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

                                                   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, 2001


                                                        OR

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

       For the transition period from _____________________________ to __________________________



                                           Commission File Number 1-9936

                                               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 800)
                  Rosemead, California
                 (Address of principal                                          91770
                   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 the number of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:


                        Class                                            Outstanding at November 9, 2001
-------------------------------------------------------      --------------------------------------------------------
              Common Stock, no par value                                           325,811,206

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EDISON INTERNATIONAL

                                                       INDEX
                                                                                                   Page
                                                                                                    No.
                                                                                                  ------

Part I.Financial Information:

  Item 1.          Consolidated Financial Statements:

                   Consolidated Statements of Income (Loss) - Three and Nine Months
                        Ended September 30, 2001, and 2000                                          1

                   Consolidated Statements of Comprehensive Income (Loss) -
                        Three and Nine Months Ended September 30, 2001, and 2000                    1

                   Consolidated Balance Sheets - September 30, 2001,
                        and December 31, 2000                                                       2

                   Consolidated Statements of Cash Flows - Nine Months
                        Ended September 30, 2001, and 2000                                          4

                   Notes to Consolidated Financial Statements                                       5

  Item 2.          Management's Discussion and Analysis of Results
                        of Operations and Financial Condition                                      21

Part II.  Other Information:

  Item 1.          Legal Proceedings                                                               49

  Item 6.          Exhibits and Reports on Form 8-K                                                51








EDISON INTERNATIONAL

PART I - FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS)
In millions, except per-share amounts

                                                                3 Months Ended                    9 Months Ended
                                                                 September 30,                     September 30,
-------------------------------------------------------------------------------------------------------------------
                                                            2001              2000             2001           2000
-------------------------------------------------------------------------------------------------------------------
                                                                                (Unaudited)
Electric utility                                         $ 2,725           $ 2,432          $ 5,826         $ 6,115
Nonutility power generation                                1,194             1,061            2,789           2,567
Financial services and other                                 124               160              517             444
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Total operating revenue                                    4,043             3,653            9,132           9,126
-------------------------------------------------------------------------------------------------------------------

Fuel                                                         403               336            1,060             930
Purchased power                                              759             1,915            3,290           3,103
Provisions for regulatory adjustment clauses - net            (5)             (861)            (124)           (856)
Other operation and maintenance                              837               736            2,551           2,292
Depreciation, decommissioning and amortization               267               535              794           1,515
Write-down of nonutility assets                            1,923                --            2,107              --
Property and other taxes                                      28                30               88             100
Net gain on sale of utility plant                             --                --               (7)             (6)
-------------------------------------------------------------------------------------------------------------------

Total operating expenses                                   4,212             2,691            9,759           7,078
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Operating income (loss)                                     (169)              962             (627)          2,048
Interest and dividend income                                  40                63              135             126
Other nonoperating income                                     47                16               78             128
Interest expense - net of amounts capitalized               (467)             (345)          (1,246)         (1,010)
Other nonoperating deductions                                (22)              (32)             (75)           (139)
Dividends on preferred securities                            (23)              (25)             (69)            (76)
Dividends on utility preferred stock                          (6)               (6)             (17)            (16)
-------------------------------------------------------------------------------------------------------------------

Income (loss) before taxes                                  (600)              633           (1,821)          1,061
Income tax expense (benefit)                                (187)              273             (689)            454
-------------------------------------------------------------------------------------------------------------------

Net income (loss)                                       $   (413)          $   360         $ (1,132)       $    607
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Weighted-average shares of common stock
   outstanding                                               326               326              326             335
Basic earnings (loss) per share                        $   (1.27)          $  1.11       $    (3.47)       $   1.81
Weighted-average shares, including effect
    of dilutive securities                                   326               327              326             336
Diluted earnings (loss) per share                      $   (1.27)          $  1.10       $    (3.47)       $   1.81
Dividends declared per common share                    $      --          $    .28       $       --       $     .84


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
                                                                3 Months Ended                    9 Months Ended
                                                                 September 30,                     September 30,
-------------------------------------------------------------------------------------------------------------------

