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

                                          FORM 10-Q

(Mark One)

[X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
      SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
      SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________________to ____________________________

                                Commission File Number 1-9936

                                     EDISON INTERNATIONAL
                    (Exact name of registrant as specified in its charter)

                   California                                        95-4137452
         (State or other jurisdiction of                          (I.R.S. Employer
         incorporation or organization)                          Identification No.)

            2244 Walnut Grove Avenue
                 (P. O. Box 976)
              Rosemead, California                                      91770
    (Address of principal executive offices)                         (Zip Code)

                                        (626) 302-2222
                     (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant  (1) has filed all reports  required to be filed
by Section 13 or 15(d) of the  Securities  Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the  registrant  was required to file such reports),  and (2)
has been subject to such filing requirements for the past 90 days.              Yes   |X|   No
|_|

Indicate by check mark  whether the  registrant  is an  accelerated  filer (as defined in Rule
12b-2 of the Exchange Act).                                                     Yes   |X|   No
|_|

Indicate by check mark  whether the  registrant  is a shell  company (as defined in Rule 12b-2
of the Exchange Act).                                                           Yes   |_|   No
|X|

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

                    Class                                Outstanding at October 31, 2005
         --------------------------                      -------------------------------
         Common Stock, no par value                                325,811,206

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


Page

EDISON INTERNATIONAL

INDEX
                                                                                 Page
                                                                                  No.
                                                                                 ----

Part I.Financial Information:

 Item 1.        Financial Statements:

                Consolidated Statements of Income - Three and Nine Months
                  Ended September 30, 2005 and 2004                               1

                Consolidated Statements of Comprehensive Income -
                  Three and Nine Months Ended September 30, 2005 and 2004         2

                Consolidated Balance Sheets - September 30, 2005
                  and December 31, 2004                                           3

                Consolidated Statements of Cash Flows - Nine Months
                  Ended September 30, 2005 and 2004                               5

                Notes to Consolidated Financial Statements                        7

 Item 2.        Management's Discussion and Analysis of Financial Condition
                  and Results of Operations                                      39

 Item 3.        Quantitative and Qualitative Disclosures About Market Risk       99

 Item 4.        Controls and Procedures                                          99


Part II.  Other Information:

 Item 1.        Legal Proceedings                                               100

 Item 2.        Unregistered Sales of Equity Securities and Use of Proceeds     102

 Item 6.        Exhibits                                                        103

Signature





Page



EDISON INTERNATIONAL
PART I     FINANCIAL INFORMATION
Item 1.    Financial Statements
CONSOLIDATED STATEMENTS OF INCOME

                                                  Three Months Ended         Nine Months Ended
                                                     September 30,            September 30,
----------------------------------------------------------------------------------------------

In millions, except per-share amounts             2005         2004         2005        2004
----------------------------------------------------------------------------------------------
                                                                   (Unaudited)
Electric utility                               $ 3,084       $2,655      $ 7,194     $6,527
Nonutility power generation                        677          509        1,605      1,257
Financial services and other                        22           24           79         85
----------------------------------------------------------------------------------------------
Total operating revenue                          3,783        3,188        8,878      7,869
----------------------------------------------------------------------------------------------
Fuel                                               489          415        1,309      1,027
Purchased power                                    502          915        1,633      2,022
Provisions for regulatory adjustment clauses - net 766          (34)         790        (85)
Other operation and maintenance                    862          787        2,485      2,367
Asset impairment and loss on lease termination      --           35           12        989
Depreciation, decommissioning and amortization     270          232          796        755
Property and other taxes                            51           50          153        148
----------------------------------------------------------------------------------------------
Total operating expenses                         2,940        2,400        7,178      7,223
----------------------------------------------------------------------------------------------
Operating income                                   843          788        1,700        646
Interest and dividend income                        31            3           78         26
Equity in income from partnerships and
  unconsolidated subsidiaries - net                 27           32          136         61
Other nonoperating income                           34            8           70         96
Interest expense - net of amounts capitalized     (198)        (251)        (615)      (741)
Impairment loss on equity method investment        (55)          --          (55)        --
Loss on early extinguishment of debt                --           --          (24)        --
Other nonoperating deductions                      (35)          (8)         (58)       (36)
----------------------------------------------------------------------------------------------
Income from continuing operations before tax
  and minority interest                            647          572        1,232         52
Income tax (benefit)                               129          181          267        (40)
Dividends on utility preferred and preference stock
  not subject to mandatory redemption                7            1           14          4
Minority interest                                   76           76          142        120
----------------------------------------------------------------------------------------------
Income (loss) from continuing operations           435          314          809        (32)
Income from discontinued operations - net of tax    27          499           55        570
----------------------------------------------------------------------------------------------
Income before accounting change                    462          813          864        538
Cumulative effect of accounting change - net of tax --           --           --         (1)
----------------------------------------------------------------------------------------------
Net income                                     $   462       $  813      $   864     $  537
----------------------------------------------------------------------------------------------
Weighted-average shares of common stock outstanding326          326          326        326
Basic earnings (loss) per common share:
Continuing operations                          $  1.33       $ 0.96      $  2.47     $(0.10)
Discontinued operations                           0.08         1.53         0.17       1.75
----------------------------------------------------------------------------------------------
Total                                          $  1.41       $ 2.49      $  2.64     $ 1.65
----------------------------------------------------------------------------------------------
Weighted-average shares, including
   effect of dilutive securities                   332          330          331        330
Diluted earnings (loss) per common share:
Continuing operations                          $  1.31       $ 0.95      $  2.45     $(0.10)
Discontinued operations                           0.08         1.51         0.16       1.73
----------------------------------------------------------------------------------------------

Total                                          $  1.39       $ 2.46      $  2.61     $ 1.63
----------------------------------------------------------------------------------------------
Dividends declared per common share            $  0.25       $ 0.20      $  0.75     $ 0.60

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


Page 1

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                                 Three Months Ended          Nine Months Ended
                                                    September 30,              September 30,
----------------------------------------------------------------------------------------------

In millions                                       2005         2004         2005         2004
----------------------------------------------------------------------------------------------
                                                                   (Unaudited)
Net income                                      $  462        $ 813       $  864       $ 537
Other comprehensive income (loss), net of tax:
   Foreign currency translation adjustments:
    Other foreign current translation
    adjustments - net                                1           33          (1)          26
    Reclassification adjustment for sale of
    investment in an international project          --         (134)          --        (134)
   Unrealized gain (loss) on investments - net      --           (6)          --          11
   Unrealized gains (losses) on cash flow hedges:
    Other unrealized losses on and
      amortization of cash flow hedges - net      (164)          (1)        (218)        (49)
    Reclassification adjustment for gain
      (loss) included in net income                (72)          27          (80)         70
----------------------------------------------------------------------------------------------
Other comprehensive loss                          (235)         (81)        (299)        (76)
----------------------------------------------------------------------------------------------
Comprehensive income                            $  227        $ 732       $  565       $ 461
----------------------------------------------------------------------------------------------


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




Page 2



EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

                                                              September 30,      December 31,
In millions                                                       2005               2004
----------------------------------------------------------------------------------------------
                                                               (Unaudited)
ASSETS
Cash and equivalents                                          $  2,575           $  2,688
Restricted cash                                                     69                 73
Margin and collateral deposits                                     875                108
Receivables, less allowances of $31 and $31 for uncollectible
  accounts at respective dates                                   1,265                846
Accrued unbilled revenue                                           429                320
Fuel inventory                                                      86                 73
Materials and supplies                                             245                231
Accumulated deferred income taxes - net                            680                288
Trading and price risk management assets                           116                 41
Regulatory assets                                                  546                553
Other current assets                                               509                294
----------------------------------------------------------------------------------------------
Total current assets                                             7,395              5,515
----------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision for
  depreciation of $1,412 and $1,311 at respective dates          3,939              3,922
Nuclear decommissioning trusts                                   2,861              2,757
Investments in partnerships and unconsolidated subsidiaries        505                608
Investments in leveraged leases                                  2,461              2,424
Other investments                                                  143                131
----------------------------------------------------------------------------------------------
Total investments and other assets                               9,909              9,842
----------------------------------------------------------------------------------------------
Utility plant, at original cost:
  Transmission and distribution                                 16,329             15,685
  Generation                                                     1,373              1,356
Accumulated provision for depreciation                          (4,667)            (4,506)
Construction work in progress                                      931                789
Nuclear fuel, at amortized cost                                    146                151
----------------------------------------------------------------------------------------------
Total utility plant                                             14,112             13,475
----------------------------------------------------------------------------------------------
Restricted cash                                                     70                155
Regulatory assets                                                2,934              3,285
Other deferred charges                                           1,076                875
----------------------------------------------------------------------------------------------
Total deferred charges                                           4,080              4,315
----------------------------------------------------------------------------------------------
Assets of discontinued operations                                   12                122
----------------------------------------------------------------------------------------------




Total assets                                                  $ 35,508           $ 33,269
----------------------------------------------------------------------------------------------



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


Page 3


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

                                                              September 30,     December 31,
In millions, except share amounts                                 2005              2004
----------------------------------------------------------------------------------------------

                                                               (Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt                                               $     --          $     88
Long-term debt due within one year                                 723               809
Preferred stock to be redeemed within one year                      --                 9
Accounts payable                                                   835               749
Accrued taxes                                                      720               226
Accrued interest                                                   202               233
Counterparty collateral                                            354                --
Customer deposits                                                  181               168
Book overdrafts                                                    271               232
Trading and price risk management liabilities                      597                31
Regulatory liabilities                                           1,263               490
Other current liabilities                                          955             1,002
----------------------------------------------------------------------------------------------
Total current liabilities                                        6,101             4,037
----------------------------------------------------------------------------------------------
Long-term debt                                                   8,953             9,678
----------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net                          5,036             5,233
Accumulated deferred investment tax credits                        133               138
Customer advances and other deferred credits                     1,331             1,109
Power-purchase contracts                                            76               130
Preferred stock subject to mandatory redemption                     --               139
Accumulated provision for pensions and benefits                    592               523
Asset retirement obligations                                     2,268             2,188
Regulatory liabilities                                           3,302             3,356
Other long-term liabilities                                        292               232
----------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                    13,030            13,048
----------------------------------------------------------------------------------------------
Liabilities of discontinued operations                              15                15
----------------------------------------------------------------------------------------------
Total liabilities                                               28,099            26,778
----------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 2, 4 and 9)
Minority interest                                                  314               313
----------------------------------------------------------------------------------------------
Preferred and preference stock of utility
  not subject to mandatory redemption                              729               129
----------------------------------------------------------------------------------------------
Common stock (325,811,206 shares outstanding at each date)       2,004             1,975
Accumulated other comprehensive loss                              (303)               (4)
Retained earnings                                                4,665             4,078
----------------------------------------------------------------------------------------------
Total common shareholders' equity                                6,366             6,049
----------------------------------------------------------------------------------------------



Total liabilities and shareholders' equity                    $ 35,508          $ 33,269
----------------------------------------------------------------------------------------------



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


Page 4



EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                         Nine Months Ended
                                                                           September 30,
----------------------------------------------------------------------------------------------
In millions                                                             2005          2004
----------------------------------------------------------------------------------------------
                                                                           (Unaudited)
Cash flows from operating activities:
Income (loss) from continuing operations,
  after accounting changes, net of tax                              $    809       $   (33)
Adjustments to reconcile to net cash provided by operating activities:
   Cumulative effect of accounting change, net of tax                     --             1
   Depreciation, decommissioning and amortization                        796           755
   Other amortization                                                     81            79
   Minority interest                                                     142           120
   Deferred income taxes and investment tax credits                     (269)         (140)
   Equity in income from partnerships and unconsolidated subsidiaries   (136)          (61)
   Income from leveraged leases                                          (54)          (62)
   Regulatory assets - long-term                                         372           318
   Regulatory liabilities - long-term                                    (92)          (38)
   Loss on early extinguishment of debt                                   24            --
   Impairment losses                                                      67            35
   Levelized rent expense                                               (115)          (59)
   Other assets                                                         (101)          (50)
   Other liabilities                                                     105            50
   Margin and collateral deposits - net of collateral received          (413)          (31)
   Receivables and accrued unbilled revenue                             (580)         (263)
   Inventory, prepayments and other current assets                      (397)           22
   Regulatory assets - short-term                                          7        (1,050)
   Regulatory liabilities - short-term                                   773           698
   Accrued interest and taxes                                            477             9
   Accounts payable and other current liabilities                        144           273
   Distributions and dividends from unconsolidated entities               40            56
----------------------------------------------------------------------------------------------
Net cash provided by operating activities                              1,680           629
----------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued and issuance costs                               1,143         3,358
Long-term debt repaid                                                 (1,883)       (2,548)
Bonds remarketed - net                                                    --           350
Issuance of preference stock                                             592            --
Redemption of preferred securities                                      (148)           (2)
Rate reduction notes repaid                                             (177)         (177)
Change in book overdrafts                                                 39          (189)
Short-term debt financing - net                                          (88)         (263)
Shares purchased for stock-based compensation                           (145)          (48)
Proceeds from stock option exercises                                      78            32
Dividends to minority shareholders                                      (122)          (90)
Dividends paid                                                          (244)         (195)
----------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities                    $   (955)       $  228
----------------------------------------------------------------------------------------------

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


Page 5



EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                         Nine Months Ended
                                                                           September 30,
----------------------------------------------------------------------------------------------
In millions                                                             2005          2004
----------------------------------------------------------------------------------------------
                                                                            (Unaudited)
Cash flows from investing activities:
Capital expenditures                                                $ (1,337)      $(1,161)
Acquisition costs related to nonutility generation plant                  --          (285)
Proceeds from sale of property and interests in projects                  --           118
Proceeds from sale of discontinued operations                            124           739
Contributions to and earnings from nuclear decommissioning trusts - net  (76)          (62)
Distributions from partnerships and unconsolidated subsidiaries           92            16
Sales of short-term investments - net                                    140            20
Restricted cash                                                           84            57
Customer advances for construction and other investments                  82            (4)
----------------------------------------------------------------------------------------------
Net cash used by investing activities                                   (891)         (562)
----------------------------------------------------------------------------------------------
Effect of consolidation of variable interest entities on cash              3            79
----------------------------------------------------------------------------------------------
Effect of deconsolidation of variable interest entities on cash          --            (32)
----------------------------------------------------------------------------------------------
Net changes in cash of discontinued operations                            52            51
----------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash                                   (1)           --
----------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents                         (112)          393
Cash and equivalents, beginning of period                              2,689         2,178
----------------------------------------------------------------------------------------------
Cash and equivalents, end of period                                    2,577         2,571
Cash and equivalents, discontinued operations                             (2)         (137)
----------------------------------------------------------------------------------------------
Cash and equivalents, continuing operations                         $  2,575       $ 2,434
----------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:

Cash payments for interest and taxes
Cash payments for interest - net of amounts capitalized             $    576       $   696
Cash payments for taxes                                                   62             8

Non-cash investing and financing activities
Details of debt exchanges:
   Pollution-control bonds redeemed                                 $   (452)           --
   Pollution-control bonds issued                                        452            --

Dividends declared but not paid                                     $     81       $    65

Details of consolidation of variable interest entities:
   Assets                                                                 --       $   625
   Liabilities                                                            --          (704)

Details of deconsolidation of variable interest entities:
   Assets                                                                 --       $  (133)
   Liabilities                                                            --           165

Reoffering of pollution-control bonds                                     --       $   196

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

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



Page 6



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management's Statement

In the opinion of management, all adjustments, including recurring accruals, have been made
that are necessary for a fair presentation of the financial position, results of operations
and cash flows in accordance with accounting principles generally accepted in the United
States for the periods covered by this report.  The results of operations for the period
ended September 30, 2005 are not necessarily indicative of the operating results for the
full year.

This quarterly report should be read in conjunction with Edison International's Annual
Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and
Exchange Commission.

Note 1.  Summary of Significant Accounting Policies

Basis of Presentation

Edison International's significant accounting policies were described in Note 1 of "Notes to
Consolidated Financial Statements" included in its 2004 Annual Report.  Edison International
follows the same accounting policies for interim reporting purposes.

Certain prior-period amounts were reclassified to conform to the September 30, 2005
financial statement presentation.  Except as indicated, amounts presented in the Notes to
the Consolidated Financial Statements relate to continuing operations.

Counterparty Collateral

Counterparty collateral includes cash received related to financial gas trading activities.

Earnings Per Common Share (EPS)

In March 2004, the Financial Accounting Standards Board (FASB) issued new accounting
guidance for the effect of participating securities on EPS calculations and the use of the
two-class method.  The new guidance, which was effective in second quarter 2004, requires
the use of the two-class method of computing EPS for companies with participating
securities.  The two-class method is an earnings allocations formula that determines EPS for
each class of common stock and participating security.  Edison International has
participating securities (vested stock options that earn dividend equivalents on an equal
basis with common shares), but determined that the effect on 2004 EPS was immaterial.

Basic EPS is computed by dividing net income available for common stock by the
weighted-average number of common shares outstanding.  Net income (loss) available for
common stock was $459 million and $813 million for the three months ended September 30,
2005, and 2004, respectively, and was $859 million and $537 million for the nine months
ended September 30, 2005, and 2004, respectively.  In arriving at net income, dividends on
preferred securities and preferred stock have been deducted.

For the diluted EPS calculation, dilutive securities (stock-based compensation awards
exercisable) are added to the weighted-average shares.  However, in periods of net loss,
dilutive securities are not added to the weighted-average shares due to their antidilutive
effect.


Page 7

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Income Taxes

Edison International's effective tax rates were 23% and 25% for the three- and nine-month
periods ended September 30, 2005, respectively, as compared to 37% and 55% for the same
periods in 2004.  The decreased effective tax rates resulted primarily from recording a $65
million benefit, including $57 million of interest income, in the third quarter of 2005
related to a settlement reached with the Internal Revenue Service (IRS) on tax issues and
pending affirmative claims relating to Edison International's 1991-1993 tax years.
Additional decreases to the effective rates resulted from reductions made to accrued tax
liabilities in 2005 to reflect progress made in settlement negotiations related to tax
audits other than the 1991-1993 tax years, changes in property-related flow-through items at
SCE and adjustments made to tax balances in 2005 at MEHC and SCE.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as
credit support under margining agreements for power and gas trading activities.  The amount
of margin and collateral deposits generally varies based on changes in the value of the
agreements.  Deposits with counterparties and brokers generally earn interest at various
rates.

New Accounting Principles

In March 2005, the FASB issued an interpretation related to accounting for conditional asset
retirement obligations (AROs).  This Interpretation clarifies that an entity is required to
recognize a liability for the fair value of a conditional ARO if the fair value can be
reasonably estimated even though uncertainty exists about the timing and/or method of
settlement.  This Interpretation is effective December 31, 2005.  Thus far, Edison
International has identified conditional AROs related to:  treated wood poles, hazardous
materials such as mercury and polychlorinated biphenyls-containing equipment; and asbestos
removal costs at buildings, operating stations and retired units.  Additional assessment is
necessary to value these AROs.  However, since SCE follows accounting principles for
rate-regulated enterprises and receives recovery of these costs through rates,
implementation of this interpretation at SCE will not affect Edison International's
earnings.  Implementation of this interpretation at Edison Mission Energy (EME) is expected
to have a minimal impact on Edison International's earnings.

A new accounting standard requires companies to use the fair value accounting method for
stock-based compensation.  Edison International currently uses the intrinsic value
accounting method for stock-based compensation.  On April 14, 2005, the Securities and
Exchange Commission announced a delay in the effective date for the new standard to fiscal
years beginning after June 15, 2005.  Edison International will implement the new standard
effective January 1, 2006 by applying the modified prospective transition method.  The
difference in expense between the two accounting methods related to stock options granted is
shown below under "Stock-Based Compensation."  Edison International is assessing the impact
of this accounting standard on its performance shares.

The American Jobs Creation Act of 2004 included a tax deduction on qualified production
activities income (including income from the sale of electricity).  In December 2004, the
FASB issued guidance that this deduction should be accounted for as a special deduction,
rather than a tax rate reduction.  Accordingly, the special deduction is recorded in the
year it is earned.  In October 2005, the IRS issued proposed regulations for this tax
deduction.  The tax deduction is not expected to materially affect Edison International's
2005 financial statements.  Edison International is evaluating the effect that the
manufacturer's deduction will have in subsequent years.


Page 8


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


In March 2004, the FASB issued new accounting guidance for the effect of participating
securities on EPS calculations and the use of the two-class method.  The new guidance, which
was effective in second quarter 2004, requires the use of the two-class method of computing
EPS for companies with participating securities (including vested stock options with
dividend equivalents).  See "Earnings Per Common Share" above.

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

On March 31, 2004, SCE consolidated four power projects partially owned by EME, EME
deconsolidated two power projects, and Edison Capital consolidated two affordable housing
partnerships and three wind projects.  Edison International recorded a cumulative effect
adjustment that decreased net income by less than $1 million, net of tax, due to negative
equity at one of Edison Capital's newly consolidated entities.


Page 9



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:

                                                               September 30, December 31,
    In millions                                                    2005          2004
-----------------------------------------------------------------------------------------

                                                                (Unaudited)
    Current
    Regulatory balancing accounts                              $    348       $   371
    Direct access procurement charges                               112           109
    Purchased-power settlements                                      57            62
    Other                                                            29            11
-----------------------------------------------------------------------------------------
                                                                    546           553
-----------------------------------------------------------------------------------------
    Long-term
    Flow-through taxes - net                                      1,008         1,018
    Rate reduction notes - transition cost deferral                 520           739
    Unamortized nuclear investment - net                            493           526
    Nuclear-related ARO investment - net                            261           272
    Unamortized coal plant investment - net                          81            78
    Unamortized loss on reacquired debt                             328           250
    Direct access procurement charges                                63           141
    Environmental remediation                                        55            55
    Purchased-power settlements                                      50            91
    Other                                                            75           115
-----------------------------------------------------------------------------------------
                                                                  2,934         3,285
-----------------------------------------------------------------------------------------
    Total regulatory assets                                    $  3,480       $ 3,838
-----------------------------------------------------------------------------------------



Page 10


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Regulatory liabilities included in the consolidated balance sheets are:

                                                               September 30, December 31,
    In millions                                                    2005          2004
-----------------------------------------------------------------------------------------
                                                                (Unaudited)
    Current
    Regulatory balancing accounts                              $    680       $   357
    Direct access procurement charges                               112           109
    Energy derivatives                                              398            --
    Other                                                            73            24
-----------------------------------------------------------------------------------------
                                                                  1,263           490
-----------------------------------------------------------------------------------------
    Long-term
    ARO                                                             806           819
    Costs of removal                                              2,151         2,112
    Direct access procurement charges                                63           141
    Employee benefits plans                                         235           200
    Energy derivatives                                               47            --
    Other                                                            --            84
-----------------------------------------------------------------------------------------
                                                                  3,302         3,356
-----------------------------------------------------------------------------------------

    Total regulatory liabilities                               $  4,565       $ 3,846
-----------------------------------------------------------------------------------------

SCE's regulatory liabilities related to energy derivatives are an offset to unrealized gains
on recorded derivatives.

Stock-Based Compensation

Edison International has three stock-based compensation plans, which are described more
fully in Note 7 of "Notes to Consolidated Financial Statements" included in its 2004 Annual
Report.  Edison International accounts for these plans using the intrinsic value method.
Upon grant, no stock-based compensation cost is reflected in net income, as all options
granted under those plans had an exercise price equal to the market value of the underlying
common stock on the date of grant.  The following table illustrates the effect on net income
and EPS if Edison International had used the fair-value accounting method for stock options
granted.


Page 11


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                      Three Months Ended    Nine Months Ended
                                                         September 30,         September 30,
----------------------------------------------------------------------------------------------
    In millions, except per-share amounts             2005         2004      2005       2004
----------------------------------------------------------------------------------------------
                                                                      (Unaudited)
    Net income, as reported                         $  462       $  813    $   864    $  537
    Add:  stock-based compensation expense using
      the intrinsic value accounting method -
      net of tax                                        18            3         44        11
    Less:  stock-based compensation expense using
      the fair-value accounting method - net of tax     20            3         51        10
----------------------------------------------------------------------------------------------
    Pro forma net income                            $  460       $  813    $   857    $  538
----------------------------------------------------------------------------------------------
    Basic earnings per common share:
      As reported                                   $ 1.41       $ 2.49    $   2.64   $  1.65
      Pro forma                                     $ 1.40       $ 2.49    $   2.61   $  1.65

    Diluted earnings per common share:
      As reported                                   $ 1.39       $ 2.46    $   2.61   $  1.63
      Pro forma                                     $ 1.38       $ 2.46    $   2.57   $  1.63
----------------------------------------------------------------------------------------------


Supplemental Accumulated Other Comprehensive Loss Information

Supplemental information regarding Edison International's accumulated other comprehensive
loss, including discontinued operations, is:

                                                               September 30,   December 31,
    In millions                                                    2005            2004
--------------------------------------------------------------------------------------------
                                                                (Unaudited)
    Foreign currency translation adjustments                     $    1           $  --
    Minimum pension liability - net                                 (16)            (15)
    Unrealized gains (losses) on cash flow hedges - net            (288)             11
--------------------------------------------------------------------------------------------
    Accumulated other comprehensive loss                         $ (303)          $  (4)
--------------------------------------------------------------------------------------------

The minimum pension liability is discussed in Note 7, Compensation and Benefit Plans of
"Notes to Consolidated Financial Statements" included in Edison International's 2004 Annual
Report.

Included in Edison International's accumulated other comprehensive loss at September 30,
2005, was a $283 million loss related to EME's net unrealized losses on cash flow hedges and
a $5 million loss related to SCE's interest rate swap (see discussion below).

Unrealized losses on cash flow hedges at September 30, 2005, include unrealized losses on
commodity hedges primarily related to EME's Midwest Generation and Homer City futures and
forward electricity contracts that qualify for hedge accounting.  These losses arise because
current forecasts of future electricity prices in these markets are greater than contract
prices.  The increase in the unrealized losses during the third quarter of 2005 resulted
from a combination of new hedges for 2006 and 2007 and an increase in market prices for
power driven largely from higher natural gas and oil prices.  In addition, at September 30,
2005, EME reclassified a $9 million, after tax, unrealized gain from other comprehensive
loss to earnings due to the impairment of its equity investment in the March Point project.


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Unrealized losses on cash flow hedges also included those related to SCE's interest rate
swap (the swap terminated on January 5, 2001, but the related debt matures in 2008).  The
unamortized loss of $5 million (as of September 30, 2005, net of tax) on the interest rate
swap will be amortized over a period ending in 2008.  Approximately $2 million, after tax,
of the unamortized loss on this swap will be reclassified into earnings during the next
12 months.  Amortized losses are recoverable through SCE's annual cost of capital proceeding.

As EME's hedged positions for continuing operations are realized, approximately
$257 million, after tax, of the net unrealized losses on cash flow hedges at September 30,
2005 are expected to be reclassified into earnings during the next 12 months. EME expects
that reclassification of net unrealized losses will offset energy revenue recognized at
market prices. Actual amounts ultimately reclassified into earnings over the next 12 months
could vary materially from this estimated amount as a result of changes in market
conditions. The maximum period over which a cash flow hedge is designated is through
December 31, 2007.

EME recorded net losses of approximately $32 million and $13 million during the third
quarter of 2005 and 2004, respectively, and $35 million and $9 million during the nine
months ended September 30, 2005 and 2004, respectively, which represented the amount of cash
flow hedges' ineffectiveness for continuing operations; these amounts are reflected in
nonutility power generation revenue in the consolidated income statements.

Note 2.  Regulatory Contingencies

Further information on these regulatory contingencies is described in Note 2 of "Notes to
Consolidated Financial Statements" included in Edison International's 2004 Annual Report.
See Note 4 for additional contingencies.

California Department of Water Resources (CDWR) Power Purchases and Revenue Requirement
Proceedings

As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in
Note 2 of "Notes to Consolidated Financial Statements" included in Edison International's
2004 Annual Report, in December 2004, the California Public Utilities Commission (CPUC)
issued its decision on how the CDWR's power charge revenue requirement for 2004 through 2013
would be allocated among the investor-owned utilities.  On June 30, 2005, the CPUC granted,
in part, San Diego Gas & Electric's (SDG&E) petition for modification of the December 2004
decision.  The June 30, 2005 decision adopted a methodology that retains the
cost-follows-contract allocation of the avoidable costs, and allocates the unavoidable costs
associated with the contracts:  42.2% to Pacific Gas and Electric's (PG&E) customers, 47.5%
to SCE's customers and 10.3% to SDG&E's customers.  This newly adopted allocation
methodology decreases the total costs allocated to SDG&E's customers and increases the total
costs allocated to SCE's and PG&E's customers, relative to the December 2004 decision.

The burden of the additional costs, relative to the December 2004 decision, is borne almost
entirely by SCE's customers for the period 2004-2009, and then shifts almost entirely to
PG&E's customers in 2010-2011, when contract deliveries of the CDWR energy to PG&E's
customers falls by approximately 75%.  SCE, joined by The Utility Reform Network and the
California Large Electricity Consumers Association, filed a petition for modification of the
June 30, 2005 decision, seeking to levelize the allocation of additional costs under the
decision to SCE's and PG&E's customers and requesting


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


clarification on other implementation issues.  On November 2, 2005, the CPUC issued a
proposed decision denying the petition for modification.  The final decision is expected in
December 2005.

The CDWR has submitted its 2006 revenue requirement determination to the CPUC for
implementation.  The CPUC must issue its final decision implementing the 2006 CDWR revenue
requirement in December 2005.  The November 2, 2005 proposed decision mentioned above also
implements the CDWR's 2006 revenue requirement.  A final decision is expected in December
2005.

Amounts billed to SCE's customers for electric power purchased and sold by the CDWR are
remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no
impact on SCE's earnings.

Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms

Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain
shareholder incentives for its performance achievements in delivering demand-side management and energy
efficiency programs.  On June 10, 2005, SCE and the ORA executed a settlement agreement for SCE's outstanding
issues concerning SCE shareholder incentives and performance achievements resulting from the demand-side
management, energy efficiency, and low-income energy efficiency programs from program years 1994-2004.  In
addition, the settlement addresses shareholder incentives and performance achievements for program years
1994-1998, anticipated but not yet claimed.  The settlement agreement recommends, among other things, that SCE
be entitled to immediately recover 92% of the total of SCE's current claims and future claims related to
SCE's pre-1998 energy efficiency programs.  SCE's total claim for program years 1994-2004 made in 2000 through
2008, including interest, franchise fees and uncollectibles, is approximately $46 million.  On October 27,
2005, the CPUC approved the settlement agreement which found it reasonable for SCE to recover approximately
$42 million of these claims which include all of SCE's outstanding claims, as well as future claims related
to SCE's pre-1998 energy efficiency programs (of which approximately $9 million has already been collected in
rates).  The remaining portion of claims in the amount of $33 million will be recognized in the fourth
quarter of 2005. As a result of the decision, during the third quarter of 2005, SCE
recognized $14 million of incentives previously awarded for which revenue recognition was deferred pending
final resolution of these matters.  The $14 million is reflected in the income statement caption "Other
nonoperating income."  In addition, $4 million related to interest on the claims was reflected in the caption
"Interest and dividend income."


Energy Resource Recovery Account (ERRA) Proceedings

In an October 2002 decision, the CPUC established the Energy Resource Recovery Account
(ERRA) as the rate-making mechanism to track and recover SCE's:  (1) fuel costs related to
its generating stations; (2) purchased-power costs related to cogeneration and renewable
contracts; (3) purchased-power costs related to existing interutility and bilateral
contracts that were entered into before January 17, 2001; and (4) new procurement-related
costs incurred on or after January 1, 2003 (the date on which the CPUC transferred back to
SCE the responsibility for procuring energy resources for its customers).  SCE recovers
these costs on a cost-recovery basis, with no markup for return or profit.  SCE files annual
forecasts of the above-described costs that it expects to incur during the following year.
As these costs are subsequently incurred, they will be tracked and recovered through the
ERRA, but are subject to a reasonableness review in a separate annual ERRA application.  If
the ERRA overcollection or


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


undercollection exceeds 5% of SCE's prior year's generation revenue, the CPUC has
established a "trigger" mechanism, whereby SCE can request an emergency rate adjustment in
addition to the annual forecast and reasonableness ERRA applications.

ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004

On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its
procurement-related costs for calendar year 2004 to be reasonable, and that its contract
administration and economic dispatch operations during 2004 complied with its CPUC-adopted
procurement plan.  In addition, SCE requested recovery of approximately $13 million
associated with Nuclear Unit Incentive Procedure rewards for efficient operation of the Palo
Verde Nuclear Generating Station (Palo Verde) and approximately $7 million in administrative
and general costs incurred to carry out the CPUC's directive to begin procuring energy
supplies on January 1, 2003 following the California energy crisis.  In August 2005, the ORA
recommended a $16 million disallowance associated with SCE's 2004 sales of energy in the
hour-ahead market, alleging that the price at which SCE sold its hour-ahead energy was
unreasonable.  SCE submitted its rebuttal testimony on September 15, 2005, contesting the
ORA's recommendation.  In addition, in its opening briefs, the ORA recommended that SCE be
penalized $37 million for allegedly having failed to prove that its least-cost dispatch
operations complied with the methodology presented by the ORA.  SCE believes the
disallowance and recommended penalty are without merit.  A decision is expected by the end
of 2005.

Generation Procurement Proceedings

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

Procurement Plan

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

Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's
procurement-related transactions associated with serving the demands of its bundled
electricity customers were in conformance with SCE's adopted short-term procurement plan.
SCE has submitted quarterly compliance filings covering the period from January 1, 2003
through September 30, 2005.  The CPUC issued one resolution approving SCE's first compliance
report for the period January 1, 2003 to March 31, 2003 and issued a resolution approving
the other transactions for calendar year 2003 in a June 16, 2005 resolution.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Resource Adequacy Requirements

Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving
entities in California have an obligation to procure sufficient resources to meet their
customers' needs.  On October 27, 2005, the CPUC issued a decision clarifying the January
2004 decision and a subsequent October 2004 decision on resource adequacy requirement.  The
October 2005 decision requires load-serving entities to ensure that adequate resources have
been contracted to meet that entity's peak forecasted energy resource demand and an
additional planning reserve margin of 15-17% in every month of the year, beginning in June
2006.  The October 2005 decision requires that SCE demonstrate that it has contracted 90% of
its June-September 2006 resource adequacy requirement by January 2006.  By the end of May
2006, SCE will be required to fill out the remaining 10% of its resource adequacy
requirement one month in advance of expected need.  A month-ahead showing demonstrating that
SCE has procured 100% of its resource adequacy requirement will be required every month
thereafter.  The October 2005 decision also adopted limits on the amount of a
portfolio-sourced, as opposed to a unit-specific, firm energy contract that can be used to
meet a load serving entity's resource adequacy requirement.  Under the October 2005
decision, a load-serving entity can have no more than 75% of its portfolio of resource
adequacy resources met by such contracts in 2006, no more than 50% met by such contracts in
2007, and no more than 25% met by such contracts in 2008.  No such contracts can be used to
meet a load-serving entities' resource adequacy requirement after December 31, 2008.  The
October 2005 decision also clarified that the CDWR contracts, some of which are firm energy
contracts, are not subject to the limitations.  Additionally, the October 2005 decision
adopted minimum elements for contracts upon which load-serving entities' may rely on to meet
their resource adequacy obligations.  Further, the October 2005 decision deferred
implementation of a local resource adequacy requirement until 2007.  Lastly, the October
2005 decision adopted penalties of 150% of the cost of new monthly capacity for load serving
entities that fail to acquire sufficient resources in 2006, and a 300% penalty in 2007 and
beyond.  SCE expects to meet its resource adequacy requirements by the deadlines set forth
in the decision.

In July 2005, SCE issued a Request for Offers (RFO) whereby SCE solicited offers from
sellers in the ISO control area for products that provide capacity, energy and resource
adequacy benefits.  In early October, SCE executed a number of contracts for these products
for terms up to 56 months.

Procurement of Renewable Resources

SCE's 2005 renewable procurement plan for 2005 through 2014 was filed on March 7, 2005.  On
July 21, 2005, the CPUC issued a decision approving SCE's renewable procurement plan for
2005 and deferred a ruling on SCE's renewable procurement plan for 2006 through 2014.  This
decision also approved the methodology advocated by SCE for determining the amount by which
reported renewable procurement should be adjusted to reflect line losses.  On October 6,
2005, the CPUC issued a decision conditionally approving SCE's renewable procurement plan
for 2006 through 2014.

The CPUC's July 21, 2005 decision referenced above states that SCE cannot count procurement
from certain geothermal facilities towards its 1% annual renewable procurement requirement,
unless such procurement is from production certified as "incremental" by the California
Energy Commission.  A 2003 CPUC decision had held that SCE could count procurement from
these geothermal facilities toward its 1% annual renewable procurement requirement.  SCE is
currently pursuing reconsideration of the July 21, 2005 decision.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The geothermal facilities have applied to the California Energy Commission for certification
of a portion of the facilities' production as "incremental."  A decision from the California
Energy Commission is expected in November 2005.  It is not clear whether any of the
facilities' production will be certified as "incremental" or how much, if any, of the
"incremental" production from the facilities will be allocated to SCE's procurement under its
contract with the facilities if the California Energy Commission certification is granted.

Depending upon the amount, if any, of California Energy Commission certified "incremental"
production allocated to SCE's procurement under its contract and the manner in which the
CPUC implements its flexible rules for compliance with renewable procurement obligations,
the CPUC could deem SCE to be out of compliance with its statutory renewable procurement
obligations for the years 2003, 2004 and 2005, and therefore SCE could be subject to
penalties for those years.  In addition, the California Energy Commission's and the CPUC's
treatment of the production from the geothermal facilities could result in SCE being deemed
to be out of compliance with its obligations for 2006.  The maximum penalty for
noncompliance is $25 million per year.  To comply with renewable procurement mandates and
avoid penalties for years beyond 2006, SCE will either need to sign new contracts and/or
extend existing renewable qualifying facility contracts.

SCE received bids for renewable resource contracts in response to a solicitation it made in
August 2003 and conducted negotiations with bidders regarding potential procurement
contracts.  On June 30, 2005, the CPUC issued a resolution approving six renewable contracts
resulting from the solicitation.  On August 11, 2005 and August 31, 2005, SCE submitted
advice letters seeking CPUC approval of two additional renewable contracts resulting from
the solicitation.

The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new request
for proposals for additional renewable contracts.  SCE issued its 2005 request for proposals
for renewable contracts on September 2, 2005.  Proposals for renewable contracts have been
received and are being evaluated.

Request for Offers for New Generation Resources

According to California state agencies, beginning in 2006, there is a need for new
generation capacity in southern California.  SCE has issued an RFO for new generation
resources.  SCE solicited offers for power-purchase agreements lasting up to 10 years from
new generation facilities with delivery under the agreement beginning between June 1, 2006
and August 1, 2008.  SCE filed an application with the CPUC seeking approval of the RFO and
the power-purchase agreements executed under the RFO.  SCE sought recovery of the costs of
the contracts, through the Federal Energy Regulatory Commission (FERC)-jurisdictional rates,
from all affected customers.  In addition, SCE sought CPUC assurance of full cost recovery
in CPUC-approved rates, if the FERC denies any recovery.  On September 9, 2005, the CPUC
issued a scoping memorandum rejecting SCE's proposal.  Since the scoping memorandum did not
provide a mechanism for SCE to secure new generation on behalf of these customers, SCE
terminated its RFO and moved to stay the proceeding and withdraw the CPUC application.  A
stay was granted on September 22, 2005.  The motion to withdraw is still pending.

Holding Company Proceeding and Order Instituting Rulemaking (OIR)

In April 2001, the CPUC issued an order instituting investigation that reopened the past
CPUC decisions authorizing utilities to form holding companies and initiated an
investigation into, among other things:  (1) whether the holding companies violated CPUC
requirements to give first priority to the capital needs


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


of their respective utility subsidiaries; (2) any additional suspected violations of laws or
CPUC rules and decisions; and (3) whether additional rules, conditions, or other changes to
the holding company decisions are necessary.  For a discussion of item (1) above, see the
"Holding Company Proceeding" disclosure in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report.

On May 5, 2005, the CPUC issued a final decision that closed the proceeding.  However,
because the CPUC closed the proceeding without addressing some of the issues the proceeding
raised (such as the appropriateness of the large utilities' holding company structure and
dividend policies), the CPUC may rule on or investigate these issues in the future.

On October 27, 2005, the CPUC issued an OIR to allow the CPUC to re-examine the
relationships of the major California energy utilities with their parent holding companies
and nonregulated affiliates.  The OIR was issued in part in response to the recent repeal of
the Public Utility Holding Company Act of 1935.

By means of the OIR, the CPUC will consider whether additional rules to supplement existing
rules and requirements governing relationships between the public utilities and their
holding companies and nonregulated affiliates should be adopted.  Any additional rules will
focus on whether (1) the public utilities retain enough capital or access to capital to meet
their customers' infrastructure needs and (2) mitigation of potential conflicts between
ratepayer interests and the interests of holding companies and affiliates that could
undermine the public utilities' ability to meet their public service obligations at the
lowest cost.  The CPUC expects to issue proposed rules in January 2006, and a final decision
is expected in March 2006.

California Independent System Operator (ISO) Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the
Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper
allocation and characterization of certain charges.  The order reversed an arbitrator's
award that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal
Congestion costs and allocation of those charges to Scheduling Coordinators (SCs) in the
affected zone within the ISO transmission grid.  The April 20, 2004 order directed the ISO
to shift the costs from SCs in the affected zone to the responsible Participating
Transmission Owner, SCE, and to do so within 60 days of the April 20, 2004 order.  Under the
April 20, 2004 order, which was stayed pending resolution of SCE's rehearing request, SCE
would be charged a certain amount as the Participating Transmission Owner but also would be
credited in its role as an SC and through the California Power Exchange, to the extent it
acted as SCE's SC.  On March 30, 2005, the FERC issued an Order Denying Rehearing.  SCE
obtained an extension of the stay pending resolution of the appeal SCE has filed with the
Court of Appeals for the D.C. Circuit.  A briefing schedule has been set in the appeal with
SCE's opening brief due on December 23, 2005.  The potential net impact on SCE is estimated
to be approximately $20 million to $25 million, including interest.  SCE filed a request for
clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the
disputed costs in SCE's reliability services rates.  On June 8, 2005, the FERC denied the
clarification, noting that during the appeal, the FERC's order is stayed; and therefore SCE
is not required to pay at this time.  SCE may seek recovery in its reliability service rates
of the costs should SCE be required to pay these costs.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Mohave Generating Station and Related Proceedings

As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2
of "Notes to Consolidated Financial Statements" included in Edison International's 2004
Annual Report, the CPUC issued a final decision in December 2004 on SCE's application
regarding the post-2005 operation of Mohave, which is partly owned by SCE.

In parallel with and since the conclusion of the CPUC proceeding, negotiations, water
studies and other efforts have continued among the relevant parties in an attempt to resolve
Mohave's post-2005 coal and water supply issues.  Although progress has been made with
respect to certain issues, no complete resolution has been reached to date.  Because
resolution has not been reached and because of the lead times required for installation of
certain pollution-control equipment and other upgrades necessary for post-2005 operation, it
appears probable that Mohave will temporarily shut down at the end of 2005, and a permanent
shutdown remains possible.  The outcome of the efforts to resolve the post-2005 coal and
water supply issues is not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's
long-term resource plan.  SCE's 2006 ERRA forecast application assumes Mohave is an
unavailable resource for power for 2006.  Because SCE expects to recover Mohave shut-down
costs in future rates, the outcome of this matter is not expected to have a material impact
on earnings.

For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.

System Reliability Incentive Mechanism

SCE's 2003 General Rate Case (GRC) decision provided for performance incentives or penalties
for differences between SCE's actual results and CPUC-authorized standards for system
reliability measures beginning in 2004.  In a March 30, 2005 advice letter, SCE reported a
$2 million penalty and recorded an accrual in 2004 for its 2004 results under the modified
reliability mechanism.  On April 28, 2005, the CPUC agreed to suspend its review of SCE's
advice letter for 2004 results until the CPUC's Consumer Protection and Safety Division
(CPSD) has completed its investigation regarding performance incentive rewards discussed in
Note 4.  Based on preliminary recorded data through September 2005 and a forecast of normal
results through December 2005, SCE projects it will incur a penalty of $26 million under the
reliability performance mechanism for 2005.  The maximum penalty that could be assessed
under the reliability performance mechanism is approximately $40 million.  As a result,
during the third quarter of 2005, SCE recorded an accrual of $26 million that is reflected
in the income statement caption "Other nonoperating deductions."

Transmission Proceeding

In August and November 2002, the FERC issued opinions affirming a September 1999
administrative law judge decision to disallow, among other things, recovery by SCE and the
other California public utilities of costs reflected in network transmission rates
associated with ancillary services and losses incurred by the utilities in administering
existing wholesale transmission contracts after implementation of the restructured
California electric industry.  SCE has incurred approximately $80 million of these
unrecovered costs since 1998.  In addition, SCE has accrued interest on these unrecovered
costs.  The three California utilities appealed the decisions to the Court of Appeals for
the Federal Circuit.  On July 12, 2005, the Court of Appeals for the Federal Circuit vacated
the FERC's August and November 2002 orders, and remanded the case to the FERC for further
proceedings.  SCE believes that the Court of Appeals for the Federal Circuit's decision
increases the likelihood that it will recover these costs.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Wholesale Electricity and Natural Gas Markets

As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in Note 2 of
"Notes to Consolidated Financial Statements" included in Edison International's 2004 Annual
Report, SCE is participating in several related proceedings seeking recovery of refunds from
sellers of electricity and natural gas who allegedly manipulated the electric and natural
gas markets.

El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of
parties (including SCE, PG&E, the State of California and various consumer class action
representatives) settling various claims stated in proceedings at the FERC and in San Diego
County Superior Court that El Paso had manipulated interstate capacity and engaged in other
anticompetitive behavior in the natural gas markets in order to unlawfully raise gas prices
at the California border in 2000-2001.  The United States District Court has issued an order
approving the stipulated judgment and the settlement agreement has become effective.
Pursuant to a CPUC decision, SCE was required to refund to customers amounts received under
the terms of the El Paso settlement (net of legal and consulting costs) through its ERRA
mechanism.  In June 2004, SCE received its first settlement payment of $76 million.
Approximately $66 million of this amount was credited to purchased-power expense, and was
refunded to SCE's ratepayers through the ERRA over the following twelve months, and the
remaining $10 million was used to offset SCE's incurred legal costs.  El Paso has elected to
prepay the additional settlement payments due over a 20-year period and, as a result, SCE
received $66 million in May 2005.  Amounts El Paso refunds to the CDWR will result in
reductions in the CDWR's revenue requirement allocated to SCE in proportion to SCE's share
of the CDWR's power charge revenue requirement.

On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement
terms with Mirant Corporation and a number of its affiliates (collectively Mirant), all of
whom are debtors in Chapter 11 bankruptcy proceedings pending in Texas.  Among other things,
the settlement terms provide for cash and equivalent refunds totaling $320 million, of which
SCE's allocated share is approximately $68 million.  The settlement also provides for an
allowed, unsecured claim totaling $175 million in the bankruptcy of one of the Mirant
parties, with SCE being allocated approximately $33 million of the unsecured claim.  The
actual value of the unsecured claim will be determined as part of the resolution of the
Mirant parties' bankruptcies.  The Mirant settlement was approved by the FERC on April 13,
2005 and by the bankruptcy court on April 15, 2005.  In April and May 2005, SCE received its
allocated $68 million in cash settlement proceeds.  SCE continues to hold its $33 million
share of the allowed, unsecured bankruptcy claim.  The Mirant settlement will be refunded to
ratepayers as described below.

On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement
terms with Enron Corporation and a number of its affiliates (collectively Enron), most of
which are debtors in Chapter 11 bankruptcy proceedings pending in New York.  Among other
things, the settlement terms provide for cash and equivalent payments from Enron totaling
approximately $47 million and an allowed, unsecured claim in the bankruptcy against one of
the Enron entities in the amount of $875 million.  SCE's allocable share of both the cash
and allowed claim portions of the settlement consideration has not yet been finally
determined, and the value of an allocable share of the allowed claim will be determined as
part of the resolution of the Enron parties' bankruptcies.  The settlement was approved by
the Enron bankruptcy court on October 20, 2005, but remains subject to approval by the
FERC.  Effective August 24, 2005, the CPUC approved the settlement by entering into an
agreement incorporating its terms.  The Enron settlement proceeds will be refunded to
ratepayers as described below.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


On August 12, 2005, SCE, PG&E, SDG&E, several governmental entities and certain other
parties agreed to settlement terms with Reliant Energy, Inc. and a number of its affiliates
(collectively Reliant).  Among other things, the settlement terms provide for Reliant to
provide cash and cash equivalents having a total value of at least $460 million, which would
be in addition to the $65 million in refunds that Reliant was already required to provide
pursuant to FERC orders.  SCE expects that its allocable share of the entire settlement
value of $525 million (including the amounts previously ordered by the FERC) will be
approximately $130 million.  The settlement remains subject to FERC approval, which is
anticipated in the first quarter of 2006.  Effective October 12, 2005, the CPUC approved the
settlement by entering into an agreement incorporating its terms.  The Reliant settlement
proceeds will be refunded to ratepayers as described below.

On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy
Settlement Memorandum Account (ESMA) for the purpose of recording the foregoing settlement
proceeds (excluding the El Paso settlement) from energy providers and allocating them in
accordance with the terms of the October 2001 settlement agreement entered into by SCE and
the CPUC which settled SCE's lawsuit against the CPUC.  This lawsuit sought full recovery of
SCE's electricity procurement costs incurred during the energy crisis.  The resolution
provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will
be allocated to recovery of SCE's litigation costs and expenses in the FERC refund
proceedings described above and a 10% shareholder incentive pursuant to the CPUC litigation
settlement agreement.  Remaining amounts for each settlement are to be refunded to
ratepayers through the ERRA mechanism.  In the second quarter of 2005, SCE recorded a
$7 million increase to other nonoperating income as a shareholder incentive related to the
Mirant refund received during the second quarter of 2005.

Note 3.  Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report that it expects to
contribute approximately $53 million to its pension plans in 2005.  As of September 30,
2005, $15 million in contributions have been made.  Edison International anticipates that
its original expectation will be met by year-end 2005.

Expense components are:
                                                    Three Months Ended       Nine Months Ended
                                                       September 30,           September 30,
----------------------------------------------------------------------------------------------

    In millions                                     2005         2004        2005       2004
----------------------------------------------------------------------------------------------
                                                                    (Unaudited)
    Service cost                                    $ 29       $  26         $  87      $ 79
    Interest cost                                     43          43           129       130
    Expected return on plan assets                   (55)        (59)         (167)     (177)
    Net amortization and deferral                      6           6            20        18
----------------------------------------------------------------------------------------------
    Expense under accounting standards                23          16            69        50
    Regulatory adjustment - deferred                  (2)         --            (6)       --
----------------------------------------------------------------------------------------------
    Total expense recognized                        $ 21        $ 16         $  63      $ 50
----------------------------------------------------------------------------------------------



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Postretirement Benefits Other Than Pensions

Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report that it expects to
contribute approximately $77 million to its postretirement benefits other than pensions
plans in 2005.  As of September 30, 2005, $19 million in contributions have been made.
Edison International anticipates that its original expectation will be met by year-end 2005.

Expense components are:
                                                    Three Months Ended       Nine Months Ended
                                                       September 30,           September 30,
----------------------------------------------------------------------------------------------

    In millions                                     2005        2004          2005      2004
----------------------------------------------------------------------------------------------
                                                                    (Unaudited)
    Service cost                                    $ 12       $   9         $  36      $ 32
    Interest cost                                     31          29            93        96
    Expected return on plan assets                   (26)        (27)          (77)      (82)
    Amortization of unrecognized prior service costs  (7)         (8)          (22)      (24)
    Amortization of unrecognized loss                 12           7            36        38
----------------------------------------------------------------------------------------------
    Total expense                                   $ 22       $  10         $  66      $ 60
----------------------------------------------------------------------------------------------

Note 4.  Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in
other legal, tax and regulatory proceedings before various courts and governmental agencies
regarding matters arising in the ordinary course of business.  Edison International believes
the outcome of these other proceedings will not materially affect its results of operations
or liquidity.

Aircraft Leases

Edison Capital has invested in three aircraft leased to American Airlines.  American has
reported very large operating and net losses due to reduced pricing power, increases in
capacity in excess of demand, deeply discounted fare sales and significant increases in fuel
prices.  In the event American Airlines defaults in making its lease payments, the lenders
with a security interest in the aircraft or leases may exercise remedies that could lead to
a loss of some or all of Edison Capital's investment in the aircraft plus any accrued
interest.  The total maximum loss exposure to Edison Capital in 2005 is $39 million.
A restructuring of the lease could also result in a loss of some or all of the investment.
At September 30, 2005, American Airlines was current in its lease payments to Edison Capital.

Environmental Remediation

Edison International 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.

Edison International believes that it is in substantial compliance with environmental
regulatory requirements; however, possible future developments, such as the enactment of
more stringent environmental laws and regulations, could affect the costs and the manner in
which business is conducted and could cause substantial additional capital expenditures.
There is no assurance that additional costs


Page 22


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


would be recovered from customers or that Edison International's financial position and
results of operations would not be materially affected.

Edison International records its environmental remediation liabilities when site assessments
and/or remedial actions are probable and a range of reasonably likely cleanup costs can be
estimated.  Edison International 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, Edison International records the lower end of
this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.

Edison International's recorded estimated minimum liability to remediate its 29 identified
sites at SCE (22 sites) and EME (7 sites related to Midwest Generation) is $84 million,
$81 million of which is related to SCE.  Edison International's other subsidiaries have no
identified remediation sites.  The ultimate costs to clean up Edison International'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.  Edison
International believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $115 million, all of which is
related to SCE.  The upper limit of this range of costs was estimated using assumptions
least favorable to Edison International among a range of reasonably possible outcomes.  In
addition to its identified sites (sites in which the upper end of the range of costs is at
least $1 million), SCE also has 33 immaterial sites whose total liability ranges from
$4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites,
representing $29 million of its recorded liability, through an incentive mechanism (SCE may
request to include additional sites).  Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties.  SCE has successfully
settled insurance claims with all responsible carriers.  SCE expects to recover costs
incurred at its remaining sites through customer rates.  SCE has recorded a regulatory asset
of $55 million for its estimated minimum environmental-cleanup costs expected to be
recovered through customer rates.

Edison International'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 Edison International 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.

Edison International expects to clean up its identified sites over a period of up to 30
years.  Remediation costs in each of the next several years are expected to range from
$11 million to $25 million.  Recorded costs for the twelve months ended September 30, 2005
were $11 million.

Based on currently available information, Edison International believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range for its identified
sites and, based upon the CPUC's regulatory treatment of environmental remediation costs
incurred at SCE, Edison International


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


believes that costs ultimately recorded will not materially affect its results of operations
or financial position.  There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of new sites,
will not require material revisions to such estimates.

Federal Income Taxes

Edison International has reached a settlement with the IRS on tax issues and pending
affirmative claims relating to its 1991-1993 tax years.  This settlement, which was signed
by Edison International in March 2005 and approved by the United States Congress Joint
Committee on Taxation on July 27, 2005, resulted in a third quarter 2005 net earnings
benefit for Edison International of approximately $65 million, including interest, most of
which relates to SCE.  This benefit was reflected in the income statement caption "Income
tax (benefit)."

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

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised
issues about the deferral of income taxes in audits of the 1994-1996 and 1997-1999 tax years
associated with Edison Capital's cross-border leases.  The IRS is challenging Edison
Capital's foreign power plant and electric locomotive sale/leaseback transactions (termed a
sale-in/lease-out or SILO transaction).  The estimated federal and state taxes deferred from
these leases were $44 million in the 1994-1996 and 1997-1999 audit periods and $32 million
in subsequent years through 2004.

The IRS is also challenging Edison Capital's foreign power plant and electric transmission
system lease/leaseback transactions (termed a lease-in, lease-out or LILO transaction).  The
estimated federal and state income taxes deferred from these leases were $558 million in the
1997-1999 audit period and $565 million in subsequent years through 2004.  The IRS has also
proposed interest and penalties in its challenge to each SILO and LILO transaction.

Edison International believes it properly reported these transactions based on applicable
statutes, regulations and case law in effect at the time the transactions were entered
into.  Written protests were filed to appeal the 1994-1996 audit adjustments asserting that
the IRS's position misstates material facts, misapplies the law and is incorrect.  This
matter is now being considered by the Administrative Appeals branch of the IRS.  Edison
International also filed protests in March 2005 to appeal the issues raised in the 1997-1999
audit.

Edison Capital also entered into a lease/service contract transaction in 1999 involving a
foreign telecommunication system (termed a Service Contract).  The IRS did not assert an
adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge this
lease in subsequent audit cycles similar to positions asserted against the SILOs discussed
above.  The estimated federal and state taxes deferred from this lease are $221 million
through 2004.

If Edison International is not successful in its defense of the tax treatment for the SILOs,
LILOs and the Service Contract, the payment of taxes, exclusive of any interest or
penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow.


Page 24


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


However, the FASB is currently considering changes to the accounting for leases.  If the
proposed accounting changes are adopted and Edison International's tax treatment for the
SILOs, LILOs and Service Contract is significantly altered as a result of IRS challenges,
there could be a material effect on reported earnings by requiring Edison International to
reverse earnings previously recognized as a current period adjustment and to report these
earnings over the remaining life of the leases.  At this time, Edison International is
unable to predict the impact of the ultimate resolution of these matters.

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

In April 2004, Edison International filed California Franchise Tax amended returns for tax
years 1997 through 2002 to abate the possible imposition of new California penalty
provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice that was published in 2001.  These
transactions include certain Edison Capital leveraged lease transactions and the SCE
subsidiary contingent liability company transaction described above.  Edison International
filed these amended returns under protest retaining its appeal rights.

Investigations Regarding Performance Incentives Rewards

SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn
rewards or penalties for the period of 1997 through 2003 based on its performance in
comparison to CPUC-approved standards of customer satisfaction, employee injury and illness
reporting, and system reliability.  Current CPUC ratemaking (through SCE's 2003 GRC
decision) provides for performance incentives or penalties for differences between actual
results and GRC-determined standards of employee injury and illness reporting, and system
reliability.

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

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that
personnel in the service planning group of SCE's transmission and distribution business unit
altered or omitted data in attempts to influence the outcome of customer satisfaction
surveys conducted by an independent survey organization.  The results of these surveys are
used, along with other factors, to determine the amounts of any incentive rewards or
penalties to SCE under the PBR provisions for customer satisfaction.  SCE recorded aggregate
customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000.  Potential
customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are
pending


Page 25


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


before the CPUC and have not been recognized in income by SCE.  SCE also anticipated that it
could be eligible for customer satisfaction rewards of about $10 million for 2003.

SCE has been keeping the CPUC informed of the progress of SCE's internal investigation.  On
June 25, 2004, SCE submitted to the CPUC a PBR customer satisfaction investigation report,
which concluded that employees in the design organization of the transmission and
distribution business unit deliberately altered customer contact information in order to
affect the results of customer satisfaction surveys.  At least 36 design organization
personnel engaged in deliberate misconduct including alteration of customer information
before the data were transmitted to the independent survey company.  Because of the apparent
scope of the misconduct, SCE proposed to refund to ratepayers $7 million of the PBR rewards
previously received and forego an additional $5 million of the PBR rewards pending that are
both attributable to the design organization's portion of the customer satisfaction rewards
for the entire PBR period (1997-2003).  In addition, during its investigation, SCE
determined that it could not confirm the integrity of the method used for obtaining customer
satisfaction survey data for meter reading.  Thus, SCE also proposed to refund all of the
approximately $2 million of customer satisfaction rewards associated with meter reading.  As
a result of these findings, SCE accrued a $9 million charge in 2004 for the potential
refunds of rewards that have been received.

SCE has taken remedial action as to the customer satisfaction survey misconduct by severing
the employment of several supervisory personnel, updating system process and related
documentation for survey reporting, and implementing additional supervisory controls over
data collection and processing.  The PBR performance incentive mechanism for customer
satisfaction expired after calendar year 2003 pursuant to the CPUC's decision in SCE's 2003
GRC.

The CPUC has not yet opened a formal investigative proceeding into this matter.  However,
the CPSD of the CPUC has submitted several data requests to SCE and has requested an
opportunity to interview a number of current and former SCE employees in the design
organization.  SCE has responded to these requests and the CPSD has conducted interviews of
approximately 20 employees who were disciplined for misconduct.  In addition, the CPSD has
conducted interviews of four senior managers and executives of the Transmission and
Distribution Business Unit regarding the design organization.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an
investigation into the accuracy of SCE's employee injury and illness reporting.  The yearly
results of employee injury and illness reporting to the CPUC are used to determine the
amount of the incentive reward or penalty to SCE under the PBR mechanism.  Since the
inception of PBR in 1997, SCE has received $20 million in employee safety incentives for
1997 through 2000 and, based on SCE's records, would have been entitled to an additional
$15 million for 2001 through 2003 ($5 million for each year).

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies
certain findings concerning SCE's performance under the PBR incentive mechanism for injury
and illness reporting.  Under the PBR mechanism, rewards and/or penalties for the years 1997
through 2003 were based upon a total incident rate, which included two equally weighted
measures:  Occupational Safety and Health Administration (OSHA) recordable incidents and
first aid incidents.  The major issue disclosed in the investigative findings to the CPUC
was that SCE failed to implement an effective recordkeeping system sufficient to capture all
required data for first aid incidents.  SCE's investigation also found reporting
inaccuracies for OSHA recordable incidents, but the impact of these inaccuracies did not
have a material effect on the PBR mechanism.


Page 26


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


As a result of these findings, SCE proposed to the CPUC that it not collect any reward under
the PBR mechanism for any year before 2004, and it return to ratepayers the $20 million it
has already received.  Therefore, SCE accrued a $20 million charge in 2004 for the potential
refund of these rewards.  SCE has also proposed to withdraw the pending requests for rewards
for the 2001-2002 time frames.  SCE has not yet filed a request related to its performance
for 2003 under the PBR mechanism.

SCE is taking other remedial action to address the issues identified, including revising its
organizational structure and overall program for environmental, health and safety
compliance.  SCE also took disciplinary action against twenty-four individuals in several
SCE business areas in early June 2005.  SCE submitted a report on the results of its
investigation to the CPUC on December 3, 2004.

As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative
proceeding into this matter.  However, the CPSD did submit several data requests to SCE to
which SCE has responded.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE has
conducted an investigation into the PBR system reliability metric for the years 1997 through
2003.  Since the inception of PBR payments in 1997, SCE has received $8 million in rewards
and has applied for an additional $5 million reward based on frequency of outage data for
2001.  For 2002, SCE's data indicates that it earned no reward and incurred no penalty.
Based on the application of the PBR mechanism, SCE would be penalized $5 million for 2003;
however, as indicated above, SCE has not filed a request related to its performance under
the PBR mechanism for 2003.

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

The CPUC is not expected to act on SCE's recent advice letter for 2004 or the pending PBR
advice letters for 2001 and 2002 until the CPSD has completed its investigation of these
matters.  SCE has agreed to file its PBR advice letter for 2003 after the CPSD has completed
its investigation.

