature  and  magnitude  of
contamination,  and the extent,  if any,  that SCE may be held  responsible  for
contributing  to any costs  incurred  for  remediating  these  sites.  Thus,  no
reasonable estimate of cleanup costs can be made for these sites.




                                       37
<PAGE>





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 June
30, 1998, were $6 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.

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

Accounting Rules

During 1996, the Financial  Accounting  Standards Board issued an exposure draft
that would establish accounting standards for the recognition and measurement of
closure and removal obligations.  The exposure draft would require the estimated
present value of an obligation to be recorded as a liability,



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<PAGE>





along with a  corresponding  increase in the plant or regulatory  asset accounts
when the  obligation  is  incurred.  If the  exposure  draft is  approved in its
present form, it would affect SCE's accounting practices for the decommissioning
of its nuclear power plants, obligations for coal mine reclamation costs and any
other  activities  related to the closure or removal of long-lived  assets.  SCE
does not expect that the accounting changes proposed in the exposure draft would
have an adverse effect on its results of operations even after  deregulation due
to its current  and  expected  future  ability to recover  these  costs  through
customer rates.

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 identify a year by using only two digits
instead of four. If not corrected, these programs could fail or create erroneous
results  beginning in 2000. This situation has been referred to generally as the
Year 2000 Issue.

SCE has a  comprehensive  program  in place to  remediate  potential  Year  2000
impacts. SCE divides its Year 2000 Issue activities into five phases: inventory,
impact  assessment,  remediation,  testing  and  implementation.  SCE's plan for
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. SCE is on schedule to have its mainframe and distributed
computing  assets Year  2000-ready  within the timeframe  discussed  above.  The
physical  asset  portfolio  includes  systems in the  generation,  transmission,
distribution,  telecommunications  and facilities  areas.  SCE has completed its
inventory of these systems and impact assessment for critical physical assets is
nearly complete.

The other  essential  component  of the SCE Year 2000  readiness  program  is to
identify  and  assess  vendor  products  and  business  partners  for 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.

Preliminary  estimates of the costs to complete these  modifications,  including
the cost of new hardware and software application  modification,  range from $55
million to $80 million, about half of which are



                                       39
<PAGE>





expected to be capital  costs.  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  remediated
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 Year 2000-related  processing failures or
malfunctions  due to SCE's  internal  systems or from  external  parties.  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  the beginning of 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.




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<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 Report
on Form 10-Q for the quarter  ended March 31,  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 ("Los Angeles  County") and one was
filed in Kern County Superior Court ("Kern  County").  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.

Geothermal Generators' Litigation

As previously  reported in Part II, Item 1 of the Registrant's  quarterly Report
on Form 10-Q for the quarter ended March 31, 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
(collectively the "Coso  Defendants").  SCE alleges that in order to avoid power
production  plant  shutdowns  caused  by  excessive  noncondensable  gas  in the
geothermal  field  brine,  the Coso  Defendants  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 Defendants of their  obligations  under their contracts and
applicable  law. The complaint  sought  termination of the contracts and damages
for  excess  power  purchase  payments  made to the  Coso  Defendants.  The Coso
Defendants'  motion to transfer venue to Inyo County  Superior Court was granted
on August 31, 1997.

On December 19, 1997,  SCE filed a first amended  complaint in response to which
the Coso Defendants  filed a motion to strike the  termination  remedy sought by
SCE. This motion was granted on June 1, 1998. The Coso  Defendants  also filed a
motion for summary judgment, asserting that SCE's claims are time-barred or were
released in connection with the settlement of prior litigation among some of the
Coso Defendants and two of SCE's affiliates,  Mission Power Engineering, and The
Mission  Group (the  Mission  Parties).  The court  denied the Coso  Defendants'
motion for summary  judgment by order dated July 8, 1998. In addition,  the Coso
Defendants  filed a motion to stay  SCE's  case  pending  resolution  of certain
technical  issues by the Great Basin Air Quality  Management  District under the
doctrine of primary adjudication. On April 30, 1998, the court denied the motion
for stay without prejudice.

The Coso  Defendants  have also  asserted  various  claims  against  SCE and the
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  Defendants
in Inyo County Superior Court. Following a hearing on



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<PAGE>





November 20, 1997,  the court  consolidated  these  actions for all purposes and
ordered  the  Coso   Defendants  to  file  a  second  amended   cross-complaint,
incorporating all but two of the claims in the separate complaint.

The second amended  cross-complaint  asserts  nineteen  causes of action against
SCE, three of which are also asserted against the Mission  Parties,  and alleges
in excess of $115 million in  compensatory  damages and also  punitive  damages.
Several of these  claims are  premised  on the theory  that SCE has  incorrectly
interpreted  the  cross-complainants'  contracts as providing  for only a single
"fixed price" period in view of the fact that the  cross-complainants  developed
their  projects  in  phases.  This  theory  has  also  been  asserted  by  other
independent power producers in litigation pending in Los Angeles Superior Court.
(See "Wind Generators  Litigation" above.) SCE filed a demurrer to, as well as a
motion to strike,  certain portions of the second amended  cross-complaint which
was argued on March 13, 1998. On May 22, 1998, the court granted SCE's motion to
strike and  sustained  the  demurrer  with leave to amend.  The Coso  Defendants
subsequently  filed a motion for leave to file a third  amended  cross-complaint
which was argued and taken under submission on July 9, 1998.