                                                            2001              2000             2001           2000
-------------------------------------------------------------------------------------------------------------------
                                                                               (Unaudited)
Net income (loss)                                       $   (413)          $   360         $ (1,132)       $    607
Other comprehensive income, net of tax:
   Cumulative translation adjustments - net                   97               (94)             (12)           (241)
   Unrealized gain (loss) on securities - net                 --                (2)              --              (7)
   Cumulative effect of change in accounting for derivatives (16)               --              152              --
   Unrealized loss on cash flow hedges                       (17)               --             (300)             --
   Reclassification adjustment for losses on derivatives
      included in net income (loss)                          (11)               --              (37)            (24)
-------------------------------------------------------------------------------------------------------------------

Comprehensive income (loss)                             $   (360)          $   264         $ (1,329)       $    335
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                    The accompanying notes are an integral part of these financial statements.


Page 1


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS
In millions

                                                                            September 30,           December 31,
                                                                                2001                    2000
-------------------------------------------------------------------------------------------------------------------

                                                                             (Unaudited)
ASSETS
Cash and equivalents                                                         $  4,094               $  1,973
Receivables, less allowances of $32 and $40 for uncollectible
  accounts at respective dates                                                  1,667                  1,099
Accrued unbilled revenue                                                          568                    377
Fuel inventory                                                                    248                    220
Materials and supplies, at average cost                                           219                    210
Accumulated deferred income taxes - net                                         1,399                  1,350
Trading and price risk management assets                                          103                    252
Prepayments and other current assets                                              258                    185
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Total current assets                                                            8,556                  5,666
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Nonutility property - less accumulated provision for
  depreciation of $961 and $774 at respective dates                             8,766                 10,084
Nuclear decommissioning trusts                                                  2,268                  2,505
Investments in partnerships and unconsolidated subsidiaries                     2,249                  2,700
Investments in leveraged leases                                                 2,334                  2,345
Other investments                                                                 114                     92
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Total investments and other assets                                             15,731                 17,726
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Utility plant, at original cost
   Transmission and distribution                                               13,453                 13,129
   Generation                                                                   1,725                  1,745
Accumulated provision for depreciation and decommissioning                     (7,852)                (7,834)
Construction work in progress                                                     592                    636
Nuclear fuel, at amortized cost                                                   129                    143
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Total utility plant                                                             8,047                  7,819
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Regulatory assets - net                                                         2,874                  2,390
Other deferred charges                                                          1,854                  1,499
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Total deferred charges                                                          4,728                  3,889
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Total assets                                                                 $ 37,062               $ 35,100
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                    The accompanying notes are an integral part of these financial statements.


Page 2


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS
In millions, except share amounts

                                                                            September 30,          December 31,
                                                                                2001                   2000
-------------------------------------------------------------------------------------------------------------------

                                                                             (Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt                                                              $  3,131              $  3,920
Long-term debt classified as due within one year                                4,018                 2,260
Preferred stock to be redeemed within one year                                    105                    --
Accounts payable                                                                3,566                 1,228
Accrued taxes                                                                     343                   593
Regulatory liabilities - net                                                      136                   195
Trading and risk management liabilities                                            51                   282
Other current liabilities                                                       2,619                 2,322
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Total current liabilities                                                      13,969                10,800
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Long-term debt                                                                 12,262                12,150
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Accumulated deferred income taxes - net                                         5,110                 5,328
Accumulated deferred investment tax credits                                       174                   183
Customer advances and other deferred credits                                    1,755                 1,692
Power-purchase contracts                                                          384                   467
Accumulated provision for pensions and benefits                                   535                   438
Other long-term liabilities                                                        98                    94
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Total deferred credits and other liabilities                                    8,056                 8,202
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Commitments and contingencies (Notes 1, 2 and 4)
Minority interest                                                                 357                    18
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Preferred stock of utility:
   Not subject to mandatory redemption                                            129                   129
   Subject to mandatory redemption                                                151                   256
Company-obligated mandatorily redeemable securities of subsidiaries
      holding solely parent company debentures                                    950                   949
Other preferred securities                                                         93                   176
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Total preferred securities of subsidiaries                                      1,323                 1,510
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Common stock (325,811,206 shares outstanding at each date)                      1,960                 1,960
Additional paid-in capital                                                          4                    --
Accumulated other comprehensive income (loss)                                    (336)                 (139)
Retained earnings (deficit)                                                      (533)                  599
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Total common shareholders' equity                                               1,095                 2,420
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Total liabilities and shareholders' equity                                   $ 37,062              $ 35,100
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                    The accompanying notes are an integral part of these financial statements.