Navajo Nation Litigation

In June 1999, the Navajo Nation filed a complaint in the United States District Court for
the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and
certain of its affiliates, Salt River Project Agricultural Improvement and Power District,
and SCE arising out of the coal supply agreement for Mohave.  The complaint asserts claims
for, among other things, violations of the federal Racketeer Influenced and Corrupt
Organizations statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related claims.  The
complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the
full value in royalty rates for the coal supplied to Mohave.  The complaint seeks damages of
not less than $600 million, trebling of that amount, and punitive damages of not less than
$1 billion, as well as a declaration that Peabody's lease and contract rights to mine coal on
Navajo Nation lands should be terminated.  SCE joined Peabody's motion to strike the Navajo
Nation's complaint.  In addition, SCE and other defendants filed motions to dismiss.  The
D.C. District Court denied these motions for dismissal, except for Salt River Project
Agricultural Improvement and Power District's motion for its separate dismissal from the
lawsuit.


Page 27



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Certain issues related to this case were addressed by the United States Supreme Court in a
separate legal proceeding filed by the Navajo Nation in the United States Court of Federal
Claims against the United States Department of Interior.  In that action, the Navajo Nation
claimed that the Government breached its fiduciary duty concerning negotiations relating to
the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody.  On March 4,
2003, the Supreme Court concluded, by majority decision, that there was no breach of a
fiduciary duty and that the Navajo Nation did not have a right to relief against the
Government.  Based on the Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed
motions to dismiss or, in the alternative, for summary judgment in the D.C. District Court
action.  On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003
motions to dismiss or, in the alternative, for summary judgment.  The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off.
Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay
of the action to allow the parties to attempt to resolve, through facilitated negotiations,
all issues associated with Mohave.  Negotiations are ongoing and the stay has been continued
until further order of the court.  On July 28, 2005, the D.C. District Court issued an order
removing the lawsuit from the Court's active docket.

The Court of Appeals for the Federal Circuit, acting on a suggestion on remand filed by the
Navajo Nation, held in an October 24, 2003 decision that the Supreme Court's March 4, 2003
decision was focused on three specific statutes or regulations and therefore did not address
the question of whether a network of other statutes, treaties and regulations imposed
judicially enforceable fiduciary duties on the United States during the time period in
question.  The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 Federal Circuit decision.  Both petitions were denied on March 9, 2004.  On
March 16, 2004, the Federal Circuit issued an order remanding the case against the
Government to the Court of Federal Claims, which conducted a status conference on May 18,
2004.  As a result of the status conference discussion, the Court of Federal Claims ordered
the Navajo Nation and the Government to brief the remaining issues following remand
(described below).  The Navajo Nation's initial brief was filed in the remanded Court of
Federal Claims matter on August 26, 2004, and the Government filed its responsive brief on
December 10, 2004.  The Navajo Nation subsequently obtained an extension of the due date for
its reply brief while the Court of Federal Claims considered a motion to strike filed by the
Government.  Peabody's motion to intervene in the remanded Court of Federal Claims case as a
party was denied.  On February 24, 2005, the Court of Federal Claims denied the motion to
strike filed by the Government, but authorized the Government to file a supplemental brief
and appendix, which was filed by the Government on March 23, 2005.  On April 25, 2005, the
Navajo Nation filed its reply brief and also filed a motion to strike the Government's
supplemental brief and all of the exhibits attached to that brief.  Oral argument on the
Navajo Nation's motion to strike took place at a hearing on September 28, 2005, at which
time the motion was denied.  At the same hearing, the Court of Federal Claims heard argument
on the issues remanded by the Federal Circuit, which are focused on (1) whether the Navajo
Nation previously waived its "network of other laws" argument and, (2) if not, whether the
Navajo Nation can establish that the Government breached any fiduciary duties pursuant to
such "network."  At the conclusion of the September 28, 2005 hearing, the Court of Federal
Claims took the remanded issues under submission.

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


Page 28


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 billion.  SCE
and other owners of San Onofre Nuclear Generating Station and Palo Verde have purchased the
maximum private primary insurance available ($300 million).  The balance is covered by the
industry's retrospective rating plan that uses deferred premium charges to every reactor
licensee if a nuclear incident at any licensed reactor in the United States results in
claims and/or costs which exceed the primary insurance at that plant site.  Federal
regulations require this secondary level of financial protection.  The Nuclear Regulatory
Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994.  The
current maximum deferred premium for each nuclear incident is $101 million per reactor, but
not more than $15 million per reactor may be charged in any one year for each incident.  The
maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear
incident will be adjusted for inflation on a 5-year schedule.  The next inflation adjustment
will occur on August 31, 2008.  Based on its ownership interests, SCE could be required to
pay a maximum of $199 million per nuclear incident.  However, it would have to pay no more
than $30 million per incident in any one year.  Such amounts include a 5% surcharge if
additional funds are needed to satisfy public liability claims and are subject to adjustment
for inflation.  If the public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a possible additional
assessment on all licensed reactor operators.  All licensed operating plants including San
Onofre and Palo Verde are grandfathered under the applicable law.

Property damage insurance covers losses up to $500 million, including decontamination costs,
at San Onofre and Palo Verde.  Decontamination liability and property damage coverage
exceeding the primary $500 million also has been purchased in amounts greater than federal
requirements.  Additional insurance covers part of replacement power expenses during an
accident-related nuclear unit outage.  A mutual insurance company owned by utilities with
nuclear facilities issues these policies.  If losses at any nuclear facility covered by the
arrangement were to exceed the accumulated funds for these insurance programs, SCE could be
assessed retrospective premium adjustments of up to $44 million per year.  Insurance
premiums are charged to operating expense.

Schedule Coordinator Tariff Dispute

SCE serves as an SC for the Los Angeles Department of Water & Power (DWP) over the
ISO-controlled grid.  In mid-2003, SCE filed a petition asking that the FERC accept a tariff
that provides for a direct pass-through of the FERC-authorized charges incurred by SCE on
the DWP's behalf.  The DWP protested SCE's filing.  The DWP asked the FERC to declare that
SCE was obligated to serve as the DWP's SC without charge.  In late 2003, the FERC accepted
the tariff, subject to refund.  The FERC held that the proposed tariff has not been shown to
be just and reasonable.

In accordance with the terms of the tariff, SCE issued several invoices for charges to the
DWP.  The DWP has objected to all of the charges but has paid, under protest, approximately
$18 million.  The DWP has protested specific charges totaling approximately $5 million based
on its allegations that those specific charges are improper for various reasons.

The FERC has not issued a final order on this issue.  SCE could be required to refund all or
part of the amounts collected under the tariff.  SCE continues to invoice the DWP.  Monthly
invoices have been averaging approximately $1 million.  SCE cannot predict with certainty
the outcome of the FERC final order.


Page 29



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Spent Nuclear Fuel

Under federal law, the United States Department of Energy (DOE) is responsible for the
selection and construction of a facility for the permanent disposal of spent nuclear fuel
and high-level radioactive waste.  The DOE did not meet its obligation to begin acceptance
of spent nuclear fuel not later than January 31, 1998.  It is not certain when the DOE will
begin accepting spent nuclear fuel from San Onofre or other nuclear power plants.  Extended
delays by the DOE have led to the construction of costly alternatives and associated siting
and environmental issues.  SCE has paid the DOE the required one-time fee applicable to
nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus
interest).  SCE is also paying the required quarterly fee equal to 0.1(cent)-per-kWh of
nuclear-generated electricity sold after April 6, 1983.  On January 29, 2004, SCE, as
operating agent, filed a complaint against the DOE in the United States Court of Federal
Claims seeking damages for DOE's failure to meet its obligation to begin accepting spent
nuclear fuel from San Onofre.  The case is currently stayed pending development in other
spent nuclear fuel cases also before the United States Court of Federal Claims.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at
San Onofre.  Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools
and the San Onofre independent spent fuel storage installation.  Movement of Unit 1 spent
fuel from the Unit 2 spent fuel pool to the independent spent fuel storage installation is
complete.  There is now sufficient space in the Unit 2 and 3 spent fuel pools to meet plant
requirements through mid-2007 and mid-2008, respectively.  In order to maintain a full core
off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the
independent spent fuel storage installation by late 2006.

In order to increase on-site storage capacity and maintain core off-load capability, Palo
Verde has constructed a dry cask storage facility.  Arizona Public Service, as operating
agent, plans to continually load casks on a schedule to maintain full core off-load
capability for all three units.

Note 5.  Business Segments

Edison International's reportable business segments include an electric utility operation
segment (SCE), a nonutility power generation segment (MEHC - parent only and EME), and a
financial services provider segment (Edison Capital).  Also, in accordance with an
accounting standard related to the impairment and disposal of long-lived assets, prior
periods have been restated to reflect EME's international operations being reported as
discontinued operations.


Page 30


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Segment information for the three and nine months ended September 30, 2005 and 2004 was:

                                                    Three Months Ended       Nine Months Ended
                                                       September 30,           September 30,
----------------------------------------------------------------------------------------------
    In millions                                      2005         2004        2005       2004
----------------------------------------------------------------------------------------------
                                                                    (Unaudited)
    Operating Revenue:
    Electric utility                              $ 3,084      $ 2,655      $7,194     $6,527
    Nonutility power generation                       677          509       1,605      1,257
    Financial services                                 21           22          72         78
    Corporate and other                                 1            2           7          7
----------------------------------------------------------------------------------------------
    Consolidated Edison International             $ 3,783      $ 3,188      $8,878     $7,869
----------------------------------------------------------------------------------------------
    Net Income (Loss):
    Electric utility(1)                           $   280      $   259      $  572     $  600
    Nonutility power generation(2)                    181          559         234        (44)
    Financial services(3)                               3           12          80         33
    Corporate and other                                (2)         (17)        (22)       (52)
----------------------------------------------------------------------------------------------
    Consolidated Edison International             $   462      $   813      $  864     $  537
----------------------------------------------------------------------------------------------

    (1) Net income available for common stock.

    (2) Includes earnings from discontinued operations of $27 million and $55 million,
        respectively, for the three and nine months ended September 30, 2005 and $499 million
        and $570 million, respectively, for the three and nine months ended September 30,
        2004.

    (3) Includes a loss of $1 million from the cumulative effect of an accounting change for
        the nine months ended September 30, 2004.

Corporate and other includes amounts from nonutility subsidiaries not significant as a
reportable segment.

Total segment assets as of September 30, 2005 were:  electric utility, $25 billion;
nonutility power generation, $7 billion; and, financial services, $4 billion.

Note 6.  Agreement to Sell the Doga Project

EME owns an 80% interest in a 180-MW gas-fired cogeneration plant near Istanbul, Turkey,
which EME refers to as the Doga project.  On August 17, 2005, EME entered into a purchase
agreement, to sell its interest in the Doga project to EME's co-investor in the Doga
project, Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an
additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which
will acquire a 50% interest in the Doga project.  Completion of the sale is subject to the
satisfaction of a number of closing conditions, including obtaining the consent of a
majority of the project's lenders.  The sale is expected to close in the fourth quarter of
2005.

Note 7.  Discontinued Operations

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to
a purchase agreement dated December 15, 2004, to a consortium comprised of International
Power plc (70%) and


Page 31


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million.  The sale of
this investment had no significant effect on net income in the first quarter of 2005.

On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan
project to Corporacion IMPSA S.A., pursuant to a purchase agreement dated November 5, 2004.
Proceeds from the sale were approximately $104 million.  EME recorded a pre-tax gain on the
sale of approximately $9 million during the first quarter of 2005.

On December 16, 2004, EME sold the stock and related assets of MEC International B.V.
(MECIBV) to IPM, pursuant to a purchase agreement dated July 29, 2004.  The purchase
agreement was entered into following a competitive bidding process.  The sale of MECIBV
included the sale of EME's interests in ten electric power generating projects or companies
located in Europe, Asia, Australia, and Puerto Rico.  Consideration from the sale of MECIBV
and related assets was $2.0 billion.

On September 30, 2004, EME sold its 51% interest in Contact Energy to Origin Energy New
Zealand Limited pursuant to a purchase agreement dated July 20, 2004.  The purchase
agreement was entered into following a competitive bidding process.  Consideration for the
sale was NZ$1.6 billion (approximately $1.1 billion) which includes NZ$535 million of debt
assumed by the purchaser.  EME recorded an after-tax gain on sale of $141 million during the
third quarter of 2004.

EME previously owned and operated a 220-MW combined cycle, natural gas-fired power plant
located in the United Kingdom, known as the Lakeland project.  The ownership of the project
was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated
from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of
TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU
Europe).  EME ceased consolidating the activities of Lakeland Power Ltd. in 2002, when an
administrative receiver was appointed following a default by Norweb Energi Ltd. under the
power sales agreement.  Accordingly, EME accounts for its ownership of Lakeland Power Ltd.
on the cost method and earnings are recognized as cash is distributed from this entity.

As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim
against Norweb Energi Ltd. for termination of the power sales agreement.  On November 19,
2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited, entered into formal administration proceedings of their own in the United Kingdom
(similar to bankruptcy proceedings in the United States).  On March 31, 2005, Lakeland Power
Ltd. received(pound)112 million (approximately $210 million) from the TXU administrators,
representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately
$217 million).

From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United
Kingdom, has made a payment of(pound)20 million (approximately $37 million) to EME on April 7,
2005 comprised of(pound)7 million (approximately $13 million) for a secured loan which EME
purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured
receivables from Lakeland Power Ltd., and(pound)13 million (approximately $24 million) as a
distribution to the EME subsidiary that owns the equity interest in Lakeland Power Ltd.
This distribution was recognized in income during the quarter ended June 30, 2005.
Additionally, Lakeland Power Ltd. will pay to EME's subsidiary that owns the equity interest
in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured and
unsecured creditor claims and payment of or provision for tax liabilities and the fees and
expenses associated with Lakeland Power Ltd.'s liquidation.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


EME estimates that the remaining net proceeds after tax (including taxes due in the United
States) and net income resulting from the above payments will be approximately $64 million.
The majority of the remaining proceeds are expected to be received in 2006, when Lakeland
Power Ltd.'s liquidation is expected to be completed.  Because the amounts required to
settle outstanding claims and UK taxes have not been finalized and cannot be estimated
precisely in the context of the liquidation, the actual amount of net proceeds and increase
in net income may vary materially from the above estimate.

For all periods presented, the results of EME's international projects, except for the Doga
project (see Note 6), discussed above have been accounted for as discontinued operations in
the consolidated financial statements in accordance with an accounting standard related to
the impairment and disposal of long-lived assets.

There was no revenue from discontinued operations in 2005.  For the three and nine months
ended September 30, 2004, revenue from discontinued operations was $354 million and $1.1
billion, respectively.  For the three months ended September 30, 2005 and 2004, pre-tax
income (loss) was $(2) million and $41 million, respectively.  For the nine months ended
September 30, 2005 and 2004, pre-tax income was $20 million and $165 million, respectively.

During the third quarter ended September 30, 2005, EME recorded tax adjustments of
$28 million, which resulted from the completion of the 2004 federal and California income tax
returns and quarterly review of tax accruals.  The majority of the tax adjustments are
related to the sale of the international assets.  These adjustments (benefits) are included
in income from discontinued operations - net of tax on the consolidated income statements.
During the quarter ended September 30, 2004, EME recorded a deferred income tax benefit of
$327 million to recognize the higher tax basis of its international holding company over its
book basis as required by accounting rules applicable to discontinued operations.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The carrying value of assets and liabilities recorded as discontinued operations is:

                                                              September 30,   December 31,
    In millions                                                  2005              2004
------------------------------------------------------------------------------------------
                                                               (Unaudited)
    Assets
    Cash and equivalents                                       $    2            $    2
    Other current assets                                           --                 2
------------------------------------------------------------------------------------------
    Total current assets                                            2                 4
------------------------------------------------------------------------------------------
    Investments in partnerships and
      unconsolidated subsidiaries                                  --               107
    Other deferred charges                                         10                11
------------------------------------------------------------------------------------------
    Total assets of discontinued operations                    $   12            $  122
------------------------------------------------------------------------------------------
    Liabilities
    Accounts payable and accrued liabilities                   $   --            $    2
------------------------------------------------------------------------------------------
    Total current liabilities                                      --                 2
------------------------------------------------------------------------------------------
    Customer advances and other deferred credits                    5                 4
    Other long-term liabilities                                    10                 9
------------------------------------------------------------------------------------------
    Total liabilities of discontinued operations               $   15            $   15
------------------------------------------------------------------------------------------


Note 8.  Impairment Losses and Loss on Lease Termination

Impairment Loss on Equity Method Investment

During the third quarter of 2005, EME fully impaired its equity investment in the March
Point project following an updated forecast of future project cash flows.  The March Point
project is a 140-MW natural gas-fired cogeneration facility located in Anacortes,
Washington, in which a subsidiary of EME owns a 50% partnership interest.  The March Point
project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements
that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil)
under a steam supply agreement that also expires in 2011.  March Point purchases a portion
of its fuel requirements under long-term contracts with the remaining requirements purchased
at current market prices.  March Point's power sales agreements do not provide for a price
adjustment related to the project's fuel costs.  During the third quarter of 2005, long-term
natural gas prices increased substantially, thereby adversely affecting the future cash
flows of the March Point project.  As a result, EME concluded that its investment was
impaired and recorded a $55 million charge during the third quarter of 2005.

Asset Impairment

In September 2004, EME completed an analysis of future competitiveness in the expanded PJM
Interconnection, LLC marketplace of its eight remaining small peaking units in Illinois.
Based on this analysis, EME decided to decommission six of the eight small peaking units.
As a result of the decision to decommission the units, projected cash flows associated with
the Illinois peaking units were less than the book value of the units resulting in an
impairment under an accounting standard for the impairment or


Page 34


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


disposal of long-lived assets.  During the third quarter of 2004, EME recorded a pre-tax
impairment charge of $29 million (approximately $18 million after tax).

Loss on Lease Termination

On April 27, 2004, Midwest Generation terminated the Collins Station lease through a
negotiated transaction with the lease equity investor.  Midwest Generation made a lease
termination payment of approximately $960 million.  This amount represented the $774 million
of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity
investor for early termination of the lease.  Midwest Generation received title to the
Collins Station as part of the transaction.  EME recorded a pre-tax loss of approximately
$956 million (approximately $587 million after tax) due to termination of the lease and the
planned decommissioning of the asset, and the disposition of excess inventory.

Note 9.  Commitments

The following is an update to Edison International's commitments.  See Note 9 of "Notes to
Consolidated Financial Statements" included in Edison International's 2004 Annual Report for
a detailed discussion.

Leases

During the first quarter of 2005, SCE entered into new power contracts in which it takes
virtually all of the power.  In accordance with an accounting standard, these power
contracts are classified as operating leases.  SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million
for 2007 and $43 million for 2008.

Other Commitments

Midwest Generation, LLC (Midwest Generation) and EME Homer City Generation L.P. (EME Homer
City) have entered into additional fuel purchase commitments with various third-party
suppliers during the first nine months of 2005.  These additional commitments are currently
estimated to be $22 million for 2005, $114 million for 2006, $169 million for 2007,
$44 million for 2008, and $62 million for 2009.

Midwest Generation has contractual agreements for the transport of coal to its facilities.
The primary contract is with Union Pacific Railroad (and various delivering carriers) which
extend through 2011.  Midwest Generation commitments under this agreement are based on
actual coal purchases from the Powder River Basin.  Accordingly, contractual obligations for
transportation are based on coal volumes set forth in fuel supply contracts.  The increase
in transportation commitments entered into during the first nine months of 2005 relates to
additional volumes of fuel purchases using the terms of existing transportation agreements.
These commitments are currently estimated to be $33 million for 2005, $61 million for 2006,
$117 million for 2007, $40 million for 2008, and $77 million for 2009.

During the first quarter of 2005, SCE entered into additional power call option contracts.
SCE's revised purchased-power capacity payment commitments under these contracts are
currently estimated to be $31 million for 2005, $95 million for 2006, $101 million for 2007
and $84 million for 2008.


Page 35


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and
indemnifications which are issued in the normal course of business.  As discussed below,
these contracts included performance guarantees, guarantees of debt and indemnifications.

EME's Tax Indemnity Agreements

In connection with the sale-leaseback transactions that EME has entered into related to the
Powerton and Joliet Stations in Illinois, and previously the Collins Station in Illinois,
and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered
into tax indemnity agreements.  Under these tax indemnity agreements, these entities agreed
to indemnify the lessors in the sale-leaseback transactions for specified adverse tax
consequences that could result in certain situations set forth in each tax indemnity
agreement, including specified defaults under the respective leases.  The potential
indemnity obligations under these tax indemnity agreements could be significant.  Due to the
nature of these potential obligations, EME cannot determine a maximum potential liability
which would be triggered by a valid claim from the lessors.  EME has not recorded a
liability related to these indemnities.  In connection with the termination of the Collins
Station lease in April 2004, Midwest Generation will continue to have obligations under the
tax indemnity agreement with the former lease equity investor.

Indemnities Provided as Part of EME's Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois plants, EME agreed to indemnify
Commonwealth Edison with respect to specified environmental liabilities before and after
December 15, 1999, the date of sale.  The indemnification claims are reduced by any
insurance proceeds and tax benefits related to such claims and are subject to a requirement
that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such
indemnification claim.  Due to the nature of the obligation under this indemnity, a maximum
potential liability cannot be determined.  This indemnification for environmental
liabilities is not limited in term and would be triggered by a valid claim from Commonwealth
Edison.  Except as discussed below, EME has not recorded a liability related to this
indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon
Generation Company on February 20, 2003 to resolve a dispute regarding interpretation of its
reimbursement obligation for asbestos claims under the environmental indemnities set forth
in the asset sale agreement.  Under this supplemental agreement, Midwest Generation agreed
to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos
claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement
for liabilities and expenses associated with future asbestos-related claims as specified in
the agreement.  As a general matter, Commonwealth Edison and Midwest Generation apportion
responsibility for future asbestos-related claims based upon the number of exposure sites
that are Commonwealth Edison locations or Midwest Generation locations.  The obligations
under this agreement are not subject to a maximum liability.  The supplemental agreement has
a five-year term with an automatic renewal provision (subject to the right of either party
to terminate).  Payments are made under this indemnity upon tender by Commonwealth Edison of
appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or
expense.  There were between 170 and 190 cases for which Midwest Generation was potentially
liable and that had not been settled and dismissed at September 30, 2005.  Midwest
Generation had recorded a $68 million liability at September 30, 2005 related to this matter.


Page 36


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The amounts recorded by Midwest Generation for the asbestos-related liability are based upon
a number of assumptions.  Projecting future events, such as the number of new claims to be
filed each year, the average cost of disposing of claims, as well as the numerous
uncertainties surrounding asbestos litigation in the United States, could cause the actual
costs to be higher or lower than projected.

Indemnity Provided as Part of EME's Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to
indemnify the sellers with respect to specific environmental liabilities before and after
the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998.  EME
guaranteed the obligations of EME Homer City.  Due to the nature of the obligation under
this indemnity provision, it is not subject to a maximum potential liability and does not
have an expiration date.  Payments would be triggered under this indemnity by a claim from
the sellers.  EME has not recorded a liability related to this indemnity.

Indemnities Provided under EME's Asset Sale Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities
from EME to the purchasers, including indemnification for taxes imposed with respect to
operations of the assets prior to the sale and for pre-closing environmental liabilities.
EME also provided an indemnity to IPM for matters arising out of the exercise by one of its
project partners of a purported right of first refusal.  Not all indemnities under the asset
sale agreements have specific expiration dates.  Payments would be triggered under these
indemnities by valid claims from the sellers or purchasers, as the case may be.  At
September 30, 2005, EME had recorded an $86 million liability related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided
indemnities to the purchasers for taxes imposed with respect to operations of the asset
prior to the sale.  EME has also provided indemnities to purchasers for items specified in
each agreement (for example, specific pre-existing litigation matters and/or environmental
conditions).  Due to the nature of the obligations under these indemnity agreements, a
maximum potential liability cannot be determined.  Not all indemnities under the asset sale
agreements have specific expiration dates.  Payments would be triggered under these
indemnities by valid claims from the sellers or purchasers, as the case may be.  EME has not
recorded a liability related to these indemnities.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments

On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York,
Inc., which holds a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners,
L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns
a 286-MW gas-fired cogeneration power plant in Brooklyn, New York.  In February 1997, the
construction contractor asserted general monetary claims under the turnkey agreement against
Brooklyn Navy Yard.  A settlement agreement was executed on January 17, 2003, and all
litigation has been dismissed.  EME agreed to indemnify Brooklyn Navy Yard and, in
connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any
payments due under this settlement agreement, which are scheduled through January 2007.  At
September 30, 2005, EME had recorded a $7 million liability related to this indemnity.


Page 37


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


EME's Capacity Indemnification Agreements

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point
Cogeneration Company under its project power sales agreements to repay capacity payments to
the project's power purchaser in the event that the power sales agreements terminate, March
Point Cogeneration Company abandons the project, or the project fails to return to normal
operations within a reasonable time after a complete or partial shutdown, during the term of
the power contracts.  In addition, a subsidiary of EME has guaranteed the obligations of
Sycamore Cogeneration Company under its project power sales agreement to repay capacity
payments to the project's power purchaser in the event that the project unilaterally
terminates its performance or reduces its electric power producing capability during the
term of the power contract.  The obligations under the indemnification agreements as of
September 30, 2005, if payment were required, would be $134 million.  EME has not recorded a
liability related to this indemnity.

Indemnity Provided as Part of SCE's Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with
respect to specific environmental claims related to SCE's previously owned San Bernardino
Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview
acquisition.  The generating station has not operated since early 2001, and SCE retained
certain responsibilities with respect to environmental claims as part of the original
divestiture of the station.  The aggregate liability for either party to the purchase
agreement for damages and other amounts is a maximum of $60 million.  This indemnification
for environmental liabilities expires on or before March 12, 2033.  SCE has not recorded a
liability related to this indemnity.

Note 10.  Preferred Stock Subject to Mandatory Redemption

SCE redeemed 807,000 shares of 7.23% $100 cumulative preferred stock at par value on
April 30, 2005 and 637,500 shares of 6.05% $100 cumulative preferred stock at par value on
May 20, 2005.

Note 11.  Preferred and Preference Stock of Utility Not Subject to Mandatory Redemption

SCE's authorized shares are:  $100 cumulative preferred - 12 million; $25 cumulative
preferred - 24 million and preference - 50 million.  SCE issued 4 million shares of 5.349%
Series A preference stock (non-cumulative, $100 liquidation value) on April 27, 2005.  The
Series A preference stock may not be redeemed prior to April 30, 2010.  After April 30,
2010, SCE may, at its option, redeem the shares in whole or in part and the dividend rate
may be adjusted.  SCE issued 2 million shares of 6.125% Series B preference stock
(non-cumulative, $100 liquidation value) on September 21, 2005.  The Series B preference
stock may not be redeemed prior to September 30, 2010.  After September 30, 2010, SCE may,
at its option, redeem the shares in whole or in part.  There is no sinking fund for the
redemption or repurchase of the shares.  The Series A and B preference stock rank junior to
all of the preferred stock and senior to all common stock.  The Series A and B preference
stock is not convertible into shares of any other class or series of SCE's capital stock or
any other security.  Shares of SCE's preferred stock have liquidation and dividend
preferences over shares of SCE's preference stock and common stock.




Page 38



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

                                         INTRODUCTION

This Management's Discussion and Analysis of Financial Condition and Results of Operations
(MD&A) for the three- and nine-month periods ended September 30, 2005 discusses material
changes in the financial condition, results of operations and other developments of Edison
International since December 31, 2004, and as compared to the three- and nine-month periods
ended September 30, 2004.  This discussion presumes that the reader has read or has access
to Edison International's MD&A for the calendar year 2004 (the year-ended 2004 MD&A), which
was included in Edison International's 2004 annual report to shareholders and incorporated
by reference into Edison International's Annual Report on Form 10-K for the year ended
December 31, 2004, filed with the Securities and Exchange Commission.

This MD&A contains "forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995.  Forward-looking statements reflect Edison International's
current expectations and projections about future events based on Edison International's
knowledge of present facts and circumstances and assumptions about future events and include
any statement that does not directly relate to a historical or current fact.  Other
information distributed by Edison International that is incorporated in this report, or that
refers to or incorporates this report, may also contain forward-looking statements.  In this
report and elsewhere, the words "expects," "believes," "anticipates," "estimates,"
"projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and
variations of such words and similar expressions, or discussions of strategy or of plans,
are intended to identify forward-looking statements.  Such statements necessarily involve
risks and uncertainties that could cause actual results to differ materially from those
anticipated.  Some of the risks, uncertainties and other important factors that could cause
results to differ, or that otherwise could impact Edison International or its subsidiaries,
include, but are not limited to:

o   the ability of Edison International to meet its financial obligations and to pay
    dividends on its common stock if its subsidiaries are unable to pay dividends;
o   the ability of Southern California Edison Company (SCE) to recover its costs in a
    timely manner from its customers through regulated rates;
o   decisions and other actions by the California Public Utilities Commission (CPUC) and
    other regulatory authorities and delays in regulatory actions;
o   market risks affecting SCE's energy procurement activities;
o   access to capital markets and the cost of capital;
o   changes in interest rates and rates of inflation;
o   governmental, statutory, regulatory or administrative changes or initiatives
    affecting the electricity industry, including the market structure rules applicable to
    each market and environmental regulations that could require additional expenditures or
    otherwise affect the cost and manner of doing business;
o   risks associated with operating nuclear and other power generating facilities,
    including operating risks, equipment failure, availability, heat rate and output;
o   the availability of labor, equipment and materials;
o   the ability to obtain sufficient insurance;
o   effects of legal proceedings, changes in tax laws, rates or policies, and changes in
    accounting standards;
o   supply and demand for electric capacity and energy, and the resulting prices and
    dispatch volumes, in the wholesale markets to which Edison Mission Energy's (EME)
    generating units have access;
o   the cost and availability of coal, natural gas, and fuel oil, and associated
    transportation costs;
o   the cost and availability of emission credits or allowances for emission credits for
    EME and its subsidiaries;


Page 39



o   transmission congestion in and to each market area and the resulting differences in prices
    between delivery points in which EME and its subsidiaries operate;
o   the ability to provide sufficient collateral in support of hedging activities and
    purchases of fuel and electric energy;
o   the extent of additional supplies of capacity, energy and ancillary services from
    current competitors or new market entrants, including the development of new generation
    facilities, including new plants  and technologies that may be developed in the future;
o   general political, economic and business conditions;
o   weather conditions, natural disasters and other unforeseen events; and
o   changes in the fair value of investments accounted for using fair value accounting.

Additional information about risks and uncertainties, including more detail about the
factors described above, is contained throughout this MD&A.  Readers are urged to read this
entire report, including the information incorporated by reference, and carefully consider
the risks, uncertainties and other factors that affect Edison International's business.  The
information contained in this report is subject to change without notice.  Forward-looking
statements speak only as of the date they are made and Edison International is not obligated
to publicly update or revise forward-looking statements.  Readers should review future
reports filed by Edison International with the Securities and Exchange Commission.  The
following discussion provides updated information about material developments since the
issuance of the year-ended 2004 MD&A and should be read in conjunction with the financial
statements contained in this quarterly report and Edison International's Annual Report on
Form 10-K for the year ended December 31, 2004.

Edison International is engaged in the business of holding, for investment, the common stock
of its subsidiaries.  Edison International's principal operating subsidiaries are Southern
California Edison Company (SCE), Edison Mission Energy (EME) and Edison Capital.  Mission
Energy Holding Company (MEHC) (parent), a subsidiary of Edison International, is the holding
company for its wholly owned subsidiary EME.  Since the second quarter of 2004,
MEHC (parent) and EME are presented as one business segment on a consolidated basis.  SCE
comprises the largest portion of the assets and revenue of Edison International.  In this
MD&A, except when stated to the contrary, references to each of Edison International, SCE,
MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated
basis.  References to Edison International (parent) or parent company and MEHC (parent) mean
Edison International or MEHC on a stand-alone basis, not consolidated with its
subsidiaries.  References to SCE, EME or Edison Capital followed by "(stand alone)" mean
each such company alone, not consolidated with its subsidiaries.