Electric and Magnetic Fields (EMF) Litigation

As previously  reported in Part II, Item 1 of the Registrant's  quarterly Report
on Form 10-Q for the  quarter  ended  March 31,  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 and has been served on SCE.

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 &
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 cases 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 Report
on Form 10-Q for the  quarter  ended  March 31,  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 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. The
impact  on SCE,  if any,  from  further  proceedings  in this case  against  the
remaining defendants cannot be determined at this time.

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



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<PAGE>





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. The impact on SCE, if any, from further
proceedings in this case against the remaining  defendants  cannot be determined
at this time.

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,  recently  issued by the Ninth  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 late 1998 or 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.

False Claims Act Litigation

As previously  reported in Part II, Item 1 of the Registrant's  quarterly Report
on Form 10-Q for the quarter ended March 31, 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.

Mohave Generating Station Environmental Litigation

As previously  reported in Part II, Item 1 of the Registrant's  quarterly Report
on Form 10-Q for the quarter  ended March 31, 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



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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
fall.

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 that may be added to the ongoing  litigation  after
August 3, 1998.  The new causes of action are  expected to be a variation of the
existing allegations,  and are not expected to raise new substantive issues. The
supplemental  notice  also  stated  the  intent  to add the  National  Parks and
Conservation  Association  as an  additional  plaintiff  to  these  proceedings.
However,  it is not expected that this will  substantially  change the timetable
for the court's initial ruling on all the pending motions.

California Proposition 9 Litigation

In November 1997, individuals  representing The Utilities Reform Network, Public
Media Center and the  Coalition  Against  Utility  Taxes filed a proposed  voter
initiative  that seeks to  overturn  major  portions  of the  electric  industry
restructuring  legislation  enacted in California in September 1996 ("Statute").
The voter initiative proposes,  among other things, to: (i) impose an additional
10% rate reduction for residential and small commercial customers beyond the 10%
reduction  that went into  effect on January 1, 1998;  (ii) block  stranded-cost
recovery  of nuclear  investments;  (iii)  restrict  stranded-cost  recovery  of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the  opportunity  to earn a fair  rate  of  return;  and  (iv)  prohibit  the
collection of any charges in connection  with a financing  order for the purpose
of making  payments on rate reduction  notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.

On June 24, 1998, the California  Secretary of State announced that the proposed
voter initiative  qualified for the November 1998 ballot.  On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.

On May 22, 1998,  Californians  for  Affordable  and Reliable  Electric  Service
(CARES),  a  coalition  of  California  business   organizations  and  utilities
(sponsored by the California  Business  Roundtable,  the  California  Chamber of
Commerce,  San  Diego  Gas &  Electric  Company,  the  California  Manufacturers
Association,   Pacific  Gas  &  Electric  Company,   the  California   Retailers
Association,  and SCE,  among other groups) filed a petition for writ of mandate
with  the  Court of  Appeal  of the  State of  California.  The  CARES  petition
challenged the voter initiative  (later  designated as Proposition 9) as illegal
and  unconstitutional  on its face, and sought to remove the initiative from the
November  1998  ballot.  On July 2, 1998,  the Court of Appeal  denied the CARES
petition.  On July 6,  1998,  CARES  filed  its  appeal of the  denial  with the
California  Supreme Court. On July 15, 1998, the California Supreme Court denied
the CARES  petition for  pre-election  review.  In these  rulings,  the Court of
Appeal of the State of California and the California Supreme Court both decided,
in effect, not to consider the legality and  constitutionality  of Proposition 9
prior to the November 1998 election.

If Proposition 9 is voted into law, further  litigation  would ensue.  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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property  right  authorized by the Statute
and  the  financing  order  by  legislative   enactment,   voter  initiative  or
constitutional  amendment that would be adverse to holders of the rate reduction
notes.  The costs of such  actions  would be payable out of  collections  of the
non-bypassable  charges  established  by the  financing  order  and the  related
issuance  advice letter as an operating  expense  related to the rate  reduction
notes.  However,  SCE may be  required  to advance  its own funds to satisfy its
obligations as servicer to take such legal and administrative actions.

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



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<PAGE>





SCE's results of operation and financial position as more specifically described
in California  Proposition 9 -- November 1998 Voter Initiative in Item 2 of Part
1 of this Form, 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)*





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<PAGE>





         3.3  Bylaws  as  adopted by the Board of Directors effective January 1,
              1998 (File No. 1-2313, Form 10-K for the year ended 
              December 31, 1997)*

         10.  Material Contracts

              10.1.    Equity Compensation Plan
              10.2.    Retirement Plan for Directors
              10.3.    Director Deferred Compensation Plan
              10.4.    Form of Agreement for 1998 Employee Awards under the
                       Equity  Compensation Plan
              10.5.    Form of 1998 Director Award under the Equity Compensation
                       Plan

         23.      Consent of Independent Public Accountants

         27.      Financial Data Schedule

(b)      Reports on Form 8-K:

         None

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

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





                                   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

August 13, 1998