page 3


EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In millions

                                                                                        9 Months Ended
                                                                                         September 30,
-------------------------------------------------------------------------------------------------------------------

                                                                                  2001                      2000
-------------------------------------------------------------------------------------------------------------------

                                                                                          (Unaudited)
Cash flows from operating activities:
Net income (loss)                                                            $  (1,132)                  $   607
Adjustments to reconcile net income (loss) to net cash
 provided by operating activities:
   Depreciation, decommissioning and amortization                                  794                     1,515
   Other amortization                                                               67                       133
   Deferred income taxes and investment tax credits                               (456)                      454
   Equity in income from partnerships and unconsolidated subsidiaries             (332)                     (197)
   Income from leveraged leases                                                    (88)                     (141)
   Regulatory assets - long-term - net                                            (388)                   (1,994)
   Write-down of nonutility assets                                               2,107                        --
   Net gain on sale of marketable securities                                        --                       (57)
   Other assets                                                                    (89)                     (199)
   Other liabilities                                                               (89)                     (113)
   Changes in working capital:
      Receivables and accrued unbilled revenue                                    (226)                     (412)
      Regulatory liabilities - short-term - net                                    (59)                      907
      Fuel inventory, materials and supplies                                        (9)                       21
      Prepayments and other current assets                                         196                       (53)
      Accrued interest and taxes                                                  (142)                      (10)
      Accounts payable and other current liabilities                             1,889                       778
Distributions and dividends from unconsolidated entities                           217                       135
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Net cash provided by operating activities                                        2,260                     1,374
-------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued                                                            3,491                     3,016
Long-term debt repaid                                                           (1,752)                   (3,332)
Bonds repurchased and funds held in trust                                         (130)                     (219)
Issuance of preferred securities                                                    95                        --
Common stock repurchased                                                            --                      (386)
Redemption of preferred securities                                                (164)                       --
Rate reduction notes repaid                                                       (174)                     (175)
Short-term debt financing - net                                                   (825)                      905
Dividends paid                                                                      --                      (280)
Nuclear fuel financing - net                                                       (14)                       (6)
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Net cash provided (used) by financing activities                                   527                      (477)
-------------------------------------------------------------------------------------------------------------------

Cash flows from investing activities:
Additions to property and plant                                                   (732)                   (1,067)
Purchase of nonutility generation plant                                             --                       (17)
Proceeds from sale of nonutility property                                          450                     1,706
Funding of nuclear decommissioning trusts                                            3                      (123)
Investments in partnerships and unconsolidated subsidiaries                        (99)                     (321)
Proceeds from sales of marketable securities                                        --                        58
Investments in leveraged leases                                                     68                      (258)
Sales of investments in other assets                                              (315)                     (259)
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Net cash used by investing activities                                             (625)                     (281)
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Effect of exchange rate changes on cash                                            (41)                      (47)
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Net increase in cash and equivalents                                             2,121                       569
Cash and equivalents, beginning of period                                        1,973                       507
-------------------------------------------------------------------------------------------------------------------

Cash and equivalents, end of period                                          $   4,094                   $ 1,076
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                     The accompanying notes are an integral part of these financial statements



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management's Statement

In the opinion of management, all adjustments have been made that are necessary to present a fair statement of
the financial position and results of operations for the periods covered by this report.

Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated
Financial Statements" included in its 2000 Annual Report on Form 10-K filed with the Securities and Exchange
Commission.  Edison International follows the same accounting policies for interim reporting purposes, with the
exception of the changes in accounting for derivatives and Southern California Edison Company's (SCE) purchased
power.  This quarterly report should be read in conjunction with Edison International's 2000 Annual Report on
Form 10-K filed with the Securities and Exchange Commission.

Certain prior-period amounts were reclassified to conform to the September 30, 2001, financial statement
presentation.