This MD&A is presented in 10 major sections.  The MD&A begins with a discussion of current
developments.  Following is a company-by-company discussion of Edison International's
principal business segments (SCE, MEHC, and Edison Capital) and Edison International
(parent).  Each principal business segment's discussion includes discussions of liquidity,
market risk exposures, and other matters (as relevant to each principal business segment).
The remaining sections discuss Edison International on a consolidated basis, including
results of operations and historical cash flow analysis, discontinued operations, new and
proposed accounting principles, commitments, guarantees and indemnities and other
developments.  These sections should be read in conjunction with the continuing operations
discussion of each principal business segment's section.

                                                                  Page
                                                                  ----
        Current Developments                                       42
        Southern California Edison Company                         46
        Mission Energy Holding Company                             60
        Edison Capital                                             78
        Edison International (Parent)                              79


Page 40



        Results of Operations and Historical Cash Flow Analysis    81
        Discontinued Operations                                    92
        New and Proposed Accounting Principles                     93
        Commitments, Guarantees and Indemnities                    95
        Other Developments                                         96


Page 41



                                     CURRENT DEVELOPMENTS

The following section provides a summary of current developments related to Edison
International's principal business segments.  This section is intended to be a summary of
those current developments that management believes are of most importance since year-end
December 31, 2004.  This section is not intended to be an all-inclusive list of all current
developments related to each principal business segment.  Further details of each current
development discussed below can be found in the specific principal business segment's
section of this MD&A, along with discussions of liquidity, market risk exposures, and other
matters as relevant to each principal business segment.

Passage of Comprehensive Energy Legislation by Congress

A comprehensive energy bill was passed by the House and Senate in July 2005 and was signed
by the President on August 8, 2005.  Known as "EPAct 2005," this comprehensive legislation
includes provisions for the repeal of the Public Utility Holding Company Act (PUHCA), for
amendments to the Public Utility Regulatory Policies Act of 1978 (PURPA), for the
introduction of new regulations regarding "Transmission Operation Improvements," for
Transmission Rate Reform, for incentives for various generation technologies and for the
extension through December 31, 2007 of production tax credits for wind and other specified
types of generation.  A number of these provisions will require implementing regulations to
be promulgated by the Federal Energy Regulatory Commission (FERC).  Edison International is
currently assessing the potential impact of this legislation and the likely regulations.

SCE:  CURRENT DEVELOPMENTS

2006 General Rate Case Proceeding

On December 21, 2004, SCE filed its application for a 2006 General Rate Case (GRC)
requesting a 2006 base rate revenue requirement of $4.06 billion, an increase of $370
million over SCE's 2005 base rate revenue.  The increase is primarily for capital-related
expenditures to accommodate infrastructure replacement, and customer and load growth.  The
requested increase is also necessary to fund substantially higher operating and maintenance
(O&M) expenses, particularly in SCE's transmission and distribution business unit.  SCE also
requested that the CPUC authorize the continuation of SCE's existing post-test year
rate-making mechanism.

As part of the GRC process, the CPUC's Office of Ratepayer Advocates (ORA) submitted
testimony proposing adjustments to reduce SCE's requested 2006 base rate revenue requirement
to $3.55 billion.  In addition, several intervenors have proposed further adjustments,
totaling $230 million, to reduce SCE's requested 2006 base rate revenue requirement.

During the course of the GRC proceeding, SCE agreed to certain revisions to its request,
updated the revenue requirement for the 2005 cost of capital, and incorporated a second
refueling and maintenance outage in the O&M expense forecast for San Onofre Nuclear
Generating Station (San Onofre) in 2006.  SCE's revised requested 2006 base rate revenue
requirement is $3.96 billion, an increase of $325 million over SCE's 2005 base rate
revenue.  SCE also proposed revised base rate revenue increases of $108 million for 2007 and
$113 million for 2008.

A final CPUC decision is expected in January 2006.  SCE cannot predict with certainty the
final outcome of SCE's GRC application.  See "SCE:  Regulatory Matters--Transmission and
Distribution--2006 General Rate Case Proceeding" for further discussion.


Page 42



MEHC:  CURRENT DEVELOPMENTS

EME Restructuring Activities

During 2004, EME sold most of its international operations. EME's international operations,
except for the Doga project, are accounted for as discontinued operations in accordance with
an accounting standard for the impairment or disposal of long-lived assets, and,
accordingly, all prior periods have been restated to reclassify the results of operations
and assets and liabilities as discontinued operations. In the first quarter of 2005, EME
completed the sale of two international projects:

o   EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to
    CBK Projects B.V., the purchasing entity designated by its partner, for $104 million.

o   EME sold its 25% equity interest in the Tri Energy project to IPM for approximately
    $20 million.

EME entered into a purchase agreement, dated as of August 17, 2005, to sell its 80% interest
in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve
Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project,
and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga
project. Completion of the sale is subject to the satisfaction of a number of closing
conditions, including obtaining the consent of a majority of the project's lenders. The sale
is expected to close in the fourth quarter of 2005.

In connection with the sale of its international operations in 2004, together with cash on
hand, in January 2005, EME:

o   made distributions to MEHC totaling $360 million, which were subsequently used
    primarily to repay the remaining $285 million portion of the term loan.

o   repaid its junior subordinated debentures and, consequently, repaid the monthly
    income preferred securities (MIPS) totaling $150 million.

In April 2005, EME made an equity contribution of $300 million to Midwest Generation, which
used the proceeds to repay indebtedness. See "MEHC:  Liquidity --Midwest Generation
Financing" for a discussion of the Midwest Generation financing.

EME has also completed a review of its domestic organization to better align its resources
with its domestic business requirements. Management and organizational changes have been
implemented to streamline EME's reporting relationships and eliminate its regional
management structure. As a result of these changes, EME recorded charges of approximately
$10 million (pre-tax) in the nine months ended September 30, 2005 for severance and related
costs.

Business Development Plans

Following the completion of restructuring activities described above, EME, together with its
affiliate, Edison Capital, has established a joint business development effort for wind
projects in addition to EME's development plans for thermal projects.

Wind Business Development

EME's affiliate, Edison Capital, has an existing 196 megawatt (MW) portfolio of wind
projects located in Iowa and Minnesota. In addition, a subsidiary of Edison Capital has
entered into an agreement to acquire a 120 MW wind project in eastern New Mexico from a wind
generation developer for


Page 43



$157 million. The acquisition of this project is subject to achieving commercial operations
and other closing conditions, which are expected to be met in December 2005. EME and Edison
Capital are considering transferring some or all of these projects to EME as part of EME's
independent power generation portfolio and expanding significantly, through EME, further
investments in wind projects throughout the United States. In addition, EME is considering
entering into agreements to purchase wind turbines to support these wind business
development activities. Pursuit of new renewable energy investments depends upon economic
and regulatory conditions and may be affected by government policies supporting renewable
energy. In August 2005, federal incentives for new wind projects, referred to as production
tax credits, were extended for new wind projects installed by December 31, 2007 under a
comprehensive federal energy bill, named the "Energy Policy Act of 2005."

Thermal Business Development

EME continues to review opportunities to develop or acquire additions to its power
generation portfolio. As part of this activity, EME had begun the process of obtaining
permits for two sites in Southern California for peaker plants and has responded to several
requests for proposals to build or acquire generation. Pursuit of new thermal projects in
California and elsewhere depends on a range of factors outside the control of EME, and,
accordingly, there is no assurance that these efforts will result in the actual development
or acquisition of additional generation capacity.

Expiration of the Exelon Power Purchase Agreements

The five-year power purchase agreements between Midwest Generation and Exelon Generation
Company expired on December 31, 2004 and, accordingly, beginning January 1, 2005, all the
output from the Illinois plants is considered merchant generation. In 2004, approximately
53% of the energy and capacity sales from the Illinois plants were to Exelon Generation
under the power purchase agreements.

The Exelon Generation power purchase agreement for coal-fired units was structured to
provide significant capacity payments and lower energy payments which were primarily
designed to reimburse the cost of production. The agreement also provided for substantial
capacity payments during the summer months. The Illinois plants continue to derive revenue
from sales of capacity and energy. In the current wholesale energy market, energy prices are
substantially higher than the energy prices previously set forth in the agreement, but
capacity payments are, and are expected to remain for some time, substantially lower. As a
result, the composition of EME's revenue was significantly different in the first nine
months of 2005 compared to 2004. EME's merchant generation is subject to significant
volatility as described further in "MEHC:  Market Risk Exposures--Commodity Price Risk."

Wholesale Energy Prices in Illinois

Wholesale energy prices at the Northern Illinois Hub (related to the Illinois plants) have
increased substantially in 2005 from the comparable market prices in 2004 driven largely by
increases in the market price of natural gas and oil. The average market price during the
nine months ended September 30, 2005 at the Northern Illinois Hub (related to the Illinois
plants) increased to $44.26 per MWh, compared to the average market prices "Into ComEd" and
at the Northern Illinois Hub of $29.36 per MWh during the nine months ended September 30,
2004.

Energy Trading Activities

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, Edison
Mission Marketing & Trading, to engage in trading activities in those markets in which it is
active as a result of its management of the merchant power plants of Midwest Generation and
Homer City. Edison Mission Marketing & Trading trades power, fuel and transmission primarily
in the eastern power grid using


Page 44



products available over-the-counter, through exchanges and from independent system
operators. Earnings from energy trading activities were $84 million and $125 million for the
third quarter and nine months ended September 30, 2005, respectively. Volatile market
conditions during the first nine months of 2005, driven by increased prices for natural gas
and oil and warmer summer temperatures, have created favorable conditions for Edison Mission
Marketing & Trading's trading strategies in 2005 compared to 2004. This trading activity is
limited by the risk management policies of EME, including a limit on value at risk. During
the first nine months of 2005, the maximum value at risk associated with trading of
over-the-counter products and exchange-traded products was $1.9 million, using a 95%
confidence interval and assuming a one-day holding period. As of September 30, 2005, the
collateral required to support Edison Mission Marketing & Trading's transactions was
approximately $90 million. EME's management pays particular attention to the risk management
of these activities, because income from them will vary substantially from period to period
depending on market conditions.

Impairment Loss on Equity Method Investment

During the third quarter of 2005, MEHC fully impaired its equity investment in the March
Point project following an updated forecast of future project cash flows. The March Point
project is a 140 MW natural gas-fired cogeneration facility located in Anacortes,
Washington, in which a subsidiary of MEHC owns a 50% partnership interest. The March Point
project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements
that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil)
under a steam supply agreement that also expires in 2011. March Point purchases a portion of
its fuel requirements under long-term contracts with the remaining requirements purchased at
current market prices. March Point's power sales agreements do not provide for a price
adjustment related to the project's fuel costs. During the third quarter of 2005, long-term
natural gas prices increased substantially, thereby adversely affecting the future cash
flows of the March Point project. As a result, MEHC concluded that its investment was
impaired and recorded a $55 million charge during the third quarter of 2005.


Page 45



                              SOUTHERN CALIFORNIA EDISON COMPANY

SCE:  LIQUIDITY

SCE's liquidity is primarily affected by under- or over-collections of energy
procurement-related costs, collateral requirements associated with power-purchase contracts,
and access to capital markets or external financings.  At September 30, 2005, SCE's credit
and long-term senior secured issuer ratings from Standard & Poor's and Moody's Investors
Service were BBB+ and A3, respectively.  At September 30, 2005, SCE's short-term (commercial
paper) credit ratings from Standard & Poor's and Moody's Investors Service were A2 and P2,
respectively.

As of September 30, 2005, SCE had cash and equivalents of $484 million ($117 million of
which was held by SCE's consolidated Variable Interest Entities (VIEs)).  As of September
30, 2005, long-term debt, including current maturities of long-term debt, was $5.34
billion.  In February 2005, SCE replaced its $700 million credit facility with a $1.25
billion senior secured 5-year revolving credit facility.  The security pledged (first and
refunding mortgage bonds) for the new facility can be removed at SCE's discretion.  If SCE
chooses to remove the security, the credit facility's rating and pricing will change to an
unsecured basis per the terms of the credit facility agreement.   As of September 30, 2005,
SCE's credit facility supported $12 million in letters of credit, leaving $1.24 billion
available under the credit facility.

As discussed in "SCE:  Regulatory Matters--Generation and Power Procurement--Energy Resource
Recovery Account Proceedings," the CPUC established the Energy Resource Recovery Account
(ERRA) as the rate-mechanism to track and recover energy procurement-related costs.  As of
September 30, 2005, the ERRA was overcollected by $112 million.

SCE has entered into margining agreements for power and gas trading activities to support
the risk of nonperformance.  SCE's margin deposit requirements can vary depending upon the
level of unsecured credit extended by counterparties and brokers, the California Independent
System Operator (ISO) credit requirements, changes in market prices relative to contractual
commitments, and other factors.  At September 30, 2005, SCE had deposited $130 million in
cash with a broker in margin accounts in support of gas trading activities and had deposited
$31 million (comprised of $19 million in cash and $12 million in letters of credit) with
counterparties in support of power-purchase agreements and to enter into transactions for
imbalance energy through the ISO.  Deposits with counterparties and brokers earn interest at
various rates.  The $149 million of cash deposited with brokers and counterparties are
reflected in the caption "Margin and Collateral Deposits" on the balance sheet.

SCE's estimated cash outflows, during the twelve-month period following September 30, 2005,
consist of:

o   Debt maturities of approximately $597 million, including approximately $247 million
    of rate reduction notes that are due at various times in 2005 and 2006, but which have a
    separate cost recovery mechanism approved by state legislation and CPUC decisions;

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

o   Dividend payments to SCE's parent company.  SCE made a $71 million dividend payment
    to Edison International on each of April 28, 2005, July 28, 2005 and September 30, 2005;


Page 46



o   Fuel and procurement-related costs; and

o   General operating expenses.

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

SCE is experiencing significant growth in actual and planned capital expenditures to replace
and expand its distribution and transmission infrastructure, and to construct and replace
generation assets.  In April 2005, the Finance Committee of SCE's Board of Directors
approved a $10.1 billion capital budget and forecast for the period 2005-2009, an increase
of approximately $700 million over the $9.4 billion amount adopted in October 2004.  The
increase is mainly due to acceleration of spending in 2005-2009 on several transmission
projects, as well as additional expenditures associated with the replacement of the steam
generator and pressurizer at San Onofre.  All amounts exceeding the October 2004 forecast
are included in either the 2006 GRC or separate regulatory filings for major generation and
transmission projects.  Pursuant to the approved capital budget and forecast, SCE expects
its capital expenditures to be $1.8 billion, $1.9 billion and $2.1 billion in 2005, 2006 and
2007, respectively.

SCE has debt covenants that require certain interest coverage, interest and preferred
dividend coverage, and debt to total capitalization ratios to be met.  At September 30,
2005, SCE was in compliance with these debt covenants.

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

SCE:  MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and
volume, and counterparty credit.  Fluctuations in interest rates can affect earnings and
cash flows.  However, fluctuations in commodity prices and volumes, and counterparty credit
losses temporarily affect cash flows, but generally should not affect earnings due to
recovery through regulatory mechanisms.  SCE uses derivative financial instruments to manage
its market risks, but does not use these instruments for speculative purposes.  See "SCE:
Market Risk Exposures" in the year-ended 2004 MD&A for a complete discussion of SCE's market
risk exposures.

SCE:  REGULATORY MATTERS

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

o   generation and power procurement;

o   transmission and distribution; and

o   other regulatory matters.


Page 47



Generation and Power Procurement

Energy Resource Recovery Account Proceedings

In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to
track and recover SCE's:  (1) fuel costs related to its generating stations;
(2) purchased-power costs related to cogeneration and renewable contracts;
(3) purchased-power costs related to existing interutility and bilateral contracts that were
entered into before January 17, 2001; and (4) new procurement-related costs incurred on or
after January 1, 2003 (the date on which the CPUC transferred back to SCE the responsibility
for procuring energy resources for its customers).  SCE recovers these costs on a
cost-recovery basis, with no markup for return or profit.  SCE files annual forecasts of the
above-described costs that it expects to incur during the following year.  As these costs
are subsequently incurred, they will be tracked and recovered through the ERRA, but are
subject to a reasonableness review in a separate annual ERRA application.  If the ERRA
overcollection or undercollection exceeds 5% of SCE's prior year's generation revenue, the
CPUC has established a "trigger" mechanism, whereby SCE can request an emergency rate
adjustment in addition to the annual forecast and reasonableness ERRA applications.

ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004

On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its
procurement-related costs for calendar year 2004 to be reasonable, and that its contract
administration and economic dispatch operations during 2004 complied with its CPUC-adopted
procurement plan.  In addition, SCE requested recovery of approximately $13 million
associated with Nuclear Unit Incentive Procedure rewards for efficient operation of the Palo
Verde Nuclear Generating Station (Palo Verde) and approximately $7 million in administrative
and general costs incurred to carry out the CPUC's directive to begin procuring energy
supplies on January 1, 2003 following the California energy crisis.  In August 2005, the
ORA recommended a $16 million disallowance associated with SCE's 2004 sales of energy in the
hour-ahead market, alleging that the price at which SCE sold its hour-ahead energy was
unreasonable.  SCE submitted its rebuttal testimony on September 15, 2005 contesting the
ORA's recommendation.  In addition, in its opening briefs, the ORA recommended that SCE be
penalized $37 million for allegedly having failed to prove that its least-cost dispatch
operations complied with the methodology presented by the ORA.  SCE believes the
disallowance and recommended penalty are without merit.  A decision is expected by the end
of 2005.

2005 ERRA Forecast

On March 17, 2005, the CPUC issued a final decision adopting SCE's requested ERRA revenue
requirement of $3.3 billion for the 2005 calendar year, an increase of $1 billion over the
2004 revenue requirement.  The increase was primarily attributable to increasing procurement
costs, in part because SCE must procure additional energy and capacity in 2005 to replace
energy and capacity that had been provided by a major California Department of Water
Resources (CDWR) contract that terminated in December 2004.  In addition, the increase was
attributable to additional capacity and associated energy costs resulting from increasing
SCE's reserve margin to fulfill the CPUC's requirement of a 15% to 17% planning reserve and a
substantially higher forecasted ERRA undercollected balance as of December 31, 2004 than the
balance included in 2004 rate levels.

2006 ERRA Forecast

SCE submitted an ERRA forecast application on August 1, 2005, in which it forecasted a
procurement-related revenue requirement for the 2006 calendar year of $3.8 billion, an
increase of $509 million over SCE's adopted 2005 ERRA proceeding revenue requirement.  The
increase was mainly attributable to load growth and resource adequacy requirements (see the
discussion under "--Generation Procurement


Page 48



Proceedings--Resource Adequacy Requirements" included in the year-ended 2004 MD&A), the
unavailability of SCE's Mohave coal-fired generating station (Mohave) after December 31,
2005, and its replacement with higher-cost natural gas generation (see "--Mohave Generating
Station and Related Proceedings").

In addition, the 2006 ERRA forecast application requested that the CPUC consolidate all
CPUC-authorized revenue requirements, including the revenue requirements from the 2006 ERRA
forecast application, the 2006 GRC (see "--Transmission and Distribution--2006 General Rate
Case Proceeding") and CDWR-related proceedings (see "--CDWR-Related Matters--CDWR Power
Purchases and Revenue Requirement Proceeding"), for recovery through rates beginning
January 1, 2006.  SCE's current system average rate for bundled service customers is
12.6(cent)-per-kilowatt-hour (kWh).  SCE expects the 2006 system average rate for bundled service
customers to range between 14.3(cent)-per-kWh and 15.0(cent)-per-kWh.

CDWR-Related Matters

CDWR Power Purchases and Revenue Requirement Proceedings

As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in
the year-ended 2004 MD&A, in December 2004, the CPUC issued its decision on how the CDWR's
power charge revenue requirement for 2004 through 2013 would be allocated among the
investor-owned utilities.  On June 30, 2005, the CPUC granted, in part, San Diego Gas &
Electric's (SDG&E) petition for modification of the December 2004 decision.  The June 30,
2005 decision adopted a methodology that retains the cost-follows-contract allocation of the
avoidable costs, and allocates the unavoidable costs associated with the contracts:  42.2%
to Pacific Gas and Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to
SDG&E's customers.  This newly adopted allocation methodology decreases the total costs
allocated to SDG&E's customers and increases the total costs allocated to SCE's and PG&E's
customers, relative to the December 2004 decision.

The burden of the additional costs, relative to the December 2004 decision, is borne almost
entirely by SCE's customers for the period 2004-2009, and then shifts almost entirely to
PG&E's customers in 2010-2011, when contract deliveries of CDWR energy to PG&E's customers
falls by approximately 75%.  SCE, joined by The Utility Reform Network (TURN) and the
California Large Electricity Consumers Association (CLECA), filed a petition for
modification of the June 30, 2005 decision, seeking to levelize the allocation of additional
costs under the decision to SCE's and PG&E's customers and requesting clarification on other
implementation issues.  On November 2, 2005, the CPUC issued a proposed decision denying the
petition for modification.  The final decision is expected in December 2005.

The CDWR has submitted its 2006 revenue requirement determination to the CPUC for
implementation.  The CPUC must issue its final decision implementing the 2006 CDWR revenue
requirement in December 2005.  The November 2, 2005 proposed decision mentioned above also
implement the CDWR's 2006 revenue requirement.  A final decision is expected in December
2005.

Amounts billed to SCE's customers for electric power purchased and sold by the CDWR are
remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no
impact on SCE's earnings.  In SCE's 2006 ERRA forecast proceeding, SCE is proposing to
consolidate the impact of the June 30, 2005 decision, as well as other CDWR revenue
requirement changes, with other changes in rates beginning on January 1, 2006 (see "--Energy
Resource Recovery Account Proceedings--2006 ERRA Forecast").


Page 49



Generation Procurement Proceedings

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

Procurement Plan

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

Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's
procurement-related transactions associated with serving the demands of its bundled
electricity customers were in conformance with SCE's adopted short-term procurement plan.
SCE has submitted quarterly compliance filings covering the period from January 1, 2003
through September 30, 2005.  The CPUC issued one resolution approving SCE's first compliance
report for the period January 1, 2003 to March 31, 2003 and issued a resolution approving
the other transactions for calendar year 2003 in a June 16, 2005 resolution.

Resource Adequacy Requirements

Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving
entities in California have an obligation to procure sufficient resources to meet their
customers' needs.  On October 27, 2005, the CPUC issued a decision clarifying the January
2004 decision and a subsequent October 2004 decision on resource adequacy requirement.  The
October 2005 decision requires load-serving entities to ensure that adequate resources have
been contracted to meet that entity's peak forecasted energy resource demand and an
additional planning reserve margin of 15-17% in every month of the year, beginning in June
2006.  The October 2005 decision requires that SCE demonstrate that it has contracted 90% of
its June-September 2006 resource adequacy requirement by January 2006.  By the end of May
2006, SCE will be required to fill out the remaining 10% of its resource adequacy
requirement one month in advance of expected need.  A month-ahead showing demonstrating that
SCE has procured 100% of its resource adequacy requirement will be required every month
thereafter.  The October 2005 decision also adopted limits on the amount of a
portfolio-sourced, as opposed to unit-specific, firm energy contract that can be used to
meet a load serving entity's resource adequacy requirement.  Under the October 2005
decision, a load-serving entity can have no more than 75% of its portfolio of resource
adequacy resources met by such contracts in 2006, no more than 50% met by such contracts in
2007, and no more than 25% met by such contracts in 2008.  No such contracts can be used to
meet a load-serving entities' resource adequacy requirement after December 31, 2008.  The
October 2005 decision also clarified that the CDWR contracts, some of which are firm energy
contracts, are not subject to the limitations.  Additionally, the October 2005 decision
adopted minimum elements for contracts upon which load-serving entities' may rely to meet
their resource adequacy obligations.  Further, the October 2005 decision deferred
implementation of a local resource adequacy requirement until 2007.  Lastly, the October
2005 decision adopted penalties of 150% of the cost of new monthly capacity for load serving
entities that fail to acquire sufficient resources in 2006, and a 300% penalty in


Page 50



2007 and beyond.  SCE expects to meet its resource adequacy requirements by the deadlines
set forth in the decision.

In July 2005, SCE issued a Request for Offers (RFO) whereby SCE solicited offers from sellers in
the ISO control area for products that provide capacity, energy and resource adequacy
benefits.  In early October 2005, SCE executed a number of contracts for these products for
terms up to 56 months.

Procurement of Renewable Resources

SCE's 2005 renewable procurement plan for 2005 through 2014 was filed on March 7, 2005.  On
July 21, 2005, the CPUC issued a decision approving SCE's renewable procurement plan for
2005 and deferred a ruling on SCE's renewable procurement plan for 2006 through 2014.  This
decision also approved the methodology advocated by SCE for determining the amount by which
reported renewable procurement should be adjusted to reflect line losses.  On October 6,
2005, the CPUC issued a decision conditionally approving SCE's renewable procurement plan
for 2006 through 2014.

The CPUC's July 21, 2005 decision referenced above states that SCE cannot count procurement
from certain geothermal facilities towards its 1% annual renewable procurement requirement,
unless such procurement is from production certified as "incremental" by the California
Energy Commission.  A 2003 CPUC decision had held that SCE could count procurement from
these geothermal facilities toward its 1% annual renewable procurement requirement.  SCE is
currently pursuing reconsideration of the July 21, 2005 decision.

The geothermal facilities have applied to the California Energy Commission for certification
of a portion of the facilities' production as "incremental."  A decision from the California
Energy Commission is expected in November 2005.  It is not clear whether any of the
facilities' production will be certified as "incremental" or how much, if any, of the
"incremental" production from the facilities will be allocated to SCE's procurement under its
contract with the facilities if the California Energy Commission certification is granted.

Depending upon the amount, if any, of California Energy Commission certified "incremental"
production allocated to SCE's procurement under its contract and the manner in which the
CPUC implements its flexible rules for compliance with renewable procurement obligations,
the CPUC could deem SCE to be out of compliance with its statutory renewable procurement
obligations for the years 2003, 2004 and 2005, and therefore SCE could be subject to
penalties for those years.  In addition, the California Energy Commission's and the CPUC's
treatment of the production from the geothermal facilities could result in SCE being deemed
to be out of compliance with its obligations for 2006.  The maximum penalty for
non-compliance is $25 million per year.  To comply with renewable procurement mandates and
avoid penalties for years beyond 2006, SCE will either need to sign new contracts and/or
extend existing renewable qualifying facility (QF) contracts.

SCE received bids for renewable resource contracts in response to a solicitation it made in
August 2003 and conducted negotiations with bidders regarding potential procurement
contracts.  On June 30, 2005, the CPUC issued a resolution approving six renewable contracts
resulting from the solicitation.  On August 11, 2005 and August 31, 2005, SCE submitted
advice letters seeking CPUC approval of two additional renewable contracts resulting from
the solicitation.

The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new request
for proposals for additional renewable contracts.  SCE issued its 2005 request for proposals
for renewable contracts on September 2, 2005.  Proposals for renewable contracts have been
received and are being evaluated.


Page 51



Request for Offers for New Generation Resources

According to California state agencies, beginning in 2006, there is a need for new
generation capacity in southern California.  SCE has issued an RFO for new generation
resources.  SCE solicited offers for power-purchase agreements lasting up to 10 years from
new generation facilities with delivery under the agreement beginning between June 1, 2006
and August 1, 2008.  SCE filed an application with the CPUC seeking approval of the RFO and
the power-purchase agreements executed under the RFO.  SCE sought recovery of the costs of
the contracts, through the FERC-jurisdictional rates, from all affected customers.  In
addition, SCE sought CPUC assurance of full cost recovery in CPUC-approved rates, if the
FERC denies any recovery.  On September 9, 2005, the CPUC issued a scoping memorandum
rejecting SCE's proposal.  Since the scoping memorandum did not provide a mechanism for SCE
to secure new generation on behalf of these customers, SCE terminated its RFO and moved to
stay the proceeding and withdraw the CPUC application.  A stay was granted on September 22,
2005.  The motion to withdraw is still pending.

Mohave Generating Station and Related Proceedings

As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the
year-ended 2004 MD&A, the CPUC issued a final decision in December 2004 on SCE's application
regarding the post-2005 operation of Mohave, which is partly owned by SCE.

In parallel with and since the conclusion of the CPUC proceeding, negotiations, water
studies, and other efforts have continued among the relevant parties in an attempt to
resolve Mohave's post-2005 coal and water supply issues.  Although progress has been made
with respect to certain issues, no complete resolution has been reached to date.  Because
resolution has not been reached and because of the lead times required for installation of
certain pollution-control equipment and other upgrades necessary for post-2005 operation, it
appears probable that Mohave will temporarily shut down at the end of 2005, and a permanent
shutdown remains possible.  The outcome of the efforts to resolve the post-2005 coal and
water supply issues is not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's
long-term resource plan.  SCE's 2006 ERRA forecast application assumes Mohave is an
unavailable resource for power for 2006 (see "--Energy Resource Recovery Account
Proceedings--2006 ERRA Forecast" for further discussion).  Because SCE expects to recover
Mohave shut-down costs in future rates, the outcome of this matter is not expected to have a
material impact on earnings.

San Onofre Nuclear Generating Station

As discussed in the "San Onofre Nuclear Generating Station" disclosure in the year-ended
2004 MD&A, there are several issues related to the operation and maintenance of San Onofre
Units 2 and 3.  The following are new developments with respect to San Onofre.

San Onofre Steam Generators

On October 31, 2005, an assigned administrative law judge issued a proposed decision on the
reasonableness of the proposed replacement of the San Onofre Units 2 and 3 steam generators
and the establishment of appropriate ratemaking for recovery in rates of the reasonable cost
of the replacement project.  The proposed decision found that:  (1) steam generator
replacement is "marginally cost-effective"; (2) $680 million ($569 million for replacement
steam generator installation and $111 million for removal and disposal of the original steam
generators) is a reasonable estimate; (3) SCE will not be allowed to recover costs above
$680 million for steam generator replacement; (4) SCE will be required to file an
application for reasonableness review of steam generator replacement upon completion of that
work; (5) SCE can recover 20% of the estimated costs of removal and disposal of the steam
generators


Page 52



through depreciation during 2006-2011; (6) SCE will be prohibited from recovering San Onofre
Units 2 and 3 O&M costs above levels forecast in its test year 2006 GRC forecast plus 10%
through 2022; (7) SCE will be prohibited from recovering San Onofre Units 2 and 3 capital
expenditures above levels forecast in its test year 2006 GRC plus 25% through 2022; and (8)
SCE acted reasonably in relation to the issue of potential claims against the manufacturer
of the steam generators or its successors.  Opening comments on the proposed decision are
due November 21, 2005, and reply comments are due November 28, 2005.  The CPUC may adopt,
reject, or modify a proposed decision.  SCE anticipates that the CPUC will issue a final
decision by early next year.  If the CPUC authorizes SCE to go forward with steam generator
replacement under terms that reasonably compensate SCE for the risk of operating San Onofre
Units 2 and 3, SCE will recover costs that are reasonably incurred as part of the steam
generator replacement capital costs.  By the time of the expected final decision, SCE
anticipates that it will have incurred approximately $80 million in steam generator
fabrication and associated project costs.  SCE will seek recovery of these costs in the
event that the CPUC does not authorize SCE to go forward with steam generator replacement
under terms that reasonably compensate it for the risk that it undertakes by operating San
Onofre Units 2 and 3.  However, there is no assurance that the CPUC would approve such a
request.

San Onofre Reactor Vessel Heads

During the ongoing San Onofre Unit 3 refueling outage in the fourth quarter of 2004, SCE
conducted a planned inspection of the Unit 3 reactor vessel head and found indications of
degradation.  Although the indications of degradation were far below the level at which
leakage would occur, SCE repaired these indications of degradation using readily available
tooling and a Nuclear Regulatory Commission-approved repair technique.  While this was San
Onofre's first experience of this kind of degradation to the reactor vessel head, the
detection and repair of similar degradation is now common in the industry.  SCE plans to
replace the Unit 2 and 3 reactor vessel heads during the planned refueling outages in
2011-2012.

Palo Verde Steam Generators

Palo Verde Steam Generator Replacement

The steam generators at Palo Verde, in which SCE owns a 15.8% interest, have material
properties that are similar to the San Onofre units.  During 2003, the Palo Verde Unit 2
steam generators were replaced.  In addition, the Palo Verde owners have approved the
manufacture and installation of steam generators in Units 1 and 3.  On October 8, 2005, Palo
Verde Unit 1 commenced an outage during which the steam generators will be replaced.  Unit 1
will return to service after the successful completion of its planned refueling and
maintenance outage including steam generator replacement.  The outage is scheduled to last
75 days.  The Palo Verde owners expect that replacement steam generators will be installed
in Unit 3 in the 2007 to 2008 time frame.  SCE's share of the costs of manufacturing and
installing all the replacement steam generators at Palo Verde is estimated to be about
$115 million; SCE expects to recover these costs through the rate-making process.

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


Page 53



Transmission and Distribution

2006 General Rate Case Proceeding

On December 21, 2004, SCE filed its application for a 2006 GRC, requesting a 2006 base rate
revenue requirement of $4.06 billion, an increase of $370 million over SCE's base rate
revenue.  The increase is primarily for capital-related expenditures to accommodate
infrastructure replacement, and customer and load growth.  The requested increase is also
necessary to fund substantially higher O&M expenses, particularly in SCE's transmission and
distribution business unit.  SCE also requested that the CPUC authorize the continuation of
SCE's existing post-test year rate-making mechanism, which would result in further base rate
revenue increases of $159 million above the 2006 request in 2007, and $122 million above the
2007 request in 2008.

As part of the GRC process, on April 15, 2005, the ORA submitted testimony proposing
adjustments to reduce SCE's requested 2006 base rate revenue requirement to $3.55 billion.
In addition, the ORA recommended that an additional year, 2009, be added to SCE's GRC cycle
and that the CPUC use a Consumer Price Indexed (CPI) method, applied to the test year
revenue requirement, to determine base rate revenue adjustments in the attrition years (2007
and 2008).  SCE had used a budget-based approach to projected capital additions in the
attrition years in its filing as previously authorized in the 2003 GRC decision.

During the course of the GRC proceeding, SCE agreed to certain revisions to its request,
updated the revenue requirement for the 2005 cost of capital, and incorporated a second
refueling and maintenance outage in the O&M expense forecast for San Onofre in 2006.  In
addition, on September 26, 2005, SCE submitted updated testimony and revised its requested
revenue requirement to reflect the current forecast of 2006-2008 escalation rates, a pending
postage rate increase, revised tax depreciation rates, and the company's current scenario
for costs to operate the Mohave Generating Station.  SCE's revised requested 2006 base rate
revenue requirement is $3.96 billion, an increase of $325 million over SCE's 2005 base rate
revenue, as set forth in an exhibit on October 17, 2005.  SCE also proposed revised base
rate revenue increases of $108 million for 2007 and $113 million for 2008.

During the course of the GRC proceeding, the ORA revised its proposed 2006 base rate revenue
requirement for SCE to also incorporate a second refueling outage in the O&M expense
forecast for San Onofre in 2006 among other changes.  The ORA's current proposed 2006 base
rate revenue requirement is $3.59 billion, with further base rate increases of $24 million
for 2007 and $75 million for 2008. In addition, several intervenors have proposed further
adjustments, totaling $230 million to reduce SCE's requested 2006 rate base revenue
requirement.

On August 2, 2005 SCE filed a motion requesting the establishment of a GRC Memo Account
which would make the GRC decision retroactive to January 9, 2006, or the first CPUC meeting
in January 2006, whichever is earlier.

A final CPUC decision is expected in January 2006.  SCE cannot predict with certainty the
final outcome of SCE's GRC application.

2006 Cost of Capital

On May 9, 2005, SCE filed an application requesting that the CPUC authorize a return on
SCE's common equity and an overall rate of return for SCE's CPUC-jurisdictional assets for
2006.  In its application, SCE requested that the CPUC maintain its 2005 authorized
rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common
equity for 2006.  SCE's application also requested that the CPUC authorize SCE's 2006 cost
of long-term debt of 6.53%, cost of preferred equity


Page 54



of 6.43% and a return on common equity of 11.80%.  A proposed decision is scheduled for
November 15, 2005, and a final CPUC decision is anticipated on or before December 15, 2005.
CPUC adoption of SCE's application request would result in a projected $10 million increase
in its annual revenue requirements.  Based on the September 2005 economic forecasts of
average long-term utility bond and other interest rates for 2006, adoption of SCE's
application request is expected to now result in a projected $10 million decrease in SCE's
annual revenue requirements with an anticipated 2006 cost of long-term debt of 6.17% and
cost of preferred equity of 6.09%.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the
Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper
allocation and characterization of certain charges.  The order reversed an arbitrator's
award that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal
Congestion costs and allocation of those charges to Scheduling Coordinators (SCs) in the
affected zone within the ISO transmission grid.  The April 20, 2004 order directed the ISO
to shift the costs from SCs in the affected zone to the responsible Participating
Transmission Owner, SCE, and to do so within 60 days of the April 20, 2004 order.  Under the
April 20, 2004 order, which was stayed pending resolution of SCE's rehearing request, SCE
would be charged a certain amount as the Participating Transmission Owner but also would be
credited in its role as an SC and through the California Power Exchange, to the extent it
acted as SCE's SC.  On March 30, 2005, the FERC issued an Order Denying Rehearing.  SCE
obtained an extension of the stay pending resolution of the appeal SCE filed with the Court
of Appeals for the D.C. Circuit.  A briefing schedule has been set in the appeal with SCE's
opening brief due on December 23, 2005.  The potential net impact on SCE is estimated to be
approximately $20 million to $25 million, including interest.  SCE filed a request for
clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the
disputed costs in SCE's reliability services rates.  On June 8, 2005, the FERC denied the
clarification, noting that during the appeal, the FERC's order is stayed, and therefore SCE
is not required to pay at this time.  SCE may seek recovery in its reliability service rates
of the costs should SCE be required to pay these costs.

Transmission Proceeding

In August and November 2002, the FERC issued opinions affirming a September 1999
administrative law judge decision to disallow, among other things, recovery by SCE and the
other California public utilities of costs reflected in network transmission rates
associated with ancillary services and losses incurred by the utilities in administering
existing wholesale transmission contracts after implementation of the restructured
California electric industry.  SCE has incurred approximately $80 million of these
unrecovered costs since 1998.  In addition, SCE has accrued interest on these unrecovered
costs.  The three California utilities appealed the decisions to the Court of Appeals for
the Federal Circuit.  On July 12, 2005, the Court of Appeals for the Federal Circuit vacated
the FERC's August and November 2002 orders, and remanded the case to the FERC for further
proceedings.  SCE believes that the Court of Appeals for the Federal Circuit's decision
increases the likelihood that it will recover these costs.

Wholesale Electricity and Natural Gas Markets

As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in the
year-ended 2004 MD&A, SCE is participating in several related proceedings seeking recovery
of refunds from sellers of electricity and natural gas who allegedly manipulated the
electric and natural gas markets.

El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of
parties (including SCE, PG&E, the State of California and various consumer class action
representatives) settling various claims stated in proceedings at the FERC and in San Diego
County Superior Court that


Page 55



El Paso had manipulated interstate capacity and engaged in other anticompetitive behavior in
the natural gas markets in order to unlawfully raise gas prices at the California border in
2000-2001.  The United States District Court has issued an order approving the stipulated
judgment and the settlement agreement has become effective.  Pursuant to a CPUC decision,
SCE was required to refund to customers amounts received under the terms of the El Paso
settlement (net of legal and consulting costs) through its ERRA mechanism.  In June 2004,
SCE received its first settlement payment of $76 million.  Approximately $66 million of this
amount was credited to purchased-power expense, and was refunded to SCE's ratepayers through
the ERRA over the following twelve months, and the remaining $10 million was used to offset
SCE's incurred legal costs.  El Paso has elected to prepay the additional settlement
payments due over a 20-year period and, as a result, SCE received $66 million in May 2005.
Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue
requirement allocated to SCE in proportion to SCE's share of the CDWR's power charge revenue
requirement.

On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement
terms with Mirant Corporation and a number of its affiliates (collectively Mirant), all of
whom are debtors in Chapter 11 bankruptcy proceedings pending in Texas.  Among other things,
the settlement terms provide for cash and equivalent refunds totaling $320 million, of which
SCE's allocated share is approximately $68 million.  The settlement also provides for an
allowed, unsecured claim totaling $175 million in the bankruptcy of one of the Mirant
parties, with SCE being allocated approximately $33 million of the unsecured claim.  The
actual value of the unsecured claim will be determined as part of the resolution of the
Mirant parties' bankruptcies.  The Mirant settlement was approved by the FERC on April 13,
2005 and by the bankruptcy court on April 15, 2005.  In April and May 2005, SCE received its
allocated $68 million in cash settlement proceeds.  SCE continues to hold its $33 million
share of the allowed, unsecured bankruptcy claim.  The Mirant settlement will be refunded to
ratepayers as described below.

On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement
terms with Enron Corporation and a number of its affiliates (collectively Enron), most of
which are debtors in Chapter 11 bankruptcy proceedings pending in New York.  Among other
things, the settlement terms provide for cash and equivalent payments from Enron totaling
approximately $47 million and an allowed, unsecured claim in the bankruptcy against one of
the Enron entities in the amount of $875 million.  SCE's allocable share of both the cash
and allowed claim portions of the settlement consideration has not yet been finally
determined, and the value of an allocable share of the allowed claim will be determined as
part of the resolution of the Enron parties' bankruptcies.  The settlement was approved by
the Enron bankruptcy court on October 20, 2005, but remains subject to approval by the
FERC.  Effective August 24, 2005, the CPUC approved the settlement by entering into an
agreement incorporating its terms.  The Enron settlement proceeds will be refunded to
ratepayers as described below.

On August 12, 2005, SCE, PG&E, SDG&E, several governmental entities and certain other
parties agreed to settlement terms with Reliant Energy, Inc. and a number of its affiliates
(collectively Reliant).  Among other things, the settlement terms provide for Reliant to
provide cash and cash equivalents having a total value of at least $460 million, which would
be in addition to the $65 million in refunds that Reliant was already required to provide
pursuant to prior FERC orders.  SCE expects that its allocable share of the entire
settlement value of $525 million (including the amounts previously ordered by the FERC) will
be approximately $130 million.  The settlement remains subject to FERC approval, which is
anticipated in the first quarter of 2006.  Effective October 12, 2005, the CPUC
approved the settlement by entering into an agreement incorporating its terms.  The Reliant
settlement proceeds will be refunded to ratepayers as described below.

On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy
Settlement Memorandum Account (ESMA) for the purpose of recording the foregoing settlement
proceeds (excluding the El Paso settlement) from energy providers and allocating them in
accordance with the terms of the October 2001 settlement agreement entered into by SCE and
the CPUC which settled SCE's


Page 56



lawsuit against the CPUC.  This lawsuit sought full recovery of SCE's electricity
procurement costs incurred during the energy crisis.  The resolution provides a mechanism
whereby portions of the settlement proceeds recorded in the ESMA will be allocated to
recovery of SCE's litigation costs and expenses in the FERC refund proceedings described
above and a 10% shareholder incentive pursuant to the CPUC litigation settlement agreement.
Remaining amounts for each settlement are to be refunded to ratepayers through the ERRA
mechanism.  In the second quarter of 2005, SCE recorded a $7 million increase to other
nonoperating income as a shareholder incentive related to the Mirant refund received during
the second quarter of 2005.

Schedule Coordinator Tariff Dispute

SCE serves as an SC for Los Angeles Department of Water & Power (DWP) over the
ISO-controlled grid.  In mid-2003, SCE filed a petition asking that the FERC accept a tariff
that provides for a direct pass-through of the FERC-authorized charges incurred by SCE on
the DWP's behalf.  The DWP protested SCE's filing.  The DWP asked the FERC to declare that
SCE was obligated to serve as the DWP's SC without charge.  In late 2003, the FERC accepted
the tariff, subject to refund.  The FERC held that the proposed tariff has not been shown to
be just and reasonable.

In accordance with to the terms of the tariff, SCE issued several invoices for charges to
the DWP.  The DWP has objected to all of the charges but has paid, under protest,
approximately $18 million.  The DWP has protested specific charges totaling approximately $5
million based on its allegations that those specific charges are improper for various
reasons.

The FERC has not issued a final order on this issue.  SCE could be required to refund all or
part of the amounts collected under the tariff.  SCE continues to invoice the DWP.  Monthly
invoices have been averaging approximately $1 million.  SCE cannot predict with certainty
the outcome of the FERC final order.

Other Regulatory Matters

Catastrophic Event Memorandum Account

Fire-Related CEMA

In October and November of 2003, wildfires damaged SCE's electrical infrastructure,
primarily in the San Bernardino Mountains of southern California where an estimated 2,085
power poles, 2,059 services, 371 transformers, 557,033 of overhead conductors and 25,822
feet of underground cable were replaced or repaired.  SCE notified the CPUC that it
initiated a CEMA on October 21, 2003 to track the incremental costs to restore and repair
damage to its facilities.  SCE filed an application with the CPUC on December 2, 2004 to
seek recovery of its fire-related costs over a one-year period commencing January 1, 2006.
In an August 25, 2005 decision, the CPUC approved the settlement agreement between SCE and
the ORA which (1) allows the authorized fire-related CEMA revenue requirement calculation to
be based on approximately $8 million of incremental operations and maintenance expenses and
$20 million of incremental capital plant additions and (2) allows SCE to continue to record
in its fire-related CEMA the revenue requirement associated with these costs, plus accrued
interest, until the effective date of the final decision in SCE's 2006 GRC.  The revenue
requirement recorded in SCE's fire-related CEMA through April 2005 is approximately $12
million.  SCE has forecast the recorded revenue requirement in this account to total
approximately $14 million in December 2005.  SCE expects to recover the costs recorded in
the fire-related CEMA account through a mechanism approved in SCE's 2006 GRC.


Page 57



Holding Company Proceeding and Order Instituting Rulemaking

In April 2001, the CPUC issued an order instituting investigation that reopened the past
CPUC decisions authorizing utilities to form holding companies and initiated an
investigation into, among other things:  (1) whether the holding companies violated CPUC
requirements to give first priority to the capital needs of their respective utility
subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions;
and (3) whether additional rules, conditions, or other changes to the holding company
decisions are necessary.  For a discussion of item (1) above, see the "SCE:  Regulatory
Matters--Other Regulatory Matters--Holding Company Proceeding" disclosure in the year-ended
2004 MD&A.

On May 5, 2005, the CPUC issued a final decision that closed the proceeding.  However,
because the CPUC closed the proceeding without addressing some of the issues the proceeding
raised (such as the appropriateness of the large utilities' holding company structure and
dividend policies), the CPUC may rule on or investigate these issues in the future.

On October 27, 2005, the CPUC issued an order instituting rulemaking (OIR) to allow the CPUC
to re-examine the relationships of the major California energy utilities with their parent
holding companies and non-regulated affiliates.  The OIR was issued in part in response to
the recent repeal of the Public Utility Holding Company Act of 1935.

By means of the OIR the CPUC will consider whether additional rules to supplement existing
rules and requirements governing relationships between the public utilities and their
holding companies and non-regulated affiliates should be adopted.  Any additional rules will
focus on whether (1) the public utilities retain enough capital or access to capital to meet
their customers' infrastructure needs and (2) mitigation of potential conflicts between
ratepayer interests and the interests of holding companies and affiliates that could
undermine the public utilities' ability to meet their public service obligations at the
lowest cost.  The CPUC expects to issue proposed rules in January 2006, and a final decision
is expected in March 2006.

System Reliability Incentive Mechanism

SCE's 2003 GRC decision provided for performance incentives or penalties for differences
between SCE's actual results and CPUC-authorized standards for system reliability measures
beginning in 2004.  In a March 30, 2005 advice letter, SCE reported a $2 million penalty and
recorded an accrual in 2004 for its 2004 results under the modified reliability mechanism.
On April 28, 2005, the CPUC agreed to suspend its review of SCE's advice letter for 2004
results until the CPUC's Consumer Protection and Safety Division has completed its
investigation regarding performance incentive rewards discussed in the 2004 year-ended
MD&A.  Based on preliminary recorded data through September 2005 and a forecast of normal
results through December 2005, SCE projects it will incur a penalty of $26 million under the
reliability performance mechanism for 2005.  The maximum penalty that could be assessed
under the reliability performance mechanism is approximately $40 million.  As a result,
during the third quarter of 2005, SCE recorded an accrual of $26 million that is reflected
in the income statement caption "Other nonoperating deductions."

Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms

Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms

Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain
shareholder incentives for its performance achievements in delivering demand-side management and energy
efficiency programs.  On June 10, 2005, SCE and the ORA executed a settlement agreement for SCE's outstanding
issues concerning SCE shareholder incentives and performance achievements resulting from the demand-side
management, energy efficiency, and low-income energy efficiency programs from program years 1994-2004.  In
addition, the settlement addresses shareholder incentives


Page 58



and performance achievements for program years 1994-1998, anticipated but not yet claimed.  The settlement
agreement recommends, among other things, that SCE be entitled to immediately recover 92% of the total of SCE's
current claims and future claims related to SCE's pre-1998 energy efficiency programs.  SCE's total claim for
program years 1994-2004 made in 2000 through 2008, including interest, franchise fees and uncollectibles, is
approximately $46 million.  On October 27, 2005, the CPUC approved the settlement agreement which found it
reasonable for SCE to recover approximately $42 million of these claims which include all of SCE's outstanding
claims, as well as future claims related to SCE's pre-1998 energy efficiency programs (of which approximately
$9 million has already been collected in rates).  The remaining portion of claims in the amount of $33 million
will be recognized in the fourth quarter of 2005.  As a result of the decision, during the third
quarter of 2005, SCE recognized $14 million of incentives previously awarded for which revenue recognition
was deferred pending final resolution of these matters.  The $14 million is reflected in the income statement
caption "Other nonoperating income."  In addition, $4 million related to interest on the claims was reflected
in the caption "Interest and dividend income."


Page 59



                                MISSION ENERGY HOLDING COMPANY

MEHC:  LIQUIDITY

Introduction

MEHC's liquidity discussion is organized in the following sections:

o   MEHC (parent)'s Liquidity
o   EME's Liquidity
o   Midwest Generation Financing
o   Capital Expenditures
o   MEHC and EME's Credit Ratings
o   Margin, Collateral Deposits and Other Credit Support for Energy Contracts
o   EME's Liquidity as a Holding Company
o   Dividend Restrictions in Major Financings
o   MEHC's Interest Coverage Ratio

MEHC (parent)'s Liquidity

At September 30, 2005, MEHC had cash and cash equivalents of $30 million (excluding amounts
held by EME and its subsidiaries). MEHC's ability to honor its obligations under the senior
secured notes and to pay overhead is substantially dependent upon the receipt of dividends
from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group,
and ultimately Edison International. See "--EME's Liquidity as a Holding
Company--Intercompany Tax-Allocation Agreement." Dividends from EME are limited based on its
earnings and cash flow, terms of restrictions contained in EME's corporate credit facility,
business and tax considerations and restrictions imposed by applicable law. For a
description of material dividend restrictions, see "MEHC:  Liquidity--Dividend Restrictions
in Major Financings" in the year-ended 2004 MD&A.

MEHC is required to offer to repurchase the senior secured notes at par plus interest if
proceeds in excess of $20 million from the sale of assets are not otherwise used to pay debt
or reinvested as permitted under the terms of such notes within twelve months from the date
of sale (on or before December 15, 2005, with respect to the sale of the stock and related
assets of MECIBV). MEHC does not expect to use or reinvest all of the excess proceeds from
the sale within the twelve-month period and, accordingly, MEHC expects to make an offer to
repurchase the senior secured notes in accordance with the terms of the indenture. Because
the senior secured notes currently trade at prices greater than par, MEHC does not currently
expect holders of the senior secured notes to accept its offer.

Dividends to MEHC (parent)

In January 2005, EME made total dividend payments of $360 million to MEHC (parent). A
portion of these payments was used to repay the remaining $285 million of MEHC's term loan
plus interest on January 3, 2005.

EME's Liquidity

At September 30, 2005, EME and its subsidiaries had cash and cash equivalents of
$1.6 billion and EME had available the full amount of borrowing capacity under a $98 million
corporate credit facility. EME's consolidated debt at September 30, 2005 was $3.4 billion.
In addition, EME's subsidiaries had $5.0 billion of long-term lease obligations that are due
over periods ranging up to 30 years.


Page 60



Midwest Generation Financing

On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The
refinancing was effected through the amendment and restatement of Midwest Generation's
existing credit facility, originally entered into April 27, 2004. The existing credit
facility had provided for a $700 million first priority secured institutional term loan due
in 2011 and a $200 million first priority secured revolving credit, working capital facility
due in 2009.

The refinancing consisted of, among other things, a repricing of Midwest Generation's
existing term loan and a new $300 million revolving credit, working capital facility due in
2011. The previously existing $200 million working capital facility remains in place.
Midwest Generation drew in full upon the new $300 million working capital facility at
closing and used the proceeds to pay down an equivalent portion of the existing term loan.
After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR +
2%. The maturity date of the repriced term loan remains 2011. The new working capital
facility, together with the existing working capital facility, shares first lien priority
with the repriced term loan. The new working capital facility carries an interest rate of
LIBOR + 2.25%. The maturity date of the new working capital facility is 2011; however, the
lenders can request to be fully repaid in 2010.

On the day after the closing of the refinancing transaction, EME contributed $300 million in
equity to Midwest Generation, and Midwest Generation used the proceeds of this equity
contribution to repay the loans outstanding under the new working capital facility. Thus,
after completion of the actions outlined herein, Midwest Generation had $343 million
outstanding under its term loan and $500 million of working capital facilities available for
working capital requirements, including credit support for hedging activities. As of
September 30, 2005, approximately $170 million was utilized under these working capital
facilities.

Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to
distribute 75% of excess cash flow (as defined in the credit agreement). In addition, if
equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute
100% of excess cash flow until the aggregate portion of distributions that Midwest
Generation attributes to the equity contribution equals the amount thereof. Accordingly,
Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate
portion of such distributions attributed to the equity contribution made by EME in Midwest
Generation on April 19, 2005 equals $300 million. However, Midwest Generation is required to
make concurrently with each distribution an offer to repay debt in an amount equal to the
excess, if any, of one-third of such distribution over the portion thereof attributed to the
equity contribution. Thus, Midwest Generation will not be required to offer to repay debt
concurrently with a distribution so long as the portion of each distribution attributed to
the April 19, 2005 equity contribution is at least one-third of such distribution.

Capital Expenditures

The estimated capital and construction expenditures of EME's subsidiaries are $14 million
for the final quarter of 2005 and $63 million and $49 million for 2006 and 2007,
respectively. Non-environmental expenditures relate to upgrades to dust
collection/mitigation systems and the coal handling system, ash removal improvements and
various other projects. EME plans to finance these expenditures with existing subsidiary
credit agreements, cash on hand or cash generated from operations. Included in the estimated
expenditures are environmental expenditures of $4 million for the final quarter of 2005,
$8 million for 2006 and $6 million for 2007. The environmental expenditures relate to
environmental projects such as selective catalytic reduction system improvements at the
Homer City facilities.


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MEHC and EME's Credit Ratings

Overview

Credit ratings for MEHC and its subsidiaries, EME, Midwest Generation, LLC and Edison
Mission Marketing & Trading, are as follows:

                                                       Moody's Rating    S&P Rating
---------------------------------------------------------------------------------------
MEHC                                                         B2              CCC+
EME                                                          B1              B+
Midwest Generation, LLC:
   First priority senior secured rating                      Ba3             BB-
   Second priority senior secured rating                     B1              B
Edison Mission Marketing & Trading                        Not Rated          B+
---------------------------------------------------------------------------------------

MEHC cannot provide assurance that its current credit ratings or the credit ratings of its
subsidiaries will remain in effect for any given period of time or that one or more of these
ratings will not be lowered. MEHC notes that these credit ratings are not recommendations to
buy, sell or hold its securities and may be revised at any time by a rating agency.

MEHC does not have any "rating triggers" contained in subsidiary financings that would
result in it or EME being required to make equity contributions or provide additional
financial support to its subsidiaries.

The credit ratings of EME are below investment grade and, accordingly, EME has historically
provided collateral in the form of cash and letters of credit for the benefit of
counterparties for its price risk management and trading activities related to accounts
payable and unrealized losses.

Credit Rating of Edison Mission Marketing & Trading

The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer
City's) ability to enter into trading activities, as defined in the documents, with Edison
Mission Marketing & Trading to sell forward the output of the Homer City facilities if
Edison Mission Marketing & Trading does not have an investment grade credit rating from
Standard & Poor's or Moody's or, in the absence of those ratings, if it is not rated as
investment grade pursuant to EME's internal credit scoring procedures. These documents
include a requirement that the counterparty to such transactions, and EME Homer City, if
acting as seller to an unaffiliated third party, be investment grade. EME currently sells
all the output from the Homer City facilities through Edison Mission Marketing & Trading,
which has a below investment grade credit rating, and EME Homer City is not rated.
Therefore, in order for EME to continue to sell forward the output of the Homer City
facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to
permit EME Homer City to sell directly into the market or through Edison Mission Marketing &
Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance
consistent with the requirements of the sale-leaseback documents. EME has obtained a consent
from the sale-leaseback owner participant that will allow EME Homer City to enter into such
sales, under specified conditions, through December 31, 2006. EME Homer City continues to be
in compliance with the terms of the consent; however, the consent is revocable by the
sale-leaseback owner participant at any time. The sale-leaseback owner participant has not
indicated that it intends to revoke the consent; however, there can be no assurance that it
will not do so in the future. Revocation of the consent would not affect trades between
Edison Mission Marketing & Trading and EME Homer City that had been entered into while the
consent was still in effect. EME is permitted to sell the output of the Homer City
facilities into the spot market at any time.  See "MEHC:


Page 62



Market Risk Exposures--Commodity Price Risk--Energy Price Risk Affecting Sales from the Homer
City Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into energy contracts (including forward contracts, transmission
contracts and futures contracts), EME's subsidiary, Edison Mission Marketing & Trading, has
entered into agreements to support the risk of nonperformance. At September 30, 2005, Edison
Mission Marketing & Trading had deposited $516 million in cash with brokers in margin
accounts in support of futures contracts and had deposited $210 million with counterparties
in support of forward energy and transmission contracts. These margin and collateral
deposits are used in support of EME's price risk management and energy trading activities.
The margin and collateral deposits generally earn interest at a rate that approximates the
Federal Funds Rate. In addition, EME has issued letters of credit of $6 million in support
of commodity contracts at September 30, 2005.

Margin and collateral deposits increased substantially during the third quarter of 2005 due
to higher wholesale energy prices and increased megawatt hours hedged. Future cash
collateral requirements may be higher than the margin and collateral requirements at
September 30, 2005, if wholesale energy prices increase further. Using the amount of energy
contracts outstanding at September 30, 2005, EME estimates that margin and collateral
requirements could increase by approximately $300 million using a 95% confidence interval
and an internal model estimate using historical volatility.

Midwest Generation has $500 million in credit facilities to support margin requirements
specifically related to contracts entered into by Edison Mission Marketing & Trading related
to the Illinois plants. At September 30, 2005, Midwest Generation has borrowed $165 million
under these credit facilities to finance margin advances to Edison Mission Marketing &
Trading of $316 million. The balance of the margining advances by Midwest Generation was
provided through cash on hand. In addition, EME has cash on hand and a $98 million working
capital facility to provide credit support to subsidiaries. See "--EME's Liquidity" for
further discussion.

EME's Liquidity as a Holding Company

Overview

At September 30, 2005, EME had corporate cash and cash equivalents of $1.3 billion to meet
liquidity needs. See "--EME's Liquidity." EME had no borrowings outstanding or letters of
credit outstanding on the $98 million secured line of credit at September 30, 2005. Cash
distributions from EME's subsidiaries and partnership investments, and unused capacity under
its corporate credit facility represent EME's major sources of liquidity to meet its cash
requirements. The timing and amount of distributions from EME's subsidiaries may be affected
by many factors beyond its control. See "--Dividend Restrictions in Major Financings."

EME's secured corporate credit facility provides credit available in the form of cash
advances or letters of credit. In addition to the interest payments, EME pays a commitment
fee of 0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum
interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such
ratios are defined in the credit agreement). At September 30, 2005, EME met both these ratio
tests.

As security for its obligations under its new corporate credit facility, EME pledged its
ownership interests in the holding companies through which it owns its interests in the
Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project.
EME also granted a security interest in an account into which all distributions received by
it from the Big 4 projects will be deposited. EME is free to use these distributions unless
and until an event of default occurs under its corporate credit facility.


Page 63




At September 30, 2005, EME also had available $88 million under Midwest Generation EME,
LLC's $100 million letter of credit facility with Citibank, N.A., as Issuing Bank, that
expires in December 2006. Under the terms of this letter of credit facility, Midwest
Generation EME is required to deposit cash in a bank account in order to cash collateralize
any letters of credit that may be outstanding under the facility. The bank account is
pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest
Holdings, which in turn owns 100% of Midwest Generation, LLC.

Historical Distributions Received By EME

The following table is presented as an aid in understanding the cash flow of EME's
continuing operations and its various subsidiary holding companies which depend on
distributions from subsidiaries and affiliates to fund general and administrative costs and
debt service costs of recourse debt.

    In millions           Nine Months Ended September 30,             2005           2004
----------------------------------------------------------------------------------------------

    Distributions from Consolidated Operating Projects:
        Edison Mission Midwest Holdings (Illinois plants) )(1)       $ 171         $   --
        EME Homer City Generation L.P. (Homer City facilities)((2))     62             61
        Holding companies of other consolidated generating projects      1             --
    Distributions from Unconsolidated Operating Projects:
        Edison Mission Energy Funding Corp. (Big 4 projects)((3))       93             80
        Sunrise Power Company                                            5              5
        Holding company for Doga project                                17             15
        Holding companies for Westside projects                         13             13
        Holding companies of other unconsolidated operating projects     5              1
----------------------------------------------------------------------------------------------

    Total Distributions                                              $ 367         $  175
----------------------------------------------------------------------------------------------

    ______________

    (1) On October 24, 2005, EME received a $160 million distribution from Midwest Generation.

    (2) On October 3, 2005, EME received a $24 million distribution from Homer City.

    (3) The Big 4 projects are comprised of investments in the Kern River project,
        Midway-Sunset project, Sycamore project and Watson project. Distributions reflect the
        amount received by EME after debt service payments by Edison Mission Energy Funding
        Corp.

Intercompany Tax-Allocation Agreement

MEHC (parent) and EME are included in the consolidated federal and combined state income tax
returns of Edison International and are eligible to participate in tax-allocation payments
with other subsidiaries of Edison International in circumstances where domestic tax losses
are incurred. The right of MEHC (parent) and EME to receive and the amount and timing of
tax-allocation payments is dependent on the inclusion of MEHC (parent) and EME,
respectively, in the consolidated income tax returns of Edison International and its
subsidiaries and other factors, including the consolidated taxable income of Edison
International and its subsidiaries, the amount of net operating losses and other tax items
of MEHC (parent), EME, its subsidiaries, and other subsidiaries of Edison International and
specific procedures regarding allocation of state taxes. MEHC (parent) and EME receive
tax-allocation payments for tax losses when and to the extent that the consolidated Edison
International group generates sufficient taxable income in order to be able to utilize MEHC
(parent)'s tax losses or the tax losses of EME in the consolidated income tax returns for
Edison International and its subsidiaries. Based on the application of the factors cited
above, MEHC (parent) and EME are obligated during periods they generate taxable income to
make payments under the tax-allocation agreements.


Page 64



Dividend Restrictions in Major Financings

General

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and
apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to
satisfy EME's obligations or the obligations of any of its other subsidiaries. However,
unrestricted cash or other assets that are available for distribution may, subject to
applicable law and the terms of financing arrangements of the parties, be advanced, loaned,
paid as dividends or otherwise distributed or contributed to EME or to its subsidiary
holding companies.