Note 1.  Liquidity Crisis

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

Undercollections in the transition revenue account (TRA) and transition cost balancing account (TCBA) mechanisms,
coupled with SCE's anticipated near-term capital requirements and the adverse reaction of the credit markets to
regulatory uncertainty regarding SCE's ability to recover its power procurement costs, materially and adversely
affected SCE's liquidity.  As a result of its liquidity crisis, SCE has taken and is taking steps to conserve
cash so that it can continue to provide service to its customers.  As a part of this process, beginning in
January 2001, SCE suspended payments of certain obligations for principal and interest on outstanding debt and
for purchased power.  As of October 31, 2001, SCE had $3.3 billion in obligations that were unpaid and overdue
including:  (1) $940 million to the California Power Exchange (PX) or the Independent System Operator (ISO); (2)
$1.2 billion to power producers that are qualifying facilities (QFs); (3) $231 million in PX energy credits for
energy service providers; (4) $531 million of matured commercial paper; and (5) $400 million of principal on its
5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the energy crisis.  As applicable, unpaid
obligations will continue to accrue interest.  At October 31, 2001, SCE had estimated cash reserves of
approximately $2.7 billion (after deducting $530 million of designated funds), which is approximately
$650 million less than its outstanding unpaid obligations and preferred stock dividends in arrears (see below),
not including its credit facilities that are subject to forbearance agreements.  If SCE is found responsible for
purchases of power by the ISO for delivery to SCE's customers on or after January 18, 2001, SCE's unpaid
obligations as of October 31, 2001, could increase by as much as $1.6 billion.  This amount could increase or
decrease depending on California Public Utilities Commission (CPUC) or Federal Energy Regulatory Commission
(FERC) decisions regarding payments and refunds.  See additional discussion in Note 2.  These stated amounts
representing past or future obligations for purchased power, PX energy credits and certain other items include
amounts that are in dispute, and the publishing of these amounts is not an admission by SCE of liability for any
disputed amounts.

SCE's failure to pay when due the principal amount of the 5-7/8% and 6-1/2% senior unsecured notes constituted a
default on each series, entitling those noteholders to exercise their remedies.  Such failure and the failure to
pay commercial paper when due could also constitute an event of default on all the other series of senior
unsecured notes if the trustee or holders of 25% in principal amount of the notes give a notice demanding that
the default be cured, and SCE does not cure the default within 30 days.  Such failures are also an event of
default under SCE's credit facilities and bilateral credit agreements, entitling those lenders to exercise their
remedies including potential acceleration of the outstanding borrowings of $1.65 billion.  If a notice of default
is received, SCE could cure the default only by paying $531 million in overdue principal to holders of commercial
paper and $400 million to the holders of the 5-7/8% and 6-1/2% senior unsecured notes.  Making such payment would
further impact SCE's liquidity.  If a notice of


Page 5


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

default were received and not cured, and the trustee or noteholders were to declare an acceleration of the
outstanding principal amount of the senior unsecured notes, SCE would not have the cash to pay the obligation and
could be forced to declare bankruptcy.  As a result of the default of the two series of senior unsecured notes,
SCE's other senior unsecured notes and subordinated debentures have been classified as due within one year in the
accompanying financial statements.

SCE has been unable to obtain financing of any kind.  As a result of investors' concerns regarding the California
energy crisis and its impact on SCE's liquidity and overall financial condition, SCE has repurchased $550 million
of pollution-control bonds that could not be remarketed in accordance with their terms.  These bonds may be
remarketed in the future if SCE's credit status improves sufficiently.  In addition, SCE has been unable to
market its commercial paper and other short-term financial instruments.  As of March 31, 2001, SCE resumed
payment of interest on its debt obligations.  However, since June 30, 2001, SCE has deferred the interest
payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the
securities.  All interest in arrears must be paid in full at the end of the deferral period.

In March 2001, the CPUC issued decisions ordering SCE and other investor-owned utilities to pay QFs for power
deliveries on a going forward basis, commencing with April 2001 deliveries, and on the California Procurement
Adjustment (CPA) calculation including the approval of a 3(cent)per kWh rate increase.  One of the CPUC decisions
also modified the formula used in calculating payments to QFs by substituting natural gas index prices based on
deliveries at the Oregon border rather than index prices at the Arizona border.  The changes apply to all QFs,
where appropriate, regardless of whether they use natural gas or other resources such as solar or wind.

In light of SCE's liquidity crisis, its Board of Directors has not declared quarterly common stock dividends to
SCE's parent, Edison International, since September 2000.  Edison International's Board of Directors also has not
declared a common stock dividend to Edison International's shareholders.  Also, SCE's Board has not declared the
regular quarterly dividends for any of SCE's cumulative preferred stock in 2001.  SCE's preferred stock dividends
in arrears total $17 million as of October 31, 2001.  Dividends are additionally restricted as detailed in
Note 2.

SCE has implemented other cost-cutting measures, such as freezing new hiring and postponing certain capital
expenditures.  SCE's current cost-cutting measures are intended to allow it to continue to operate while efforts
to restore its creditworthiness (such as that contemplated in the CPUC litigation settlement agreement) are
underway.

Unless the court of appeals issues a stay pending appeal (described below) or the settlement is successfully
challenged on appeal, SCE's litigation settlement agreement with the CPUC, if implemented, is expected to allow
SCE to obtain financing which, combined with SCE's increasing cash reserves arising from the 2001 surcharges,
should allow SCE to pay all of its past due obligations by the end of first quarter 2002.  Until these
obligations are paid, resolution of SCE's liquidity crisis and its ability to continue to operate outside of
bankruptcy is uncertain.

Edison International and the nonutility affiliates believe that their corporate financing plans will be
successful in meeting cash requirements for 2001.

Note 2.  Electric Utility Regulatory Matters

CPUC Litigation Settlement Agreement

In November 2000, SCE filed a lawsuit against the CPUC in federal district court in California, seeking a ruling
that SCE is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs
filed with the FERC.  By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE
sought implementation of legislative, regulatory and executive actions to resolve the California energy crisis
and SCE's related financial and liquidity problems.  On October 5, 2001, the district court


Page 6


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

entered a stipulated judgment approving an agreement between the CPUC and SCE to settle the pending lawsuit.

Key elements of the settlement agreement include the following items:

o    The CPUC will establish an account called the procurement-related obligations account (PROACT) as of
     September 1, 2001, which will have an opening balance equal to the amount of SCE's procurement-related
     liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and cash equivalents as of
     that date (approximately $2.5 billion), and less $300 million.  The opening balance of approximately
     $3.6 billion has been verified by the CPUC.

o    During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has
     recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will
     apply to the PROACT, on a monthly or other basis established by the CPUC, the difference between SCE's
     revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC
     to recover in retail electric rates.  Unrecovered obligations in the PROACT will accrue interest from
     September 1, 2001.

o    The parties agree that SCE will recover in retail electric rates its procurement-related obligations in
     the PROACT, with interest, by December 31, 2005.  Subject to certain adjustments, the CPUC will maintain
     current rates (including surcharges) in effect until December 31, 2003, or, if earlier, until the date that
     SCE recovers the entire PROACT balance.  If SCE has not recovered the entire balance by December 31, 2003,
     the unrecovered balance will be amortized for up to an additional two years.  The parties currently project
     that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will
     likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior
     to the end of 2003.

o    If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
     procurement-related obligations, the parties will work together to achieve the securitization.  Proceeds of
     any securitization will be credited to the PROACT when they are actually received.

o    During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed
     by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.

o    SCE intends to apply for CPUC approval to incur up to $250 million of recoverable costs to acquire
     financial instruments and engage in other transactions intended to hedge fuel cost risks associated with
     SCE's retained generation assets and power purchase contracts with qualifying facilities and other
     utilities.  The CPUC indicated that it will schedule proceedings reasonably promptly and consider SCE's
     application on an expedited basis.

o    SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
     by Edison International) prior to the earlier of the date SCE has recovered all of its procurement-related
     obligations in the PROACT or January 1, 2005.  However, if SCE has not recovered all of its
     procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common
     stock dividends, and the CPUC will not unreasonably withhold its consent.

o    To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's
     next general rate case, SCE may make capital expenditures above the level contained in current rates, up to
     $900 million per year, which will be treated as recoverable costs.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

o    Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General to pursue
     and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to claims
     arising from any failure to make payments to the PX or ISO, and similar claims by the State of California or
     its agencies against the same adverse parties.  During the recovery period discussed above, refunds obtained
     by SCE related to its procurement-related liabilities during the recovery period will be applied to the
     balance in the PROACT.

The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past.  SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.