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing
arrangements for the twelve months ended September 30, 2005:

          Subsidiary               Financial Ratio         Covenant             Actual
------------------------------------------------------------------------------------------

    Midwest Generation, LLC      Interest Coverage      Greater than or         2.35 to 1
    (Illinois plants)            Ratio                  equal to 1.25 to 1

    Midwest Generation, LLC      Secured Leverage       Less than or            3.06 to 1
    (Illinois plants)            Ratio                  equal to 8.75 to 1

    EME Homer City               Senior Rent Service    Greater than 1.7 to 1   3.03 to 1
    Generation L.P.              Coverage Ratio
    (Homer City facilities)

    Edison Mission Energy        Debt Service           Greater than or         3.14 to 1
    Funding Corp.                Coverage Ratio         equal to 1.25 to 1
    (Big 4 Projects)
------------------------------------------------------------------------------------------


For a more detailed description of the covenants binding EME's principal subsidiaries that
may restrict the ability of those entities to make distributions to EME directly or
indirectly through the other holding companies owned by EME, refer to "MEHC:
Liquidity--Dividend Restrictions in Major Financings" in the year-ended 2004 MD&A.

MEHC's Interest Coverage Ratio

The following details with respect to MEHC's interest coverage ratio are provided as an aid
to understanding the computations set forth in the indenture governing MEHC's senior secured
notes. This information is not intended to measure the financial performance of MEHC and,
accordingly, should not be read in lieu of the financial information set forth in MEHC's
consolidated financial statements. The terms Funds Flow from Operations, Operating Cash Flow
and Interest Expense are as defined in the indenture and are not the same as would be
determined in accordance with generally accepted accounting principles.


Page 65



MEHC's interest coverage ratio equals Funds Flow from Operations divided by Interest Expense
and is comprised of interest income and expense related to its holding company activities
and the consolidated financial information of EME. The following table sets forth MEHC's
interest coverage ratio for the twelve months ended September 30, 2005:

                                                                           September 30,
    In millions                                                                 2005
    ------------------------------------------------------------------- -----------------
    Funds Flow from Operations:
        Operating Cash Flow(1) from Consolidated Operating
    Projects(2):
            Illinois plants                                                  $   366
            Homer City                                                           121
            First Hydro                                                           25
        Other consolidated operating projects                                      3
        Price risk management and energy trading                                 121
        Distributions from unconsolidated Big 4 projects                         121
        Distributions from other unconsolidated operating projects                79
        Interest income                                                           38
        Operating expenses                                                      (118)
    ------------------------------------------------------------------- -----------------
            Total EME funds flow from operations                             $   756
        Operating cash flow from unrestricted subsidiaries                         1
        Funds flow from operations of projects sold                              (30)
        MEHC (parent)                                                             (2)
    ------------------------------------------------------------------- -----------------
            Total funds flow from operations                                 $   725

    Interest Expense:
        EME                                                                  $   262
        EME - affiliate debt                                                       2
        MEHC (parent) interest expense                                           120
        Interest savings on projects sold                                        (29)
    ------------------------------------------------------------------- -----------------
            Total interest expense                                           $   355
    ------------------------------------------------------------------- -----------------
    Interest Coverage Ratio                                                     2.04
    ------------------------------------------------------------------- -----------------

    ______________
    (1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid
        and project debt service.  Operating cash flow does not include capital expenditures
        or the difference between cash payments under EME's long-term leases and lease
        expenses recorded in EME's income statement.  EME expects its cash payments under its
        long-term power plant leases to be higher than its lease expense through 2014.

    (2) Consolidated operating projects are entities of which EME owns more than a 50%
        interest and, thus, include the operating results and cash flows in its consolidated
        financial statements.  Unconsolidated operating projects are entities of which EME
        owns 50% or less and which EME accounts for on the equity method or EME is not the
        primary beneficiary under an accounting interpretation for variable interest entities.

The above interest coverage ratio was determined in accordance with the definitions set
forth in the indenture governing MEHC's senior secured notes. The provisions of the
indenture permit  MEHC, EME and its subsidiaries to incur additional indebtedness, if, after
giving effect to the incurrence of such indebtedness, MEHC's interest coverage ratio exceeds
2.0 to 1 for the immediately preceding four fiscal quarters, or if such additional
indebtedness is permitted debt as specified in the indenture.  In addition, MEHC is
permitted to make dividend if, after giving effect to the dividend, MEHC's interest coverage
ratio exceeds 2.0 to 1 for the immediately preceding four fiscal quarters, subject to
certain additional conditions and the limits specified in the indenture.


Page 66



MEHC:  MARKET RISK EXPOSURES

Introduction

EME's primary market risk exposures are associated with the sale of electricity and capacity
from and the procurement of fuel for its uncontracted generating plants. These market risks
arise from fluctuations in electricity, capacity and fuel prices, emission allowances,
transmission rights, and interest rates. EME manages these risks in part by using derivative
financial instruments in accordance with established policies and procedures. See "MEHC:
Current Developments and "MEHC:  Liquidity--EME's Credit Ratings," as well as "Critical
Accounting Policies and Estimates" in the year-ended 2004 MD&A for a discussion of market
developments and their impact on EME's credit and the credit of its counterparties.

This section discusses these market risk exposures under the following headings:

o   Commodity Price Risk
o   Credit Risk
o   Interest Rate Risk
o   Fair Value of Financial Instruments

Commodity Price Risk

General Overview

EME's revenue and results of operations of its merchant power plants will depend upon
prevailing market prices for capacity, energy, ancillary services, emission allowances or
credits, coal, natural gas and fuel oil, and associated transportation costs in the market
areas where EME's merchant plants are located. Among the factors that influence the price of
energy, capacity and ancillary services in these markets are:

o   prevailing market prices for coal, natural gas and fuel oil, and associated
    transportation costs;

o   the extent of additional supplies of capacity, energy and ancillary services from
    current competitors or new market entrants, including the development of new generation
    facilities;

o   transmission congestion in and to each market area and the resulting differences in
    prices between delivery points;

o   the market structure rules to be established for each market area and regulatory
    developments affecting the market areas;

o   the cost and availability of emission credits or allowances;

o   the availability, reliability and operation of nuclear generating plants, where
    applicable, and the extended operation of nuclear generating plants beyond their
    presently expected dates of decommissioning;

o   weather conditions prevailing in surrounding areas from time to time; and

o   the rate of electricity usage as a result of factors such as regional economic
    conditions and the implementation of conservation programs.

A discussion of commodity price risk for the Illinois plants and Homer City facilities is
set forth below.


Page 67




Energy Price Risk - Introduction

Electric power generated at EME's merchant plants is generally sold into the PJM
Interconnection, LLC (PJM) market.

EME's merchant operations expose it to commodity price risk, which represents the potential
loss that can be caused by a change in the market value of a particular commodity. Commodity
price risks are actively monitored by a risk management committee to ensure compliance with
EME's risk management policies. Policies are in place which define risk tolerance, and
procedures exist which allow for monitoring of all commitments and positions with regular
reviews by EME's risk management committee. Despite this, there can be no assurance that all
risks have been accurately identified, measured and/or mitigated.

In addition to the prevailing market prices, EME's ability to derive profits from the sale
of electricity will be affected by the cost of production, including costs incurred to
comply with environmental regulations. The costs of production of the units vary and,
accordingly, depending on market conditions, the amount of generation that will be sold from
the units is expected to vary from unit to unit.

EME uses a "value at risk" analysis in its daily business to identify, measure, monitor and
control its overall market risk exposure in respect of its Illinois plants, its Homer City
facilities, and its trading positions. The use of value at risk allows management to
aggregate overall commodity risk, compare risk on a consistent basis and identify the risk
factors. Value at risk measures the possible loss over a given time interval, under normal
market conditions, at a given confidence level. Given the inherent limitations of value at
risk and relying on a single risk measurement tool, EME supplements this approach with the
use of stress testing and worst-case scenario analysis for key risk factors, as well as stop
loss limits and counterparty credit exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk
through Edison Mission Marketing & Trading. To the extent that EME does not hedge its
merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot
market price movements. Hedge transactions are primarily implemented through the use of
contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile
Exchange. Hedge transactions are also entered into as forward sales to utilities and power
marketing companies.

The extent to which EME hedges its market price risk depends on several factors. First, EME
evaluates over-the-counter market prices to determine whether sales at forward market prices
are sufficiently attractive compared to assuming the risk associated with spot market sales.
Second, EME's ability to enter into hedging transactions depends upon its, Midwest
Generation's and Edison Mission Marketing & Trading's credit capacity and upon the forward
sales markets having sufficient liquidity to enable EME to identify appropriate
counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois
plants, Midwest Generation is permitted to use its working capital facility and cash on hand
to provide credit support for such hedging transactions entered into by Edison Mission
Marketing & Trading under an energy services agreement between Midwest Generation and Edison
Mission Marketing & Trading. Utilization of this credit facility in support of such hedging
transactions is expected to provide additional liquidity support for implementation of EME's
contracting strategy for the Illinois plants. In the case of hedging transactions related to
the generation and capacity of the Homer City facilities, credit support is provided


Page 68



by EME pursuant to intercompany arrangements between it and Edison Mission Marketing &
Trading. See "--Credit Risk," below.

Energy Price Risk Affecting Sales from the Illinois Plants

Pre-2005 Merchant Sales

Energy generated at the Illinois plants was historically sold under three power purchase
agreements between Midwest Generation and Exelon Generation Company, under which Exelon
Generation was obligated to make capacity payments for the plants under contract and energy
payments for the energy produced by these plants and taken by Exelon Generation. The power
purchase agreements began on December 15, 1999. The capacity payments provided the units
under contract with revenue for fixed charges, and the energy payments compensated those
units for all, or a portion of, variable costs of production. The three power purchase
agreements with Exelon Generation had all been terminated by December 31, 2004.

To the extent that energy and capacity from the Illinois plants was not sold under the power
purchase agreements with Exelon Generation, it was sold on a wholesale basis through a
combination of bilateral agreements, forward energy sales and spot market sales.
Approximately 43% of the energy and capacity sales from the Illinois plants in the first
nine months of 2004 were made on a wholesale basis outside of the power purchase agreements.

Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale
sales of electricity from the Illinois plants were direct "wholesale customers" and broker
arranged "over-the-counter customers." Effective May 1, 2004, the transmission system of
Commonwealth Edison was placed under the control of PJM as the Northern Illinois control
area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, which
linked eastern PJM and the Northern Illinois control areas of the PJM system and improved
access from the Illinois plants into the broader PJM market.  Further, on April 1, 2005, the
Midwest Independent Transmission System Operator (MISO) commenced operation, linking the
MISO footprint, including Illinois, Wisconsin, Indiana, Michigan, and Ohio, in a locational
marginal pricing system similar to that of PJM.

Since the initial expansion of PJM, Midwest Generation sells its power into PJM at spot
prices based upon locational marginal pricing and is no longer required to arrange and pay
separately for transmission when making sales to wholesale buyers within the PJM system.
Hedging transactions related to the generation of the Illinois units are entered into at the
Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM and, with the advent of MISO, at the
Cinergy Hub in MISO.  Because of proximity, the Midwest Generation assets are primarily
hedged with transactions at the Northern Illinois Hub, but from time to time may be hedged
in limited amounts at the AEP/Dayton Hub and the Cinergy Hub.  These trading hubs have been
the most liquid locations for these hedging purposes.  However, hedging transactions which
settle at points other than the Northern Illinois Hub are subject to the possibility of
basis risk.  See "--Basis Risk" below for further discussion.

Following the expansion of the PJM system described above, sales into the expanded PJM, the
primary market currently available to the Illinois plants, replaced sales previously made as
bilateral sales and spot sales "Into ComEd" and "Into AEP." See "MEHC:  Other
Development--Regulatory Matters" in the year-ended 2004 MD&A for a more detailed discussion of
developments regarding Commonwealth Edison's joining PJM, and "--Basis Risk" below for a
discussion of locational marginal pricing.

2005 Merchant Sales

During 2005, electric power generated at the Illinois plants has generally been sold into
the PJM market. The PJM pool has a short-term market, which establishes an hourly clearing
price. The Illinois plants are


Page 69



situated in the new expanded western PJM control area and are physically connected to
high-voltage transmission lines serving this market.

The following table depicts the average historical market prices for energy per
megawatt-hour during the first nine months of 2005 and 2004.

                                                      2005(1)        2004
----------------------------------------------------------------------------
               January                             $  38.36      $   27.88(2)
               February                               34.92          29.98(2)
               March                                  45.75          30.66(2)
               April                                  38.98          27.88(2)
               May                                    33.60          34.05((1))
               June                                   42.45          28.58((1))
               July                                   50.87          30.92((1))
               August                                 60.09          26.31((1))
               September                              53.30          27.98((1))
               Nine-Month Average                  $  44.26      $   29.36
----------------------------------------------------------------------------

               ______________

               (1)Represents average historical market prices for energy as
                  quoted for sales into the Northern Illinois Hub. Energy
                  prices were calculated at the Northern Illinois Hub
                  delivery point using hourly real-time prices as published
                  by PJM.

               (2)Represents average historical market prices for energy for
                  "Into ComEd." Energy prices were determined by obtaining
                  broker quotes and other public price sources for "Into
                  ComEd" delivery points. See discussion under "--Pre-2005
                  Merchant Sales" above for further discussion regarding the
                  replacement of sales "Into ComEd" with sales into the
                  expanded PJM.

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of
factors, including natural gas prices, transmission congestion, changes in market rules,
electricity demand which is affected by weather and economic growth, plant outages in the
region, and the amount of existing and planned power plant capacity. The actual spot prices
for electricity delivered by the Illinois plants into these markets may vary materially from
the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as
quoted for sales into the Northern Illinois Hub at September 30, 2005:

                                      24-Hour Northern
                                            Illinois Hub
2005                                Forward Energy Prices*
----------------------------------------------------------------
    October                                   $  47.40
    November                                     49.98
    December                                     55.85
2006 Calendar "strip"(1)                      $  52.74
2007 Calendar "strip"(1)                      $  47.61
----------------------------------------------------------------
                 ______________

                 (1)Market price for energy purchases for the entire calendar
                    year, as quoted for sales into the Northern Illinois Hub.

                 *  Energy prices were determined by obtaining broker quotes
                    and information from other public sources relating to the
                    Northern Illinois Hub delivery point.


Page 70

The following table summarizes Midwest Generation's hedge position (primarily based on
prices at the Northern Illinois Hub) at September 30, 2005:

                                         2005           2006           2007
---------------------------------------------------------------------------------
                                      4,835,118     14,193,014      6,804,000
 Megawatt hours
 Average price/MWh(1)                $    35.34     $    43.02     $    42.24
---------------------------------------------------------------------------------
        ______________
        (1)The above hedge positions include forward contracts for the sale of power
           during different periods of the year and the day. Market prices tend to be
           higher during on-peak periods during the day and during summer months,
           although there is significant variability of power prices during different
           periods of time. Accordingly, the above hedge position at September 30,
           2005 is not directly comparable to the 24-hour Northern Illinois Hub
           prices set forth above.

Energy Price Risk Affecting Sales from the Homer City Facilities

Electric power generated at the Homer City facilities is generally sold into the PJM market.
The PJM pool has short-term markets, which establish an hourly clearing price. The Homer
City facilities are situated in the PJM control area and are physically connected to
high-voltage transmission lines serving both the PJM and New York Independent System
Operator (NYISO) markets.

The following table depicts the average historical market prices for energy per
megawatt-hour in PJM during the first nine months of 2005 and 2004:

                                                 Historical Energy Prices*
                                                        24-Hour PJM
                                      -------------------------------------------------
                                            Homer City                West Hub
                                           2005       2004          2005      2004
---------------------------------------------------------------------------------------
                                        $  45.82    $  51.12     $  49.53    $  55.01
January
February                                   39.40       47.19        42.05       44.22
March                                      47.42       39.54        49.97       39.21
April                                      44.27       43.01        44.55       42.81
May                                        43.67       44.68        43.64       48.04
June                                       46.63       36.72        53.72       38.05
July                                       54.63       40.09        66.34       43.64
August                                     66.39       34.76        82.83       38.59
September                                  66.67       40.62        76.82       41.96
Nine-Month Average                      $  50.54    $  41.97     $  56.61    $  43.50
=======================================================================================
    ______________
    *   Energy prices were calculated at the Homer City busbar (delivery point) and PJM West
        Hub using historical hourly real-time prices provided on the PJM-ISO web-site.

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors,
including natural gas prices, transmission congestion, changes in market rules, electricity
demand which is affected by weather and economic growth, plant outages in the region, and
the amount of existing and planned power plant capacity. The actual spot prices for
electricity delivered by the Homer City facilities into these markets may vary materially
from the forward market prices set forth in the table below.


Page 71



The following table sets forth the forward market prices for energy per megawatt-hour as
quoted for sales into the PJM West Hub at September 30, 2005:

                                    24-Hour PJM West Hub
2005                               Forward Energy Prices*
----------------------------------------------------------------
    October                                      69.90
    November                                     74.49
    December                                     80.80
2006 Calendar "strip"(1)                      $  72.01
2007 Calendar "strip"(1)                      $  62.18
----------------------------------------------------------------

        ______________

        (1)Market price for energy purchases for the entire calendar
           year, as quoted for sales into the PJM West Hub.

        *  Energy prices were determined by obtaining broker quotes
           and information from other public sources relating to the
           PJM West Hub delivery point. Forward prices at PJM West
           Hub are generally higher than the prices at the Homer
           City busbar.

The following table summarizes Homer City's hedge position at September 30, 2005:

                                         2005           2006           2007
---------------------------------------------------------------------------------
                                      2,215,125      8,525,200      3,618,000
 Megawatt hours
 Average price/MWh(1)                $    43.14     $    53.24     $    60.68
---------------------------------------------------------------------------------

        ______________
        (1)The above hedge positions include forward contracts for the sale of power
           during different periods of the year and the day. Market prices tend to be
           higher during on-peak periods during the day and during summer months,
           although there is significant variability of power prices during different
           periods of time. Accordingly, the above hedge position at September 30, 2005
           is not directly comparable to the 24-hour PJM West Hub prices set forth
           above.

The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy
prices at the Homer City busbar have been lower than energy prices at the PJM West Hub.  See
"--Basis Risk" below for a discussion of the difference.

Basis Risk

Sales made from the Illinois plants and the Homer City facilities in the real-time or
day-ahead market receive the actual spot prices at the busbars (delivery points) of the
individual plants. In order to mitigate price risk from changes in spot prices at the
individual plant busbars, EME may enter into cash settled futures contracts as well as
forward contracts with counterparties for energy to be delivered in future periods.
Currently, there is not a liquid market for entering into these contracts at the individual
plant busbars. A liquid market does exist for a settlement point known as the PJM West Hub
in the case of Homer City and for a settlement point known as the Northern Illinois Hub in
the case of the Illinois plants. EME's price risk management activities use these settlement
points (and, to a lesser extent, other similar trading hubs) to enter into hedging
contracts. EME's revenue with respect to such forward contracts include:

o   sales of actual generation in the amounts covered by such forward contracts with
    reference to PJM spot prices at the busbar of the plant involved, plus,


Page 72



o   sales to third parties at the price under such hedging contracts at designated settlement
    points (generally the PJM West Hub for Homer City and the Northern Illinois Hub for the
    Illinois plants) less the cost of power at spot prices at the same designated settlement
    points.

Under the PJM market design, locational marginal pricing (sometimes referred to as LMP),
which establishes hourly prices at specific locations throughout PJM by considering factors
including generator bids, load requirements, transmission congestion and losses, can cause
the price of a specific delivery point to be raised or lowered relative to other locations
depending on how the point is affected by transmission constraints. To the extent that, on
the settlement date of a hedge contract, spot prices at the relevant busbar are lower than
spot prices at the settlement point, the proceeds actually realized from the related hedge
contract are effectively reduced by the difference. This is referred to by EME as "basis
risk." During the past 12 months, transmission congestion in PJM has resulted in prices at
the Homer City busbar being lower than those at the PJM West Hub (the primary trading hub in
PJM for the Homer City facilities) by an average of 9%. The monthly average difference
during this period ranged from zero to 20%, which occurred in August 2005.  For comparison,
the same difference during 2004 was 4%. By contrast to the Homer City facilities, during the
past 12 months, transmission congestion in PJM has not resulted in prices at the Northern
Illinois Hub being significantly different from those at the individual busbars of the
Illinois plants.

By entering into cash settled future contracts and forward contracts using the PJM West Hub
and the Northern Illinois Hub (or other similar trading hubs) as the settlement points, EME
is exposed to basis risk as described above. In order to mitigate basis risk, EME has
participated in purchasing financial transmission rights in PJM, and may continue to do so
in the future. A financial transmission right is a financial instrument that entitles the
holder thereof to receive actual spot prices at one point of delivery and pay prices at
another point of delivery that are pegged to prices at the first point of delivery, plus or
minus a fixed amount. Accordingly, EME's price risk management activities include using
financial transmission rights alone or in combination with forward contracts to manage basis
risk.

Coal Price and Transportation Risk

The Illinois plants use approximately 18 million to 20 million tons of coal annually,
primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer
City facilities use approximately 5 million tons of coal annually, obtained from mines
located near the facilities in Pennsylvania. Coal purchases are made under a variety of
supply agreements typically ranging from one year to six years in length. The following
table summarizes the percent of expected coal requirements for the next five years that are
under contract at September 30, 2005.

                                           Percent of Coal Requirements
                                                  Under Contract
                                    --------- -------- ------- -------- -------
                                    2005(1)    2006     2007    2008     2009
----------------------------------- --------- -------- ------- -------- -------
Illinois plants                       111%     100%     91%      32%     32%
Homer City facilities((2))            101%      78%     78%      21%     15%
----------------------------------- --------- -------- ------- -------- -------

         ______________

         (1) The percentage in 2005 is calculated based on coal supply and expected
             generation requirements for a full year.

         (2) Adjusted for expected deliveries under an executed agreement to settle
             outstanding contract disputes. See "Commitments, Guarantees and
             Indemnities-- Fuel Supply Contracts" for more information regarding fuel
             supply interruptions and the dispute with two suppliers.

EME is subject to price risk for purchases of coal that are not under contract. Prices of
Northern Appalachia coal, which is purchased for the Homer City facilities, increased
considerably since 2004. In January 2004, prices of Northern Appalachia coal (with 13,000
British Thermal units (Btu) content and


Page 73



lesser than 3.0 SO2 MMBtu content) were below $40 per ton and increased to more than $60 per ton during
2004. On September 30, 2005, the Energy Information Administration reported the price of
Northern Appalachia coal at $54.00 per ton. The overall increase in the Northern Appalachia
coal price has been largely attributed to greater demand from domestic power producers and
increased international shipments of coal to Asia. Prices of Powder River Basin (PRB) coal
(with 8,800 Btu content and 0.8 SO2 MMBtu content), which is purchased for the Illinois
plants, have recently increased due to curtailment of coal shipments for the remainder of
2005 due to increased PRB coal demand from the other regions (east), rail constraints
(discussed below) and higher prices for SO2 allowances. On September 30, 2005, the Energy
Information Administration reported the price of $12.79 per ton, which compares to 2004
prices generally below $7 per ton.

During the first nine months of 2005, the rail lines that bring coal from the PRB to EME's
Illinois plants were damaged from derailments caused by heavy rains. The railroads are in
the process of making repairs to these rail lines and have advised their customers,
including EME, that shipments will be curtailed by 15% to 20% during 2005. Through
September 30, 2005, EME received approximately 87% of expected shipments and expects to
receive shipments of approximately 80% to 85% during the fourth quarter of 2005. Rail
maintenance will continue as long as weather permits. EME continues to work with its
transportation provider to minimize any disruption of planned shipments. Based on
communication with the transportation provider, EME expects to continue receiving a
sufficient amount of coal to generate power at historical levels while these repairs are
being completed.

Emission Allowances Price Risk

Under the federal Acid Rain Program (which requires electric generating stations to hold
sulfur dioxide allowances) and Illinois and Pennsylvania regulations implementing the
federal NOx SIP Call requirement, EME purchases (or sells) emission allowances based on the
amounts required for actual generation in excess of (or less than) the amounts allocated
under these programs. As part of the acquisition of the Illinois plants and the Homer City
facilities, EME obtained the rights to the emission allowances that have been or are
allocated to these plants.

The price of emission allowances, particularly SO2 allowances issued through the United
States EPA Acid Rain Program, increased substantially during 2004 and the first nine months
of 2005. The average price of purchased SO2 allowances increased to $765 per ton during the
nine months ended September 30, 2005 from $281 per ton during the nine months ended
September 30, 2004. The increase in the price of SO2 allowances has been attributed to
reduced numbers of both allowance sellers and prior vintage allowances.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a
number of utilities, energy companies, financial institutions, and other companies,
collectively referred to as counterparties. In the event a counterparty were to default on
its trade obligation, EME would be exposed to the risk of possible loss associated with
re-contracting the product at a price different from the original contracted price if the
non-performing counterparty were unable to pay the resulting liquidated damages owed to EME.
Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for
products delivered prior to the time such counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by counterparties.
Credit risk is measured by the loss that would be incurred if counterparties failed to
perform pursuant to the terms of their contractual obligations. EME measures, monitors and
mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master
netting agreements are used whenever possible and counterparties may be required to pledge
collateral when deemed necessary. EME also takes other appropriate steps


Page 74



to limit or lower credit exposure. Processes have also been established to determine and
monitor the creditworthiness of counterparties. EME manages the credit risk on the portfolio
based on credit ratings using published ratings of counterparties and other publicly
disclosed information, such as financial statements, regulatory filings, and press releases,
to guide it in the process of setting credit levels, risk limits and contractual
arrangements, including master netting agreements. A risk management committee regularly
reviews the credit quality of EME's counterparties. Despite this, there can be no assurance
that these efforts will be wholly successful in mitigating credit risk or that collateral
pledged will be adequate.

EME measures credit risk exposure from counterparties of its merchant energy activities as
either: (i) the sum of 60 days of accounts receivable, current fair value of open positions,
and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and
the current fair value of open positions. EME's subsidiaries enter into master agreements
and other arrangements in conducting price risk management and trading activities which
typically provide for a right of setoff in the event of bankruptcy or default by the
counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net
exposure under these agreements. At September 30, 2005, the amount of exposure, broken down
by the credit ratings of EME's counterparties, was as follows:

 In millions                                        September 30,
                                                         2005
---------------------------------------------------------------------
 S&P Credit Rating
   A or higher                                         $    2
   A-                                                     148
   BBB+                                                    64
   BBB                                                      3
   BBB-                                                     1
   Below investment grade                                  --
---------------------------------------------------------------------
 Total                                                 $  218
---------------------------------------------------------------------

EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power
under long-term power purchase agreements. Generally, each plant sells its output to one
counterparty. Accordingly, a default by a counterparty under a long-term power purchase
agreement, including a default as a result of a bankruptcy, would likely have a material
adverse effect on the operations of such power plant.

In addition, coal for the Illinois plants and the Homer City facilities is purchased from
suppliers under contracts which may be for multiple years. A number of the coal suppliers to
the Illinois plants and the Homer City facilities do not currently have an investment grade
credit rating and, accordingly, EME may have limited recourse to collect damages from a
supplier in the event of default. EME seeks to mitigate this risk through diversification of
its coal suppliers and through guarantees and other collateral arrangements when available.
Despite this, there can be no assurance that these efforts will be successful in mitigating
credit risk from coal suppliers.

For the nine months ended September 30, 2004, one customer accounted for 14% and a second
customer, Exelon Generation, accounted for 40% of EME's consolidated operating revenue. For
more information on Exelon Generation, see "--Commodity Price Risk--Energy Price Risk
Affecting Sales from the Illinois Plants--Pre-2005 Merchant Sales."

Interest Rate Risk

Interest rate changes affect the cost of capital needed to operate EME's projects. EME
mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or
variable rate financing with interest rate swaps, interest rate options or other hedging
mechanisms for a number of its project financings. The fair market values of long-term fixed
interest rate obligations are subject to interest rate risk. The fair


Page 75



market value of MEHC's total long-term obligations (including current portion) was
$4.7 billion at September 30, 2005, compared to the carrying value of $4.1 billion. The fair
market value of MEHC's parent only total long-term obligations was $961 million at
September 30, 2005, compared to the carrying value of $791 million.

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial
instruments used in EME's continuing operations for purposes other than trading by risk
category:

 In millions                                  September 30,   December 31,
                                                  2005            2004
----------------------------------------------------------------------------
   Commodity price:
     Electricity                                $ (582)         $   10
----------------------------------------------------------------------------

In assessing the fair value of EME's non-trading derivative financial instruments, EME uses
a variety of methods and assumptions based on the market conditions and associated risks
existing at each balance sheet date. The fair value of commodity price contracts takes into
account quoted market prices, time value of money, volatility of the underlying commodities
and other factors. The following table summarizes the maturities, the valuation method and
the related fair value of EME's commodity price risk management assets and liabilities as of
September 30, 2005:

In millions                 Total       Maturity   Maturity    Maturity      Maturity
                              Fair     Less than    1 to 3      4 to 5     Greater than
                              Value      1 year      years      years        5 years
--------------------------- ---------- ----------- ---------- ----------- ---------------
Prices actively quoted       $(582)     $ (501)       $(81)     $  --          $ --
--------------------------- ---------- ----------- ---------- ----------- ---------------


Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities
as of September 30, 2005 and December 31, 2004, are set forth below:

                                    September 30, 2005          December 31, 2004
                                 -------------------------  --------------------------
 In millions                        Assets    Liabilities      Assets    Liabilities
--------------------------------------------------------------------------------------
 Electricity                       $  186        $  79        $  125         $ 36
--------------------------------------------------------------------------------------


The change in the fair value of trading contracts for the nine months ended September 30,
2005, was as follows:

In millions
---------------------------------------------------------- ----------

Fair value of trading contracts at January 1, 2005           $  89
Net gains from energy trading activities                       130
Amount realized from energy trading activities                (130)
Other changes in fair value                                     18
---------------------------------------------------------- ----------
Fair value of trading contracts at September 30, 2005        $ 107
---------------------------------------------------------- ----------



Page 76



Quoted market prices are used to determine the fair value of the financial instruments
related to energy trading activities, except for the power sales agreement with an
unaffiliated electric utility that EME's subsidiary purchased and restructured and a
long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded
these agreements at fair value based upon a discounting of future electricity prices derived
from a proprietary model using a discount rate equal to the cost of borrowing the
non-recourse debt incurred to finance the purchase of the power supply agreement. The
following table summarizes the maturities, the valuation method and the related fair value
of energy trading assets and liabilities (as of September 30, 2005):

                                                                                  Maturity
                                       Total     Maturity   Maturity   Maturity    Greater
                                       Fair     Less than   1 to 3     4 to 5       than
In millions                            Value     1 year      years      years     5 years
------------------------------------ ---------- ---------- ---------- ---------- -----------
Prices actively quoted                $  18        $ 18       $ --       $--        $  --
Prices based on models and other
   valuation methods                     89           2          9         7           71
------------------------------------ ---------- ---------- ---------- ---------- -----------
Total                                 $ 107        $ 20       $  9       $ 7        $  71
------------------------------------ ---------- ---------- ---------- ---------- -----------


MEHC:  OTHER DEVELOPMENTS

Agreement to Sell the Doga Project

EME owns an 80% interest in a 180 MW gas-fired cogeneration plant near Istanbul, Turkey,
which EME refers to as the Doga project.  On August 17, 2005, EME entered into a purchase
agreement to sell its interest in the Doga project to EME's co-investor in the Doga project,
Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30%
interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a
50% interest in the Doga project.  Completion of the sale is subject to the satisfaction of
a number of closing conditions, including obtaining the consent of a majority of the
project's lenders.  The sale is expected to close in the fourth quarter of 2005.

Regulatory Matters

There have been no significant developments with respect to regulatory matters specifically
affecting EME since the filing of MEHC's annual report, except as follows:

The MISO's day-ahead and real-time locational marginal pricing markets commenced operation
on April 1, 2005. Since that time, the wholesale electricity trading community has opted to
trade a product delivered at the Cinergy Hub as defined by MISO rather than at the "Into
Cinergy" location that was used previously. EME anticipates that the opening of the MISO
market will lead to increased liquidity in the Midwest electricity markets because
locational marginal pricing provides a liquid and credible cash index against which the
trading community can settle contracts.