The settlement agreement states that the CPUC shall adopt such decisions or orders it deems necessary to
implement and carry out the provisions of the agreement, with the understanding that the agreement and stipulated
judgment shall be binding and irrevocable upon the parties.  SCE expects that these implementing decisions or
orders will be issued during fourth quarter 2001.

On October 26, 2001, a California consumer group asked a federal court of appeals for a stay of judgment pending
appeal of the federal district court's judgment approving the settlement.  The group alleged that it was denied
due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze.  On
October 30, 2001, the court of appeals granted a temporary stay, and instructed the consumer group to return to
district court to argue the merits of the stay.  On November 9, 2001, the district court denied the consumer
group's request for a stay.  The consumer group indicated that it intends to ask the court of appeals for a stay
of judgment pending appeal.  If the stay of judgment pending appeal is granted, or the settlement is successfully
challenged on appeal, the ability of SCE and the CPUC to implement the settlement agreement would be affected
adversely, which in turn would have an adverse effect on SCE's ability to restore its financial condition, repay
its creditors, and avoid an involuntary bankruptcy petition.

California Department of Water Resources (CDWR) Power Purchases

In accordance with an emergency order signed by the Governor, the CDWR began making emergency power purchases for
SCE's customers on January 18, 2001.  Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not considered
revenue to SCE.  In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to
retail customers being served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5, 2001),
for each kWh the CDWR sells to SCE's customers.  The CPUC determined that the generation-related retail rate
should be equal to the total bundled electric rate (including the 1(cent)per kWh surcharge adopted by the CPUC on
January 4, 2001) less certain nongeneration-related rates or charges.  For the period January 19 through January
31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277(cent)per kWh for power delivered to SCE's
customers.  The CPUC determined that the applicable rate component is 7.277(cent)per kWh (which increased to 10.277(cent)
per kWh for electricity delivered after March 27, 2001, due to the 3(cent)surcharge discussed in Rate Stabilization
Proceedings), for electricity delivered by the CDWR to SCE's retail customers after February 1, 2001, until more
specific rates are calculated.  The CPUC ordered SCE to pay the CDWR within 45 days after the CDWR supplies power
to retail customers, subject to penalties for each day the payment is late.

On September 4, 2001, the CPUC issued a proposed decision authorizing a CDWR revenue requirement of $12.1 billion
to pay its bonds' costs and energy procurement costs for 2001 and 2002.  The proposed decision states that SCE's
allocated share of this revenue requirement (based on a cost-of-service


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

approach) would be approximately $4 billion, and changes SCE's payment from 10.277(cent)per kWh to 10.03(cent)per kWh.  A
balancing account would be established to record the difference between the two rates, with the difference to be
trued up in a subsequent CPUC order.  In comments filed with the CPUC on September 12, 2001, SCE requested that
the CPUC refrain from adopting a final revenue requirement until hearings are held to determine how the revenue
requirement was calculated and its relationship to SCE's revenue requirement to be determined in the
utility-retained generation (URG) proceeding.  In a November 5, 2001, filing with the CPUC, the CDWR reduced its
revenue requirement to $10.0 billion, due to conservation efforts, lower natural gas prices and other changes in
market conditions.  The CPUC has not determined SCE's share of the $10.0 billion.  A final decision on the URG
and CDWR matters is not expected until early 2002.