Page 77

                                        EDISON CAPITAL

EDISON CAPITAL:  LIQUIDITY

Edison Capital's main sources of liquidity are tax-allocation payments from Edison
International, distributions from its global infrastructure fund investments and lease
rents.  During the nine months ended September 30, 2005, Edison Capital received $163 million
in tax-allocation payments, $98 million in global infrastructure fund distributions and $13
million in lease rent payments.

Edison Capital's cash requirements during the twelve-month period following September 30,
2005, are expected to primarily consist of:

o   Funding investments in renewable energy;

o   Scheduled debt principal and interest payments; and

o   General and administrative expenses.

As of September 30, 2005, Edison Capital had unrestricted cash and cash equivalents of $354
million and long-term debt, including current maturities, of $299 million.

Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation
payments from Edison International (parent) and expected cash flow from operating activities.

At September 30, 2005, Edison Capital's long-term debt had credit ratings of Ba1 and BB+
from Moody's Investors Service and Standard & Poor's, respectively.

Edison Capital has an existing 196 MW portfolio of wind projects located in Iowa and
Minnesota.  In addition, a subsidiary of Edison Capital has entered into an agreement to
acquire a 120 MW wind project in eastern New Mexico from a wind generation developer for
$157 million.  The acquisition of this project is subject to substantial completion of
construction and other closing conditions which are expected to be met in December 2005.
EME and Edison Capital are considering transferring some or all of these projects to EME as
part of its independent power generation portfolio and to expand significantly through EME
further investments in wind projects throughout the United States.

EDISON CAPITAL:  MARKET RISK EXPOSURES

Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and
credit and performance risk that could adversely affect its results of operations or
financial position.  See "Edison Capital:  Market Risk Exposures" in the year-ended 2004
MD&A for a complete discussion of Edison Capital's market risk exposures.

EDISON CAPITAL:  OTHER DEVELOPMENT

Federal Income Taxes

Edison International received Revenue Agent Reports from the Internal Revenue Service (IRS)
in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes
with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively.  Among the
issues raised were items related to Edison Capital.  See "Other Developments--Federal Income
Taxes" for further discussion of these matters.


Page 78



                                EDISON INTERNATIONAL (PARENT)

EDISON INTERNATIONAL (PARENT):  LIQUIDITY

The parent company's liquidity and its ability to pay interest, debt principal, operating
expenses and dividends to common shareholders are affected by dividends from subsidiaries,
tax-allocation payments under its tax-allocation agreements with its subsidiaries, and
access to capital markets or external financings.  Edison International was focused on
reducing its parent company debt in 2004, and as of September 30, 2005, had no debt
outstanding.

Edison International (parent)'s 2005 cash requirements primarily consist of:

o   Dividends to common shareholders.  The Board of Directors of Edison International
    declared a $0.25 per share quarterly common stock dividend in the first, second and third
    quarters of 2005.  The $81 million quarterly common stock dividends were paid on each of
    May 3, 2005, August 1, 2005 and October 31, 2005, respectively; and

o   General and administrative expenses.

Edison International (parent) expects to meet its continuing obligations through cash and
cash equivalents on hand, short-term borrowings, when necessary, and dividends from its
subsidiaries.  At September 30, 2005, Edison International (parent) had approximately $135
million of cash and cash equivalents on hand.  In February 2005, Edison International
(parent) entered into a $750 million senior unsecured 5-year revolving credit facility and
as of September 30, 2005, the entire $750 million was available under the credit facility.
The ability of subsidiaries to make dividend payments to Edison International is dependent
on various factors as described below.

The CPUC regulates SCE's capital structure by requiring that SCE maintain prescribed
percentages of common equity, preferred equity and long-term debt in the utility's capital
structure.  SCE may not make any distributions to Edison International that would reduce the
common equity component of SCE's capital structure below the prescribed level on a 13-month
weighted average basis.  The CPUC also requires that SCE establish its dividend policy as
though it were a comparable stand-alone utility company and give first priority to the
capital requirements of the utility as necessary to meet its obligation to serve its
customers.  Other factors at SCE that affect the amount and timing of dividend payments by
SCE to Edison International include, among other things, SCE's cash requirements, SCE's
access to capital markets, dividends on SCE's preferred and preference stock, and actions by
the CPUC.  SCE made dividend payments of $71 million to Edison International on each of
April 28, 2005, July 28, 2005, and September 30, 2005.

MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1.
At September 30, 2005, its interest coverage ratio was 2.04 to 1.  See "MEHC:
Liquidity--MEHC's Interest Coverage Ratio."  In addition, MEHC's certificate of incorporation
and senior secured note indenture contain restrictions on MEHC's ability to declare or pay
dividends or distributions (other than dividends payable solely in MEHC's common stock).
These restrictions require the unanimous approval of MEHC's Board of Directors, including
its independent director, before it can declare or pay dividends or distributions, as long
as any indebtedness is outstanding under the indenture.  MEHC's ability to pay dividends is
dependent on EME's ability to pay dividends to MEHC (parent).  MEHC has not declared or made
dividend payments to Edison International in 2005.  EME and its subsidiaries have certain
dividend restrictions as discussed in the "MEHC:  Liquidity--Dividend Restrictions in Major
Financings" section.

Edison Capital's ability to make dividend payments is currently restricted by covenants in
its financial instruments, which require Edison Capital, through a wholly owned subsidiary,
to maintain a specified


Page 79


minimum net worth of $200 million.  Edison Capital satisfied this minimum net worth
requirement as of September 30, 2005.  Edison Capital has not declared or made dividend
payments to Edison International in 2005.

EDISON INTERNATIONAL (PARENT):  MARKET RISK EXPOSURES

Although Edison International (parent) had no debt outstanding as of September 30, 2005, the
parent company may be exposed to changes in interest rates which may result from future
borrowing and investing activities.  The proceeds of such borrowings and investing
activities may be used for general corporate purposes, including investments in nonutility
businesses.  The nature and amount of the parent company's long-term and short-term debt can
be expected to vary as a result of future business requirements, market conditions and other
factors.

EDISON INTERNATIONAL (PARENT):  OTHER DEVELOPMENTS

Holding Company Proceeding

Edison International was a party to a CPUC holding company proceeding that closed in May
2005.  On October 27, 2005, the CPUC issued an order instituting rulemaking to allow the CPUC
to re-examine the relationships of the major California energy utilities with their parent
holding companies and non-regulated affiliates.   See "SCE:  Regulatory Matters--Other
Regulatory Matters--Holding Company Proceeding and Order Instituting Rulemaking" for a
discussion of these matters.

Federal Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in
January 2005 asserting deficiencies in federal corporate income taxes with respect to audits
of its 1994-1996 and 1997-1999 tax years, respectively.  See "Other Developments--Federal
Income Taxes" for further discussion of these matters.


Page 80



                             EDISON INTERNATIONAL (CONSOLIDATED)

The following sections of the MD&A are on a consolidated basis.  The section begins with a
discussion of Edison International's consolidated results of operations and historical cash
flow analysis.  This is followed by discussions of discontinued operations, new and proposed
accounting principles, commitments, guarantees and indemnities, and other developments.

RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS

The following subsections of "Results of Operations and Historical Cash Flow Analysis"
provide a discussion on the changes in various line items presented on the Consolidated
Statements of Income as well as a discussion of the changes on the Consolidated Statements
of Cash Flows.

Results of Operations

Edison International recorded consolidated earnings of $462 million, or $1.41 per common
share for the three-month period ended September 30, 2005, compared with consolidated
earnings of $813 million or $2.49 per common share for the three-month period ended
September 30, 2004.  The decrease is primarily due to the impacts from the sale of MEHC's
international assets in 2004 reported as discontinued operations.  The decrease was
partially offset by improved operating results at MEHC from higher wholesale energy prices,
higher energy trading income and lower net interest expense.

Edison International recorded consolidated earnings of $864 million, or $2.64 per common
share for the nine-month period ended September 30, 2005, compared to consolidated earnings
of $537 million or $1.65 per common share for the same period in 2004.  The increase
reflects higher wholesale energy prices and higher energy trading income at MEHC, lower net
interest expense, higher net revenue and tax items at SCE, gains from Edison Capital's
Emerging Europe Infrastructure Fund, and a loss recorded in 2004 on the termination of
MEHC's Collins Station lease.  These increases were partially offset by the impacts from the
sale of MEHC's international assets in 2004 reported as discontinued operations, as well as
net positive regulatory adjustments recorded in 2004 related to the implementation of SCE's
2003 GRC decision.

The tables below present Edison International's earnings and earnings per common share for
the three- and nine-month periods ended September 30, 2005 and 2004, and the relative
contributions by its subsidiaries.

In millions, except per common share amounts   Earnings (Loss)     Earnings (Loss) per Common Share
----------------------------------------------------------------------------------------------
Three-Month Period Ended September 30,       2005         2004            2005         2004
----------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
    SCE                                     $ 280       $  259          $  0.86      $  0.79
    MEHC                                      154           60             0.48         0.18
    Edison Capital                              3           12             0.01         0.04
    Edison International (parent) and other    (2)         (17)           (0.02)       (0.05)
----------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
  (Loss) from Continuing Operations           435          314             1.33         0.96
----------------------------------------------------------------------------------------------
Earnings from Discontinued Operations          27          499             0.08         1.53
----------------------------------------------------------------------------------------------
Edison International Consolidated           $ 462       $  813          $  1.41      $  2.49
----------------------------------------------------------------------------------------------


Page 81


In millions, except per common share amounts   Earnings (Loss)     Earnings (Loss) per Common Share
----------------------------------------------------------------------------------------------
Nine-Month Period Ended September 30,        2005         2004            2005         2004
----------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
    SCE                                     $ 572       $  600          $  1.75      $  1.84
    MEHC                                      179         (614)            0.55        (1.88)
    Edison Capital                             80           34             0.25         0.11
    Edison International (parent) and other   (22)         (52)           (0.08)       (0.17)
----------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
  (Loss) from Continuing Operations           809          (32)            2.47        (0.10)
----------------------------------------------------------------------------------------------
Earnings from Discontinued Operations          55          570             0.17         1.75
----------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change         --           (1)             --          --
----------------------------------------------------------------------------------------------
Edison International Consolidated           $ 864       $  537          $  2.64      $  1.65
----------------------------------------------------------------------------------------------

Earnings from Continuing Operations

SCE's earnings from continuing operations were $280 million and $572 million for the three-
and nine-month periods ended September 30, 2005, respectively, compared to $259 million and
$600 million for the same periods in 2004.  SCE's earnings reflect a positive tax item of
$61 million related to a favorable tax settlement (see "Other Developments--Federal Income
Taxes) for both periods in 2005, as well as net positive regulatory adjustments of $50
million and $172 million for the three- and nine-month periods ended September 30, 2004,
respectively, primarily from the implementation of SCE's 2003 GRC decision.  The increases
for both periods were due to higher net revenue for 2005 and a tax benefit from a new IRS
regulation.  The quarter increase was partially offset by the expected timing difference
related to the implementation of the 2003 GRC decision in July 2004.  The year-to-date
increase was further increased by the favorable resolution of tax issues.

MEHC's earnings from continuing operations were $154 million and $179 million for the three-
and nine-months ended September 30, 2005, respectively, compared to $60 million and a loss
of $614 million for the same periods in 2004, respectively.  MEHC's 2005 earnings reflect an
impairment charge of $34 million recorded in the third quarter of 2005, related to MEHC's
March Point project as the rise in forecast fuel costs lowered projected cash flows.  In
addition, the year-to-date 2005 earnings reflect a $15 million charge related to early debt
retirements.  MEHC's 2004 earnings include charges of $18 million recorded in the third
quarter of 2004, primarily from an impairment related to Midwest Generation's small peaking
plants. In addition, the year-to-date 2004 earnings include a $590 million charge for the
termination of the Collins Station lease, a net gain of $27 million on the sale of MEHC's
interest in Four Star Oil & Gas and the Brooklyn Navy Yard projects, and an $18 million
charge related to a peaker impairment.  The increase for the three- and nine-month periods
ended September 30, 2005, as compared to the same periods in 2004, were primarily due to
higher wholesale energy prices, higher energy trading income and lower net interest expense.

Earnings in the third quarter of 2005 for Edison Capital were $3 million and $80 million for
the three- and nine-month periods ended September 30, 2005, respectively, compared to $12
million and $34 million for the same periods in 2004, respectively.  The three-month period
decrease reflects lower income from Edison Capital's investment in the Emerging Europe
Infrastructure Fund.  The nine-month period increase is primarily due to gains on Edison
Capital's investment in the Emerging Europe Infrastructure Fund.

The loss for "Edison International parent company and other" decreased by $15 million and
$30 million for the three- and nine-month periods ended September 30, 2005, respectively, as
compared to the same periods in 2004, primarily due to lower net interest expense.


Page 82



Operating Revenue

SCE's retail sales represented approximately 85% and 83% of electric utility revenue for the
three- and nine-month periods ended September 30, 2005, respectively, compared to
approximately 88% and 86% of electric utility revenue for the three- and nine-month periods
ended September 30, 2004, respectively.  Due to warmer weather during the summer months,
electric utility revenue during the third quarter of each year is generally significantly
higher than other quarters.

The following table sets forth the major changes in electric utility revenue:

                                             Three-Month Period   Nine-Month Period
                                             Ended September 30, Ended September 30,
    In millions                                 2005 vs. 2004       2005 vs. 2004
------------------------------------------------------------------------------------
    Electric utility revenue
        Rate changes (including unbilled)         $ 316                $ 497
        Sales volume changes (including unbilled)   190                  352
        Deferred revenue                           (200)                (473)
        Sales for resale                             90                  134
        SCE's variable interest entities             20                  129
        Other (including intercompany transactions)  13                   28
------------------------------------------------------------------------------------
    Total                                         $ 429                $ 667
------------------------------------------------------------------------------------


Total electric utility revenue increased by $429 million and $667 million for the three- and
nine-month periods ended September 30, 2005, respectively (as shown in the table above), as
compared to the same periods in 2004.  The variance in electric utility revenue from rate
changes reflects the implementation of the 2003 GRC, effective in August 2004.  As a result,
generation rates increased revenue by approximately $295 million and $235 million for the
three- and nine-month periods ended September 30, 2005, respectively, and distribution rates
increased revenue by approximately $20 million and $260 million for the three- and
nine-month periods ended September 30, 2005, respectively.  The change in deferred revenue
reflects the deferral of approximately $90 million and $290 million of revenue in the three-
and nine-month periods ended September 30, 2005, respectively, resulting from balancing
account overcollections, compared to the recognition of approximately $110 million and $180
million of deferred revenue in the three- and nine-month periods ended September 30, 2004,
respectively.  The increase in electric utility revenue resulting from sales volume changes
was mainly due to an increase in kWh sold and SCE providing a greater amount of energy to
its customers from its own sources in 2005, compared to 2004.  Electric utility revenue from
sales for resale represents the sale of excess energy.  As a result of the CDWR contracts
allocated to SCE, excess energy from SCE sources may exist at certain times, which then is
resold in the energy markets.  SCE's variable interest entities revenue represents the
recognition of revenue resulting from the consolidation of SCE's variable interest entities
on March 31, 2004.

Amounts SCE bills and collects from its customers for electric power purchased and sold by
the CDWR to SCE's customers (beginning January 17, 2001), CDWR bond-related costs (beginning
November 15, 2002) and direct access exit fees (beginning January 1, 2003) are remitted to
the CDWR and are not recognized as revenue by SCE.  These amounts were $534 million and $1.5
billion for the three- and nine-month periods ended September 30, 2005, respectively,
compared to $693 million and $1.9 billion for the same periods in 2004.

Nonutility power generation revenue increased $168 million and $348 million for the three-
and nine-month periods ended September 30, 2005, respectively, as compared to the same
periods in 2004, due to higher energy revenue, higher net gains from price risk management
and energy trading activities, partially offset by lower capacity revenue.  Energy revenue
from MEHC's Illinois plants increased by approximately $245 million and $460 million for the
three- and nine-month periods ended September 30,


Page 83



2005, respectively, as compared to the same periods in 2004, due to increased average energy
prices.  Energy revenue at MEHC's Homer City facilities increased by approximately $55
million and $110 million for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to the same periods in 2004, due to higher average energy prices
and increased generation.  During the first quarter of 2004, an unplanned outage at MEHC's
Homer City facilities contributed to lower generation.  During the third quarter of 2004,
coal deliveries under contracts with four fuel suppliers to MEHC's Homer City facilities
were temporarily interrupted.  As a result of these interruptions, MEHC's Homer City
facilities reduced generation during off-peak periods when power prices were lower and
purchased coal from alternative suppliers at spot prices, which were substantially higher
than the contract prices from these four fuel suppliers (see "Commitments, Guarantees, and
Indemnities--Fuel Supply Contracts" for further discussion).  The increases in energy revenue
were partially offset by lower capacity revenue of approximately $160 million and $245
million for the three- and nine-month periods ended September 30, 2005, respectively, at
MEHC's Illinois plants from the expiration of the power-purchase agreements with Exelon
Generation, as well as a decrease of $29 million (representing revenue for the first quarter
of 2005) due to the deconsolidation of EME's Doga project at March 31, 2004, in accordance
with accounting standards.  Net gains (losses) from price risk management and energy trading
activities increased approximately $35 million and $60 million for the three- and nine-month
periods ended September 30, 2005, respectively, as compared to the same periods in 2004.
The volatile market conditions during the first nine months of 2005, driven by increased
prices for natural gas and oil and warmer summer temperatures, have created favorable
conditions for Edison Mission Marketing & Trading's strategies relative to conditions in
2004.  The results of these favorable conditions have been partially offset by losses from
price risk management activities at MEHC's Illinois plants and Homer City facilities.

Due to higher demand for electricity resulting from warmer weather during the summer months,
nonutility power generation revenue generated from MEHC's Illinois plants and Homer City
facilities is generally higher during the third quarter of each year. However, as a result
of recent increases in market prices for power (driven in part by higher natural gas and oil
prices), this historical trend may not be applicable to quarterly revenue in the future.

Operating Expenses

Fuel Expense

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005       2004         2005      2004
---------------------------------------------------------------------------------------
        SCE                                 $ 296     $  254      $  817     $  550
        MEHC                                  193        161         492        477
---------------------------------------------------------------------------------------
        Edison International Consolidated   $ 489     $  415      $1,309     $1,027
---------------------------------------------------------------------------------------

SCE's fuel expense increased for the three- and nine-month periods ended September 30, 2005,
as compared to the same periods in 2004, mainly due to the consolidation of SCE's variable
interest entities in March 31, 2004.  Fuel expense related to SCE's variable interest
entities was approximately $225 million and $624 million for the three- and nine-month
periods ended September 30, 2005, respectively, compared to approximately $187 million and
$375 million for the comparable periods in 2004.

MEHC's fuel expense increased for the three- and nine-month periods ended September 30,
2005, mainly attributable to higher fuel consumption, higher coal prices and higher priced
SO2 emission allowances (see "MEHC:  Market Risk Exposures--Commodity Price Risk--Emission
Allowances Price Risk" for more information regarding the price of SO2 allowances).  The
nine-month period increase was partially offset by


Page 84



lower fuel costs attributable to the cessation of operations at MEHC's Collins Station
effective September 30, 2004.

Purchased-Power Expense

Purchased-power expense decreased $413 million and $389 million for the three- and
nine-month periods ended September 30, 2005, respectively, as compared to the same periods
in 2004.  The decreases were mainly due to net realized and unrealized gains on economic
hedging transactions and lower ISO-related purchases, partially offset by higher firm energy
and QF purchases.  Net realized and unrealized gains related to economic hedging
transactions, resulting from increased hedging activities, were approximately $585 million
and $530 million for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to net realized and unrealized losses of approximately $75 million
for both periods in 2004.  ISO-related purchases decreased approximately $50 million and $95
million for the three- and nine-month periods ended September 30, 2005, respectively, as
compared to the same periods in 2004.  These decreases were partially offset by higher firm
energy expenses of approximately $315 million and $490 million for the three- and nine-month
periods ended September 30, 2005, respectively, as compared to the same periods in 2004,
resulting from an increase in the number of bilateral contracts in 2005, as compared to 2004,
and higher QF-related purchases of approximately $30 million and $70 million for the three-
and nine-month periods ended September 30, 2005, respectively, as compared to the same
periods in 2004.  The nine-month period decrease also reflects approximately $130 million of
energy settlement refunds received in 2005 (see "SCE:  Regulatory Matters--Transmission and
Distribution--Wholesale Electricity and Natural Gas Markets"), as compared to approximately
$65 million received during the same period in 2004, as well as a reduction of $205 million
in purchased-power resulting from the consolidation of SCE's variable interest entities on
March 31, 2004.

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs
at CPUC-mandated prices.  Energy payments to gas-fired QFs are generally tied to spot
natural gas prices.  Effective May 2002, energy payments for most renewable QFs were
converted to a fixed price of 5.37(cent)-per-kWh.  Average spot natural gas prices were higher
during 2005 as compared to 2004.  The higher expenses related to power purchased from QFs
were mainly due to higher average spot natural gas prices, partially offset by lower kWh
purchases.

Provisions for Regulatory Adjustment Clauses - Net

Provisions for regulatory adjustment clauses - net increased $800 million and $875 million
for the three- and nine-month periods ended September 30, 2005, respectively, as compared to
the same periods in 2004.  The increases mainly result from higher net unrealized gains on
economic hedging transactions, net overcollections related to balancing accounts, lower
CEMA-related costs, and GRC regulatory adjustments.  The quarter and year-to-date increases
reflect higher net unrealized gains of approximately $575 million and $525 million for the
three- and nine-month periods ended September 30, 2005, respectively, related to economic
hedging transactions (mentioned above in purchased-power expense) that, if realized, would
be refunded to ratepayers; net overcollections of purchased power, fuel, and operating and
maintenance expenses of approximately $180 million and $45 million for the three- and
nine-month periods ended September 30, 2005 which were deferred in balancing accounts for
future recovery; lower costs incurred and deferred (approximately $25 million and $85
million for the three- and nine-month periods ended September 30, 2005, respectively, as
compared to the same periods in 2004) associated with CEMA-related costs; and the net effect
of regulatory adjustments related to the implementation of SCE's 2003 GRC decision in the
amount of $180 million recorded in the second quarter of 2004 and approximately $15 million
recorded in the third quarter of 2004.  The 2003 GRC regulatory adjustments primarily
related to recognition of revenue from the rate recovery of pension contributions during the
time period that the pension plan was fully funded, resolution over the allocation of costs
between transmission and distribution for 1998 through 2000, partially offset by the
deferral of revenue previously collected during the incremental cost incentive pricing
mechanism for dry cask storage.


Page 85



Other Operation and Maintenance Expense

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005       2004         2005      2004
---------------------------------------------------------------------------------------
        SCE                                 $ 668     $  606      $1,835     $1,760
        MEHC                                  172        170         586        561
        Other                                  22         11          64         46
---------------------------------------------------------------------------------------
        Edison International Consolidated   $ 862     $  787      $2,485     $2,367
---------------------------------------------------------------------------------------

SCE's other operation and maintenance expense increased for the three- and nine-month
periods ended September 30, 2005, as compared to the same periods in 2004.  The increases
were mainly due to an increase in reliability costs, demand-side management and energy
efficiency costs, and benefit-related costs, partially offset by lower CEMA-related costs
and generation-related costs.  The quarter and year-to-date increases reflect an increase in
reliability costs of approximately $35 million and $75 million for the three- and nine-month
periods ended September 30, 2005, respectively, as compared to the same periods in 2004, due
to an increase in must-run units to improve the reliability of the California ISO systems
operations (which are recovered through regulatory mechanisms approved by the FERC); an
increase in demand side management and energy efficiency costs of approximately $25 million
and $50 million for the three- and nine-month periods ended September 30, 2005 in 2005,
respectively (which are recovered through regulatory mechanisms approved by the CPUC); and
higher benefit-related costs of approximately $40 million and $50 million for the three- and
nine-month periods ended September 30, 2005, respectively, resulting from an increase in
heath care costs and value of performance shares.  The quarter and year-to-date increases
were partially offset by lower CEMA-related costs of approximately $25 million and $85
million for the three- and nine-month periods, respectively, compared to the same periods in
2004; and a decrease in generation-related expenses of approximately $10 million and $65
million, for the three- and nine-month periods ended September 30, 2005, respectively, as
compared to 2004, resulting from lower outage and refueling costs (in 2004, there was a
scheduled major overhaul at SCE's Four Corners coal facility, as well as a refueling outage
at SCE's San Onofre Unit 2).  The year-to-date variance was also due to an increase of
approximately $30 million in O&M expenses as a result of the consolidation of SCE's variable
interest entities, as well as higher worker's compensation accruals of approximately $10
million in 2005 compared to 2004.

MEHC's other operation and maintenance expense increased for the nine-month period ended
September 30, 2005, as compared to the same period in 2004, mainly due to higher plant
operation costs at MEHC's Illinois plants resulting from higher planned maintenance.  The
increase was partially offset by a decrease in plant operating lease costs due to the
termination of MEHC's Collins Station lease in April 2004.

Asset Impairment and Loss on Lease Termination

Asset impairment and loss on lease termination for the nine-month period ended September 30,
2004 includes a $954 million loss recorded during the second quarter of 2004 and a $7
million loss recorded during the third quarter of 2004 related to the loss on the
termination of MEHC's Collins Station lease, asset impairment, and related inventory
reserves.  MEHC concluded that the Collins Station was not economically competitive in the
marketplace given generation overcapacity and ceased operations effective September 30,
2004.  In addition, a $29 million loss was recorded during the third quarter of 2004 related
to the impairment of six of MEHC's small peaking units in Illinois.


Page 86



Depreciation, Decommissioning and Amortization

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005       2004         2005      2004
---------------------------------------------------------------------------------------
        SCE                                 $ 234     $  188       $ 688      $ 628
        MEHC                                   30         39          91        112
        Other                                   6          5          17         15
---------------------------------------------------------------------------------------
        Edison International Consolidated   $ 270     $  232       $ 796      $ 755
---------------------------------------------------------------------------------------


SCE's depreciation, decommissioning and amortization increased for the three- and nine-month
periods ended September 30, 2005, as compared to the same periods in 2004, mainly due to a
decrease in depreciation expense recorded in the third quarter of 2004 as a result of the
implementation of the 2003 GRC related to the Palo Verde incremental cost incentive pricing
rate-making mechanism, as well as depreciation expense associated with additions to
transmission and distribution assets.

Other Income and Deductions

Interest and Dividend Income

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005       2004         2005      2004
---------------------------------------------------------------------------------------
        SCE                                 $  13     $    3       $  29      $   9
        MEHC                                   15         (5)         43         --
        Other                                   3          5           6         17
---------------------------------------------------------------------------------------
        Edison International Consolidated   $  31     $    3       $  78      $  26
---------------------------------------------------------------------------------------

SCE's interest and dividend income increased for the three- and nine-month periods ended
September 30, 2005, as compared to the same period in 2004, mainly due to interest income
related to balancing account undercollections, as well as $4 million related to interest on
demand-side management and energy efficiency performance incentive claims resulting from a
CPUC-approved settlement.  See "SCE:  Regulatory Matters--Other Regulatory
Matters--Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms" for
further discussion. MEHC's interest and dividend income increased for both the three- and
nine-month periods ended September 30, 2005, as compared to the same periods in 2004,
primarily due to higher interest income resulting from higher average cash balances during
the first nine months of 2005, compared to the corresponding period of 2004.

Equity in Income from Partnerships and Unconsolidated Subsidiaries - Net

Equity in income from partnerships and unconsolidated subsidiaries - net increased $75
million for the nine-month period ended September 30, 2005, as compared to the same period
in 2004.  The increase is mainly due to increased earnings of approximately $85 million from
Edison Capital's global infrastructure funds, partially offset by the effects of accounting
for variable interest entities consolidated upon adoption of a new accounting pronouncement
in second quarter 2004, resulting in a decrease of approximately $25 million.  As a result,
SCE now consolidates projects previously treated under the equity method by EME.

Third quarter equity in income from partnerships and unconsolidated subsidiaries - net from
EME's energy projects is materially higher than equity in income from partnerships and
unconsolidated subsidiaries - net related to other quarters of the year due to warmer
weather during the summer months


Page 87



and because a number of EME's energy projects located on the west coast have power sales
contracts that provide for higher payments during the summer months.

Other Nonoperating Income

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005       2004        2005       2004
---------------------------------------------------------------------------------------
        SCE                                 $  33     $    2       $  68      $  42
        MEHC                                    1          6           2         54
---------------------------------------------------------------------------------------
        Edison International Consolidated   $  34     $    8       $  70      $  96
---------------------------------------------------------------------------------------

SCE's other nonoperating income for the three- and nine-month periods ended September 30,
2005 includes a $14 million incentive related to demand-side management and energy
efficiency performance for the portion of the incentives previously collected in rates but
which were deferred.  See "SCE:  Regulatory Matters--Other Regulatory Matters--Demand-Side
Management and Energy Efficiency Performance Incentive Mechanisms" for further discussion of
this matter.  In addition, the quarter and year-to-date amounts include approximately $10
million and $20 million for the three- and nine-months ended September 30, 2005,
respectively, related to an allowance for funds used during construction (AFUDC), which
represents the estimated cost of equity funds that finance utility-plant construction,
compared to approximately $5 million and $15 million in the same periods in 2004.  The
nine-month period ended September 30, 2005, also includes a $7 million shareholder incentive
related to the Mirant settlement received in the second quarter of 2005 (see "SCE:
Regulatory Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas
Markets"), as well as a $10 million reward for the efficient operation of Palo Verde during
2003, which was approved by the CPUC in 2005.  SCE's other nonoperating income for the
nine-month period ended September 30, 2004, includes $19 million in rewards for the
efficient operation of Palo Verde during 2001 and 2002, which were approved by the CPUC in
2004.

MEHC's other nonoperating income in 2004 consisted of a pre-tax gain of $47 million on the
sale of EME's interest in Four Star Oil & Gas on January 7, 2004 and a $4 million loss
related to the sale of MEHC's interest in Brooklyn Navy Yard Cogeneration Partners.

Interest Expense - Net of Amounts Capitalized

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                           2005       2004        2005       2004
---------------------------------------------------------------------------------------
        SCE                                 $   91    $    98      $  289     $  302
        MEHC                                   101        120         305        334
        Other                                    6         33          21        105
---------------------------------------------------------------------------------------
        Edison International Consolidated   $  198    $   251      $  615     $  741
---------------------------------------------------------------------------------------

MEHC's interest expense - net of amounts capitalized decreased for the three- and nine-month
periods ended September 30, 2005, as compared to the same periods in 2004, mainly due to the
repayment of MEHC (parent)'s $385 million term loan ($100 million of the term loan was
repaid in July 2004 and the remaining $285 million of the term loan was repaid in January
2005).  The year-to-date decrease was partially offset by higher interest expense at EME's
Illinois plants, primarily attributable to higher interest rates on fixed rate debt issued
in April 2004.


Page 88



The decrease in interest expense - net of amounts capitalized related to Other for the
three- and nine-month periods ended September 30, 2005, as compared to the same periods in
2004, was mainly due to the elimination of Edison International (parent)'s debt.  Edison
International (parent) has had no debt outstanding since the fourth quarter of 2004.

Impairment Loss on Equity Method Investment

During the third quarter of 2005, MEHC fully impaired its equity investment in the March
Point project following an updated forecast of future project cash flows. The March Point
project is a 140 MW natural gas-fired cogeneration facility located in Anacortes,
Washington, in which a subsidiary of MEHC owns a 50% partnership interest. The March Point
project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements
that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil)
under a steam supply agreement that also expires in 2011. March Point purchases a portion of
its fuel requirements under long-term contracts with the remaining requirements purchased at
current market prices. March Point's power sales agreements do not provide for a price
adjustment related to the project's fuel costs. During the third quarter of 2005, long-term
natural gas prices increased substantially, thereby adversely affecting the future cash
flows of the March Point project. As a result, MEHC concluded that its investment was
impaired and recorded a $55 million charge during the third quarter of 2005.