SCE believes that the intent of AB 1X was for the CDWR to assume full responsibility for purchasing all power
needed to serve the retail customers of electric utilities, in excess of the output of generating plants owned by
the electric utilities and power delivered to the utilities under existing contracts.  However, the CDWR has
stated that it would only purchase power that it considers to be reasonably priced, leaving the ISO to purchase
in the short-term market the additional power necessary to meet system requirements.  The ISO, in turn, took the
position that it will charge SCE for the costs of power it purchases in this manner.  If SCE is found responsible
for purchases of power by the ISO for delivery to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs for the nine months ended September 30, 2001, could increase by as much as $1.6 billion
(which includes bills received for January through July 2001, and an estimate of August and September 2001).
This amount could increase or decrease depending on CPUC or FERC decisions regarding payments and refunds.  In
its March interim order, the CPUC stated that it cannot assume that the CDWR will pay for the ISO purchases and
that it does not have the authority to order the CDWR to do so.  Litigation among certain power generators, the
ISO and the CDWR (to which SCE is not a party), and proceedings before the FERC (to which SCE is a party), may
result in rulings clarifying the CDWR's financial responsibility for purchases of power.  In April 2001, the FERC
issued an order confirming its February 2001 order that the ISO must have a creditworthy buyer for any
transactions.  SCE has not met the ISO's creditworthiness requirements since its credit ratings were downgraded
in mid-January 2001.  As a result, SCE has protested and returned the bills it has received from the ISO.  On
November 7, 2001, the FERC issued an order directing the ISO to invoice CDWR (within 15 days of the date of the
order) for all transactions it entered into on behalf of SCE's customers.  The ISO was also directed to file a
report with the FERC within 15 days from the date of the order indicating overdue amounts from CDWR and a
schedule for payments of those amounts within three months of the date of the order.  In any event, SCE takes the
position that it is not responsible for purchases of power by the CDWR or the ISO on or after January 18, 2001.
SCE cannot predict the outcome of any of these proceedings or issues.

Status of Transition and Power-Procurement Cost Recovery

The electric utility industry restructuring plan instituted a multi-year freeze on the rates that SCE could
charge its customers and transition cost recovery mechanisms designed to allow SCE to recover its stranded costs
associated with generation-related assets.  California's electric utility industry restructuring statute included
provisions to finance a portion of the stranded costs that residential and small commercial customers would have
paid between 1998 and 2001, which allowed SCE to reduce rates by at least 10% to these customers, effective
January 1, 1998.  These frozen rates (except for the surcharges effective in 2001) were to remain in effect until
the earlier of March 31, 2002, or the date when the CPUC-authorized costs for utility-owned generation assets and
obligations were recovered.  However, between May 2000 and June 2001, the prices charged by generators and other
sellers escalated far beyond what SCE could charge its customers.  As a result, SCE incurred a $4 billion
undercollection in transition costs.

SCE's transition costs include power purchases from QF contracts (which are the direct result of prior
legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide
service to customers.  Other costs include the recovery of income tax benefits previously flowed through to
customers, postretirement benefit transition costs and accelerated recovery of investment in SCE's nuclear
plants.  Recovery of costs related to power-purchase QF contracts is permitted through the


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

terms of each contract.  Legislation and regulatory decisions issued prior to the beginning of the rate freeze
called for most of the remaining transition costs to be recovered through the end of the four-year transition
period (not later than March 31, 2002).  Because regulatory and legislative actions that make such recovery
probable were not taken in a timely manner during the energy crisis, as of December 31, 2000, SCE was unable to
conclude that the net regulatory assets related to purchased-power settlements, the unamortized loss on SCE's
generating plant sales in 1998, and various other generation regulatory assets were probable of recovery through
the rate-making process.  As a result, these balances were written off as a charge to earnings at that time.

There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001.  Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism.  State legislation enacted in January 2001 prohibits the sale of SCE's remaining generation assets
until 2006.  SCE stopped selling power from its generation into the ISO and PX markets in January 2001, after
SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges.

CTC revenue has been determined residually (i.e., CTC revenue was the residual amount remaining from monthly
gross customer revenue under the rate freeze after subtracting the revenue requirements for transmission,
distribution, nuclear decommissioning and public benefit programs, and ISO payments and power purchases from the
PX and ISO).  The CTC applied to all customers who were using or began using utility services on or after the
CPUC's 1995 restructuring decision date.  Residual CTC revenue was calculated through the TRA mechanism.  In
accordance with the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue
was transferred from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998.  A previous decision
had called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had
not been any positive residual CTC revenue between May 2000 and June 2001. The cumulative transition cost
undercollection (as recalculated) was $4.0 billion as of September 30, 2001, and $2.9 billion as of December 31,
2000.

Rate Stabilization Proceedings

In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery.  In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.

In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates.  The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition.  The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates.  In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into: whether the holding companies violated CPUC requirements to give priority to the capital
needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the requirements to give priority to the
capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary.  SCE believes the holding company
decision refers to equity investment, not working capital for operating costs.  The CPUC ordered testimony and
briefing on


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

these matters, which SCE filed in May and June 2001.  Neither Edison International nor SCE can predict what
effects this investigation or any subsequent actions by the CPUC may have on either of them.