Loss on Early Extinguishment of Debt

The loss on early extinguishment of debt in the nine-month period ended September 30, 2005,
consisted of a $20 million loss related to the early repayment of MEHC (parent)'s $385
million term loan and a $4 million loss related to the early repayment of EME's junior
subordinated debentures recorded during the first quarter of 2005.

Other Nonoperating Deductions

Other nonoperating deductions increased $27 million and $22 million for the three- and
nine-month periods ended September 30, 2005, as compared to the same periods in 2004, mainly
due to an accrual of $26 million in system reliability penalties.  See "SCE:  Regulatory
Matters--Other Regulatory Matters--System Reliability Incentive Mechanism" for further
discussion of this matter.

Income Tax (Benefit)

                                               Three Months            Nine Months
                                            Ended September 30,    Ended September 30,
---------------------------------------------------------------------------------------
        In millions                          2005        2004        2005       2004
---------------------------------------------------------------------------------------
        SCE                                 $  52     $   174      $  176     $  398
        MEHC                                   95          22          89       (389)
        Other                                 (18)        (15)          2        (49)
---------------------------------------------------------------------------------------

        Edison International Consolidated   $ 129     $   181      $  267     $  (40)
---------------------------------------------------------------------------------------

Edison International's effective tax rates were 23% and 25% for the three- and nine-month
periods ended September 30, 2005, respectively, as compared to 37% and 55% for the same
periods in 2004.  The decreased effective tax rates resulted primarily from recording a $65
million benefit, including $57 million of interest income, in the third quarter of 2005
related to a settlement reached with the IRS on tax issues and pending affirmative claims
relating to Edison International's 1991-1993 tax years.  See "Other Developments--Federal
Income Taxes" for further discussion of this matter.  Additional decreases to the effective
rates resulted from reductions made to accrued tax liabilities in 2005 to reflect progress
made in settlement negotiations related to tax audits other than the 1991-1993 tax years,
changes in


Page 89



property-related flow-through items at SCE and adjustments made to tax balances in 2005 at
MEHC and SCE.

Minority Interest

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

Income from Discontinued Operations

The third-quarter 2005 earnings from discontinued operations primarily reflect positive tax
adjustment of $28 million resulting from the sales of MEHC's international projects.
Beginning in the third quarter of 2004, MEHC reclassified the results of its international
projects to discontinued operations for all periods presented due to completion of the sale
of its interest in Contact Energy and its agreement to sell the remaining international
projects.  Earnings from discontinued operations during the third quarter of 2004, including
a gain and recognition of a tax benefit, were $499 million.  Earnings from discontinued
operations for the nine months ended September 30, 2005 were $55 million including positive
tax adjustments of $28 million related to MEHC's international asset sales and distributions
from MEHC's Lakeland project of $24 million.  Earnings from discontinued operations for the
nine months ended September 30, 2004 were $570 million representing the operating results,
gain on sale and recognition of tax benefits related to MEHC's international projects.

Cumulative Effect of Accounting Change - Net of Tax

Edison International's results for the nine-month period ended September 30, 2004, include a
charge for the cumulative effect of a change in accounting principle reflecting the impact
of Edison Capital's implementation of an accounting standard that requires the consolidation
of certain variable interest entities.

Historical Cash Flow Analysis

The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows
from operating, financing and investing activities.

Cash Flows from Operating Activities

Net cash provided by operating activities:

        In millions       Nine-Month Period Ended September 30,    2005        2004
---------------------------------------------------------------------------------------
        Continuing operations                                    $1,680       $ 629
---------------------------------------------------------------------------------------


The 2005 change in cash provided by operating activities from continuing operations was
mainly due an increase in short-term regulatory balancing account collections, partially
offset by required margin and collateral deposits in 2005 mainly for MEHC's price risk
management and trading activities resulting from an increase in forward market prices.  In
addition, the change in cash provided by operating activities results from the timing of
cash receipts and disbursements related to working capital items.


Page 90



Cash Flows from Financing Activities

Net cash provided (used) by financing activities:

        In millions     Nine-Month Period Ended September 30,      2005         2004
---------------------------------------------------------------------------------------
        Continuing operations                                   $  (955)     $   228
---------------------------------------------------------------------------------------

Cash provided (used) by financing activities from continuing operations mainly consisted of
long-term and short-term debt payments at SCE and EME.

Financing activities in the nine-month period ended September 30, 2005, were mainly related
to SCE.  SCE's first quarter 2005 financing activity included the issuance of $650 million
of first and refunding mortgage bonds.  The issuance included $400 million of 5% bonds due
in 2016 and $250 million of 5.55% bonds due in 2036.  The proceeds were used to redeem the
remaining $50,000 of its 8% first and refunding mortgage bonds due February 2007 (Series
2003A) and $650 million of the $966 million 8% first and refunding mortgage bonds due
February 2007 (Series 2003B).  SCE's second quarter financing activity included the issuance
of $350 million of its 5.35% first and refunding mortgage bond due in 2035 (Series 2005E).
A portion of the proceeds was used to redeem $316 million of its 8% first and refunding
mortgage bonds due in 2007 (Series 2003B).  In addition, in April 2005, SCE issued
4,000,000 shares of Series A preference stock (non-cumulative, $100 liquidation value) and
received net proceeds of approximately $394 million.  Approximately $81 million of the
proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred
stock, 7.23% Series, and approximately $64 million of the proceeds was used to redeem all
the outstanding shares of its $100 cumulative preferred stock, 6.05% Series.  SCE's third
quarter 2005 financing activity included the issuance of 2,000,000 shares of Series B
preference stock (non-cumulative, $100 liquidation value) and received net proceeds of
approximately $197 million.   MEHC's first quarter financing activity included the repayment
of the remaining $285 million of the term loan, $11 million paid for the call premium on the
retirement of the term loan and the repayment of the junior subordinated debentures of
$150 million.  MEHC's second quarter activity included a $302 million repayment in April 2005
related to Midwest Generation's existing term loan. Financing activities in 2005 also
include dividend payments of $244 million paid by Edison International to its shareholders.

Financing activities in the nine-month period ended September 30, 2004 included repurchases
of approximately $47 million of Edison International (parent)'s $618 million 6-7/8% notes
due September 2004 and paid the remaining balance in September 2004.  SCE financing
activities include the issuance of $300 million of 5% bonds due in 2014, $525 million of 6%
bonds due in 2034 and $150 million of floating rate bonds due in 2006 during the first
quarter of 2004.  The proceeds from these issuances were used to redeem $300 million of
7.25% first and refunding mortgage bonds due March 2026, $225 million of 7.125% first and
refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding mortgage
bonds due October 2018, and $100 million of junior subordinated deferrable interest
debentures due June 2044.  In addition, during the first quarter of 2004, SCE paid the
$200 million outstanding balance of its credit facility, as well as remarketed approximately
$550 million of pollution-control bonds with varying maturity dates ranging from 2008 to
2040.  Approximately $354 million of these pollution-control bonds had been held by SCE
since 2001 and the remaining $196 million were purchased and reoffered in 2004.  In March
2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds due in 2015 and
$350 million of 5.75% first and refunding mortgage bonds due in 2035.  A portion of the
proceeds from the March 2004 first and refunding mortgage bond issuances were used to fund
the acquisition and construction of the Mountainview project.  During the third quarter, SCE
paid $125 million of 5.875% bonds due in September 2004.  EME's financing activities
included the $1 billion secured notes and $700 million term loan facility received by
Midwest Generation in April 2004, the repayment of $693 million related to Edison Mission
Midwest Holdings' credit facility, $28 million related to the EME's Coal and Capex facility
in April 2004, and $100 million


Page 91



related to MEHC's $385 million term loan in July 2004.  Financing activities in 2004 also
included dividend payments of $195 million paid by Edison International to its shareholders.

Cash Flows from Investing Activities

Net cash used by investing activities:

        In millions     Nine-Month Period Ended September 30,      2005        2004
---------------------------------------------------------------------------------------
        Continuing operations                                   $  (891)     $ (562)
---------------------------------------------------------------------------------------

Cash flows from investing activities are affected by capital expenditures, EME's sales of
assets and SCE's funding of nuclear decommissioning trusts.

Investing activities for the nine-month period ended September 30, 2005 reflect $1.3 billion
in capital expenditures at SCE, primarily for transmission and distribution assets,
including approximately $43 million for nuclear fuel acquisitions, and $41 million in
capital expenditures at EME.  Investing activities also include $140 million in net sales of
auction rate securities at EME and $124 million in proceeds received in 2005 from the sale
of EME's 25% investment in the Tri Energy project and EME's 50% investment in the CBK
project, as well as a decrease in restricted cash and customer advances for construction.

Investing activities for the nine-month period ended September 30, 2004 reflect $1.1 billion
in capital expenditures at SCE, primarily for transmission and distribution assets,
including approximately $59 million for nuclear fuel acquisitions, and $39 million in
capital expenditures at EME.  In addition, investing activities include $285 million of
acquisition costs related to the Mountainview project at SCE, and $118 million in proceeds
received from the sale of 100% of EME's stock of Edison Mission Energy Oil & Gas and the
sale of EME's interest in the Brooklyn Navy Yard project, and $739 million in proceeds
received in 2004 at EME from the sale of its interest in Contact Energy.  Cash flows from
investing activities also reflect a decrease in restricted cash.

DISCONTINUED OPERATIONS

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to
a purchase agreement dated December 15, 2004, to a consortium comprised of International
Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately
$20 million.  The sale of this investment had no significant effect on net income in the
first quarter of 2005.

On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan
project to Corporacion IMPSA S.A., pursuant to a purchase agreement dated November 5, 2004.
Proceeds from the sale were approximately $104 million.  EME recorded a pre-tax gain on the
sale of approximately $9 million during the first quarter of 2005.

EME previously owned and operated a 220 MW combined cycle, natural gas-fired power plant
located in the United Kingdom, known as the Lakeland project.  The ownership of the project
was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated
from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of
TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU
Europe).  EME ceased consolidating the activities of Lakeland Power Ltd. in 2002, when an
administrative receiver was appointed following a default by Norweb Energi Ltd. under the
power sales agreement.  Accordingly, EME accounts for its ownership of Lakeland Power Ltd.
on the cost method and earnings are recognized as cash is distributed from this entity.


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As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim
against Norweb Energi Ltd. for termination of the power sales agreement.  On November 19,
2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited, entered into formal administration proceedings of their own in the United Kingdom
(similar to bankruptcy proceedings in the United States).  On March 31, 2005, Lakeland Power
Ltd. received(pound)112 million (approximately $210 million) from the TXU administrators,
representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately
$217 million).

From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United
Kingdom, has made a payment of(pound)20 million (approximately $37 million) to EME on April 7,
2005 comprised of(pound)7 million (approximately $13 million) for a secured loan which EME
purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured
receivables from Lakeland Power Ltd., and(pound)13 million (approximately $24 million) as a
distribution to the EME subsidiary that owns the equity interest in Lakeland Power Ltd.
This distribution was recognized in income during the quarter ended June 30, 2005.
Additionally, Lakeland Power Ltd. will pay to EME's subsidiary that owns the equity interest
in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured and
unsecured creditor claims and payment of or provision for tax liabilities and the fees and
expenses associated with Lakeland Power Ltd.'s liquidation.

EME estimates that the remaining net proceeds after tax (including taxes due in the United
States) and net income resulting from the above payments will be approximately $64 million.
The majority of the remaining proceeds are expected to be received in 2006, when Lakeland
Power Ltd.'s liquidation is expected to be completed.  Because the amounts required to
settle outstanding claims and UK taxes have not been finalized and cannot be estimated
precisely in the context of the liquidation, the actual amount of net proceeds and increase
in net income may vary materially from the above estimate.

For all periods presented, the results of EME's international projects, except for the Doga
project (discussed in MEHC:  Other Developments--Agreement to Sell the Doga Project"), have
been accounted for as discontinued operations in the consolidated financial statements in
accordance with an accounting standard related to the impairment and disposal of long-lived
assets.

There was no revenue from discontinued operations in 2005.  For the three and nine months
ended September 30, 2004, revenue from discontinued operations was $354 million and $1.1
billion, respectively.  For the three months ended September 30, 2005 and 2004, pre-tax
income (loss) was $(2) million and $41 million, respectively.  For the nine months ended
September 30, 2005 and 2004, pre-tax income was $20 million and $165 million, respectively.

During the third quarter ended September 30, 2005, EME recorded tax adjustments of
$28 million which resulted from the completion of the 2004 federal and California income tax
returns and quarterly review of tax accruals.  The majority of the tax adjustments are
related to the sale of the international assets.  These adjustments (benefits) are included
in income from discontinued operations - net of tax on the consolidated income statement.
During the quarter ended September 30, 2004, EME recorded a deferred income tax benefit of
$327 million to recognize the higher tax basis of its international holding company over its
book basis as required by accounting rules applicable to discontinued operations.

NEW AND PROPOSED ACCOUNTING PRINCIPLES

In March 2005, the FASB issued an interpretation related to accounting for conditional asset
retirement obligations (AROs).  This Interpretation clarifies that an entity is required to
recognize a liability for the fair value of a conditional ARO if the fair value can be
reasonably estimated even though uncertainty exists about the timing and/or method of
settlement.  This Interpretation is effective December 31, 2005.  Thus far, Edison
International has identified conditional AROs related to:  treated wood poles, hazardous


Page 93



materials such as mercury and polychlorinated biphenyls-containing equipment; and asbestos
removal costs at buildings, operating stations and retired units.  Additional assessment is
necessary to value these AROs.  However, since SCE follows accounting principles for
rate-regulated enterprises and receives recovery of these costs through rates,
implementation of this interpretation at SCE will not affect Edison International's
earnings.  Implementation of this interpretation at EME is expected to have a minimal impact
on Edison International's earnings.

A new accounting standard requires companies to use the fair value accounting method for
stock-based compensation.  Edison International currently uses the intrinsic value
accounting method for stock-based compensation.  On April 14, 2005, the Securities and
Exchange Commission announced a delay in the effective date for the new standard to fiscal
years beginning after June 15, 2005.  Edison International will implement the new standard
effective January 1, 2006 by applying the modified prospective transition method.  The
difference in expense between the two accounting methods related to stock options granted is
an increase of $2 million and $7 million in expense for the three- and nine-month periods
ended September 30, 2005, respectively.  Edison International is assessing the impact of
this accounting standard on its performance shares.

The American Jobs Creation Act of 2004 included a tax deduction on qualified production
activities income (including income from the sale of electricity).  In December 2004, the
FASB issued guidance that this deduction should be accounted for as a special deduction,
rather than a tax rate reduction.  Accordingly, the special deduction is recorded in the
year it is earned.  In October 2005, the IRS issued proposed regulations for this tax
deduction.  The tax deduction is not expected to materially affect Edison International's
2005 financial statements.  Edison International is evaluating the effect that the
manufacturer's deduction will have in subsequent years.

In March 2004, the FASB issued new accounting guidance for the effect of participating
securities on EPS calculations and the use of the two-class method.  The new guidance, which
was effective in second quarter 2004, requires the use of the two-class method of computing
EPS for companies with participating securities (including vested stock options with
dividend equivalents).

Basic EPS is computed by dividing net income available for common stock by the
weighted-average number of common shares outstanding.  Net income (loss) available for
common stock was $459 million and $813 million for the three months ended September 30,
2005, and 2004, respectively, and was $859 million and $537 million for the nine months
ended September 30, 2005, and 2004, respectively.  In arriving at net income, dividends on
preferred securities and preferred stock have been deducted.

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

On March 31, 2004, SCE consolidated four power projects partially owned by EME, EME
deconsolidated two power projects, and Edison Capital consolidated two affordable housing
partnerships and three wind projects.  Edison International recorded a cumulative effect
adjustment that decreased net income by less than $1 million, net of tax, due to negative
equity at one of Edison Capital's newly consolidated entities.


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On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax
positions.  An enterprise would recognize, in its financial statements, the benefit of a tax
position only if that position is probable of being sustained on audit based solely on the
technical merits of the position.  The comment period for the exposure draft ended on
September 12, 2005; the earliest the guidance would be implemented would be December 31,
2005.  Edison International is evaluating the potential impact of the proposal on its
financial statements.

COMMITMENTS, GUARANTEES AND INDEMNITIES

The following is an update to Edison International's commitments, guarantees and
indemnities.  See the "Commitments, Guarantees and Indemnities" section of the year-ended
2004 MD&A for a detailed discussion.

Fuel Supply Contracts

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments
with various third-party suppliers during the first nine months of 2005. These additional
commitments are currently estimated to be $22 million for 2005, $114 million for 2006,
$169 million for 2007, $44 million for 2008, and $62 million for 2009.

Beginning in 2004, EME Homer City experienced interruptions of supply under two agreements
with Unionvale Coal Company and Genesis, Inc. Unionvale and Genesis claimed that alleged
geologic conditions at the Genesis No. 17 Mine in Pennsylvania, which is one source of coal
under these multi-source coal contracts, constituted force majeure and excused contract
performance. These two agreements together provide for the delivery to EME Homer City of
approximately 20% of EME Homer City's clean coal requirements in 2005 and 2006, and
approximately 10% in 2007. Claims arising from these matters have been resolved in a
confidential settlement and the lawsuit has been dismissed. EME Homer City has awarded
contracts to alternate suppliers, and adjusted its inventory strategies to reflect and
offset the delivery shortfall for 2005.

During the second quarter of 2005, SCE amended one of its coal fuel contracts which reduced
the term of the contract.  As a result of this modification, the fuel supply contract
payments for the thereafter period decreased by $158 million.

Gas and Coal Transportation

Midwest Generation has contractual agreements for the transport of coal to its facilities.
The primary contract is with Union Pacific Railroad (and various delivering carriers) which
extend through 2011. Midwest Generation commitments under this agreement are based on actual
coal purchases from the Powder River Basin. Accordingly, contractual obligations for
transportation are based on coal volumes set forth in fuel supply contracts. The increase in
transportation commitments entered into during the first nine months of 2005 relates to
additional volumes of fuel purchases using the terms of existing transportation agreements.
These commitments are currently estimated to be $33 million for 2005, $61 million for 2006,
$117 million for 2007, $40 million for 2008, and $77 million for 2009.

Power-Purchase Contracts

During the first quarter of 2005, SCE entered into additional power call option contracts.
SCE's revised purchased-power capacity payment commitments under these contracts are
currently estimated to be $31 million for 2005, $95 million for 2006, $101 million for 2007
and $84 million for 2008.


Page 95



Leases

During the first quarter of 2005, SCE entered into new power contracts in which SCE takes
virtually all of the power.  In accordance with an accounting standard, these power
contracts are classified as operating leases.  SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million
for 2007 and $43 million for 2008.

OTHER DEVELOPMENTS

Environmental Matters

Edison International 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.

Edison International believes that it is in substantial compliance with environmental
regulatory requirements; however, possible future developments, such as the enactment of
more stringent environmental laws and regulations, could affect the costs and the manner in
which business is conducted and could cause substantial additional capital expenditures.
There is no assurance that additional costs would be recovered from customers or that Edison
International's financial position and results of operations would not be materially
affected.

Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments
and/or remedial actions are probable and a range of reasonably likely cleanup costs can be
estimated.  Edison International 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, Edison International records the lower end of
this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.

Edison International's recorded estimated minimum liability to remediate its 29 identified
sites at SCE (22 sites) and EME (7 sites related to Midwest Generation) is $84 million,
$81 million of which is related to SCE.  Edison International's other subsidiaries have no
identified remediation sites.  The ultimate costs to clean up Edison International'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.  Edison
International believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $115 million, all of which is
related to SCE.  The upper limit of this range of costs was estimated using assumptions
least favorable to Edison International among a range of reasonably possible outcomes.  In
addition to its identified sites (sites in which the upper end of the range of costs is at
least $1 million), SCE also has 33 immaterial sites whose total liability ranges from
$4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites,
representing $29 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


Page 96



third parties.  SCE has successfully settled insurance claims with all responsible
carriers.  SCE expects to recover costs incurred at its remaining sites through customer
rates.  SCE has recorded a regulatory asset of $55 million for its estimated minimum
environmental-cleanup costs expected to be recovered through customer rates.

Edison International'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 Edison International 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.

Edison International expects to clean up its identified sites over a period of up to 30
years.  Remediation costs in each of the next several years are expected to range from
$11 million to $25 million.  Recorded costs for the twelve months ended September 30, 2005
were $11 million.

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

Federal Income Taxes

Edison International has reached a settlement with the IRS on tax issues and pending
affirmative claims relating to its 1991-1993 tax years.  This settlement, which was signed
by Edison International in March 2005 and approved by the United States Congress Joint
Committee on Taxation on July 27, 2005, resulted in a third quarter 2005 net earnings
benefit for Edison International of approximately $65 million, including interest, most of
which relates to SCE.  This benefit was reflected in the income statement caption "Income
tax (benefit)."

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

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised
issues about the deferral of income taxes in audits of the 1994-1996 and 1997-1999 tax years
associated with Edison Capital's cross-border leases.  The IRS is challenging Edison
Capital's foreign power plant and electric locomotive sale/leaseback transactions (termed a
sale-in/lease-out or SILO transaction).  The estimated federal and state taxes deferred from
these leases were $44 million in the 1994-1996 and 1997-1999 audit periods and $32 million
in subsequent years through 2004.

The IRS is also challenging Edison Capital's foreign power plant and electric transmission
system lease/leaseback transactions (termed a lease-in, lease-out or LILO transaction).  The
estimated federal and state income taxes deferred from these leases were $558 million in the
1997-1999 audit period and $565 million in subsequent years through 2004.  The IRS has also
proposed interest and penalties in its challenge to each SILO and LILO transaction.

Edison International believes it properly reported these transactions based on applicable
statutes, regulations and case law in effect at the time the transactions were entered
into.  Written protests were


Page 97



filed to appeal the 1994-1996 audit adjustments asserting that the IRS's position misstates
material facts, misapplies the law and is incorrect.  This matter is now being considered by
the Administrative Appeals branch of the IRS.  Edison International also filed protests in
March 2005 to appeal the issues raised in the 1997-1999 audit.

Edison Capital also entered into a lease/service contract transaction in 1999 involving a
foreign telecommunication system (termed a Service Contract).  The IRS did not assert an
adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge this
lease in subsequent audit cycles similar to positions asserted against the SILOs discussed
above.  The estimated federal and state taxes deferred from this lease are $221 million
through 2004.

If Edison International is not successful in its defense of the tax treatment for the SILOs,
LILOs and the Service Contract, the payment of taxes, exclusive of any interest or
penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow.  However, the FASB is currently
considering changes to the accounting for leases.  If the proposed accounting changes are
adopted and Edison International's tax treatment for the SILOs, LILOs and Service Contract
is significantly altered as a result of IRS challenges, there could be a material effect on
reported earnings by requiring Edison International to reverse earnings previously
recognized as a current period adjustment and to report these earnings over the remaining
life of the leases.  At this time, Edison International is unable to predict the impact of
the ultimate resolution of these matters.

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

In April 2004, Edison International filed California Franchise Tax amended returns for tax
years 1997 through 2002 to abate the possible imposition of new California penalty
provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice that was published in 2001.  These
transactions include certain Edison Capital leveraged lease transactions and the SCE
subsidiary contingent liability company transaction described above.  Edison International
filed these amended returns under protest retaining its appeal rights.




Page 98



EDISON INTERNATIONAL

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's
Discussion and Analysis of Financial Condition and Results of Operations," under the
headings "SCE:  Market Risk Exposures," "MEHC:  Market Risk Exposures," "Edison Capital:
Market Risk Exposures," and "Edison International (Parent):  Market Risk Exposures" and is
incorporated herein by this reference.

Item 4.  Controls and Procedures

Disclosure Controls and Procedures

Edison International's management, under the supervision and with the participation of the
company's Chief Executive Officer and Chief Financial Officer, has evaluated the
effectiveness of Edison International's disclosure controls and procedures (as that term is
defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as
amended (the Exchange Act)) as of the end of the period covered by this report.  Based on
that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded
that, as of the end of the period, Edison International's disclosure controls and procedures
are effective.

Internal Control Over Financial Reporting

There were no changes in Edison International's internal control over financial reporting
(as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the
quarter to which this report relates that have materially affected, or are reasonably likely
to materially affect, Edison International's internal control over financial reporting.




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PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

Edison International or its subsidiaries are party to certain lawsuits and legal
proceedings, which are described in Part I, Item 3 of Edison International's Annual Report
on Form 10-K for the year ended December 31, 2004.  The following is a description of
material developments during the period covered by this Quarterly Report and should be read
in conjunction with the Annual Report referenced above.  There were no significant
developments with respect to litigation required to be disclosed under Part II, Item I of
Form 10-Q of Edison International or its subsidiaries during the quarterly period ended
September 30, 2005, except as follows:

                              Southern California Edison Company

Navajo Nation Litigation

See Note 4, "Contingencies - Navajo Nation Litigation" of Notes to Consolidated Financial
Statements for minor updates on litigation involving SCE and the Navajo Nation which was
previously reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K
for the year ended December 31, 2004, and in Part II, Item 1 of Edison International's
Quarterly Report on Form 10-Q for the period ended March 31, 2005, and Edison
International's Quarterly Report on Form 10-Q for the period ended June 30, 2005.

Department of the Army, Los Angeles District, Corps of Engineers/Notice of Violation of
Clean Water Act

In December 2004, the US Army Corps of Engineers (Corps) sent SCE a Notice of Violation
(Notice), alleging that SCE or its contractors had discharged fill material into wetlands
adjacent to the Santa Ana River (River), in the City of Huntington Beach, CA (City).  Under
Sections 301 and 404 of the Clean Water Act, the discharge of fill material into waters of
the United States is unlawful unless first permitted by the Corps pursuant to Section 404 of
the Clean Water Act.

The Notice provided a general description of the area in question but did not specify the
location of the violation.  Following discussions and correspondence with the Corps, it was
determined that the Corps was concerned about the actions of a certain licensee of SCE on an
SCE-owned transmission right-of-way corridor located adjacent to the River.  SCE's licensee,
or its predecessor-in-interest, had obtained from the City a Conditional Use Permit (CUP) to
locate landscape nursery operations within the right-of-way corridor.  The CUP required the
licensee to perform certain drainage and grading improvements to the property before
locating nursery operations on site.  During the course of the grading work, the licensee
brought additional soil onto SCE's property for use as fill material.

Pursuant to the Notice, potential penalties for violation of Section 404 of the Clean Water
Act include a maximum criminal fine of $50,000 per day and imprisonment for up to three
years, and a maximum civil penalty of $25,000 per day of violation.  To date, however, the
Corps has not proposed to impose any specific fine or penalty on SCE with respect to the
subject matter of the Notice.

In the process of investigating the matter, the Corps has requested that SCE perform a
wetlands delineation study of the property to determine whether the property in question
qualifies as a wetland area subject to Corps jurisdiction.  SCE has hired a consulting group
to perform the wetlands delineation study.


Page 100



                                Mission Energy Holding Company

Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all
its output to the California Department of Water Resources. On May 15, 2002, Sunrise Power
Company was served with a complaint filed in the Superior Court of the State of California,
City and County of San Francisco, by James M. Millar, "individually, and on behalf of the
general public and as a representative taxpayer suit" against sellers of long-term power to
the California Department of Water Resources, including Sunrise Power Company.  The lawsuit
alleges that the defendants, including Sunrise Power Company, engaged in unfair and
fraudulent business practices by knowingly taking advantage of a manipulated power market to
obtain unfair contract terms.  The lawsuit seeks to enjoin enforcement of the "unfair and
oppressive terms and conditions" in the contracts, as well as restitution by the defendants
of excessive monies obtained by the defendants.  Plaintiffs in several other class action
lawsuits pending in Northern California have filed petitions seeking to have the Millar
lawsuit consolidated with those lawsuits.  In December 2003, James Millar filed a First
Amended Class Action and Representative Action Complaint which contains allegations similar
to those in the earlier complaint but also alleges a class action.  One of the newly added
parties removed the lawsuit to federal court, and the court ordered remand to the San
Francisco Superior Court.  Defendants filed a responding pleading on May 6, 2005. Following
a hearing on September 7, 2005, the court sustained defendants' demurrer regarding
preemption and filed rate doctrine.  The plaintiff has waived his right to appeal.



Page 101



Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

(c)      Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table contains information about all purchases made by or on behalf of Edison
International or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the
Exchange Act) of shares or other units of any class of Edison International's equity
securities that is registered pursuant to Section 12 of the Exchange Act.

                                                                 (c) Total        (d) Maximum
                                                              Number of Shares     Number (or
                                                                 (or Units)       Approximate
                                                                 Purchased         Dollar Value)
                                                                 as Part of         of Shares
                            (a) Total         (b) Average         Publicly      (or Units) that May
                          Number of Shares   Price Paid per      Announced       Yet Be Purchased
                            (or Units)         Share (or          Plans or        Under the Plans
         Period            Purchased(1)         Unit)(1)          Programs          or Programs
----------------------- ------------------ ---------------- ------------------ -------------------

July 1, 2005 to              1,200,269        $40.28              --                  --
July 31, 2005

August 1 to                  1,796,658        $41.21              --                  --
August 31, 2005

September 1, 2005 to         1,579,506        $46.19              --                  --
September 30, 2005
----------------------- ------------------ ---------------- ------------------ -------------------

Total                        4,576,433        $42.68              --                  --
----------------------- ------------------ ---------------- ------------------ -------------------

___________________
(1) The shares were purchased by agents acting on Edison International's behalf for delivery
    to plan participants to fulfill requirements in connection with Edison International's
    (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Direct Stock Purchase Plan, and
    (iii) long-term incentive compensation plans.  The shares were purchased in open-market
    transactions pursuant to plan terms or participant elections.  Edison International did
    not control the quantity of shares purchased, the timing of the purchases or the price of
    the shares purchased in these transactions.  The shares were never registered in Edison
    International's name and none of the shares purchased were retired as a result of the
    transactions.




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Item 6.  Exhibits

         Edison International

         3       Bylaws of Edison International, as Amended to and including October 20, 2005
                 (File No. 1-9936, filed as Exhibit 3.1 to Edison International's Form 8-K
                 dated October 24, 2005, and filed on October 26, 2005)*

         10.1    Retirement Agreement, dated as of August 25, 2005, between Southern
                 California Edison Company and Robert Foster (File No. 1-02313, filed as
                 Exhibit 10.1 to Southern California Edison Company's Form 8-K dated August
                 25, 2005 and filed on August 26, 2005)*

         10.2    Consulting Agreement, dated as of August 25, 2005, between Southern
                 California Edison Company and Robert Foster (File No. 1-02313, filed as
                 Exhibit 10.2 to Southern California Edison Company's Form 8-K dated August
                 25, 2005, and filed on August 26, 2005)*

         10.3    Engagement Letter for Legal Services between Edison International and Bryant
                 C. Danner, effective September 28, 2005 (File No. 1-9936, filed as Exhibit
                 99.1 to Edison International's Form 8-K dated September 28, 2005, and filed
                 on October 4, 2005)*

         10.4    Legal Fees Reimbursement, dated September 2005 (File No. 1-02313, filed as
                 Exhibit 10.3 to Southern California Edison Company's Form 10-Q for the
                 quarter ended September 30, 2005)*

         31.1    Certification of the Chief Executive Officer pursuant to Section 302 of the
                 Sarbanes-Oxley Act

         31.2    Certification of the Chief Financial Officer pursuant to Section 302 of the
                 Sarbanes-Oxley Act

         32      Statement Pursuant to 18 U.S.C. Section 1350

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



Page 103



                                          SIGNATURE


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.


                                            EDISON INTERNATIONAL
                                                   (Registrant)


                                            By    /s/ LINDA G. SULLIVAN
                                                  ----------------------------------
                                                   LINDA G. SULLIVAN
                                                   Vice President and Controller
                                                   (Duly Authorized Officer and
                                                   Principal Accounting Officer)


Dated:  November 4, 2005