In March 2001, the CPUC ordered a rate increase in the form of a 3(cent)per kWh surcharge applied only to
going-forward electric power procurement costs, effective immediately, and affirmed that a 1(cent)interim surcharge
granted in January 2001 is now permanent.  The 3(cent)surcharge is to be added to the rate paid to the CDWR.
Although the 3(cent)increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the
CPUC established a rate design in early June 2001.

Also, in the March 2001 order, the CPUC granted a petition previously filed by The Utility Reform Network and
directed that the balance in SCE's TRA account, whether over or undercollected, be transferred on a monthly basis
to the TCBA, retroactive to January 1, 1998.  Previous rules called only for TRA overcollections (residual CTC
revenue) to be transferred to the TCBA.  The CPUC also ordered SCE to transfer the coal and hydroelectric
balancing account overcollections to the TRA on a monthly basis before any transfer of residual CTC revenue to
the TCBA, retroactive to January 1, 1998.  Previous rules called for overcollections in these two balancing
accounts to be transferred directly to the TCBA on an annual basis.  Based upon the transfer of balances into the
TCBA, the CPUC denied SCE's December 2000 filing to have the current rate freeze end, and stated that the
four-year rate freeze will not end until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze.  The CPUC also said that it will
monitor the balances remaining in the TCBA and consider how to address remaining balances in the ongoing
proceedings.  In accordance with the October 2001 settlement with the CPUC, it is expected that the TCBA
mechanism will be discontinued and the PROACT mechanism will be established retroactive to August 31, 2001.

Utility Retained Generation Proceeding

In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
cost-of-service ratemaking for utility retained generation through the end of 2002.  The URG proposal calls for
balancing accounts for SCE-owned generation, QF and interutility contracts, procurement costs and ISO charges
based on either actual or CPUC-authorized revenue requirements.  Under the proposal, the four new balancing
accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for
non-capital-related costs.  In addition, SCE's unamortized nuclear investment would be amortized and recovered in
rates over a 10-year period effective January 1, 2001. Should this application be approved, SCE expects to
reestablish for financial reporting purposes its unamortized nuclear investment and related flow-through taxes as
regulatory assets with a corresponding credit to earnings.  Hearings were held in July 2001.  A final decision is
not expected until early 2002.

Wholesale Electricity Markets

In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds.  In December 2000, the FERC took limited action and failed
to impose a price cap.  SCE filed an emergency petition in the federal court of appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates.  The court denied SCE's
petition in January 2001.

In its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling
coordinators that do not schedule sufficient resources to supply 95% of their respective loads.  In May 2001, the
FERC indicated that it will make a determination regarding the suspension of the underscheduling penalty in a
future order in response to a complaint filed by SCE that asked the FERC to eliminate the penalty.  As of October
31, 2001, SCE's share of the accumulated penalties were estimated to be as much as $360 million.  The ISO has not
billed SCE for any amounts associated with the underscheduling penalty.  SCE cannot predict the outcome of this
matter.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).  The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period.  Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region.  The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices.  An administrative law judge will conduct evidentiary hearings on this matter.  SCE
cannot predict the amount of any potential refunds.  Under the settlement of litigation with the CPUC, refunds
will be applied to the balance in the PROACT.

Note 3.  Business Segments

Edison International's reportable business segments include its electric utility operation segment (SCE), an
unregulated power generation segment (Edison Mission Energy (EME)), and a capital and financial services provider
segment (Edison Capital).

Segment information for the three and nine months ended September 30, 2001, and 2000, was:

                                                     3 Months Ended                   9 Months Ended
                                                      September 30,                    September 30,
----------------------------------------------------------------------------------------------------------

     In millions                                  2001             2000            2001             2000
----------------------------------------------------------------------------------------------------------

                                                                       (Unaudited)
     Operating Revenue:
     Electric utility                          $ 2,726          $ 2,432         $ 5,826          $ 6,115
     Unregulated power generation                1,194            1,061           2,789            2,567
     Capital and financial services                 40               66             155              205
     Corporate and other                            83               94             362              239
----------------------------------------------------------------------------------------------------------

     Consolidated Edison International         $ 4,043          $ 3,653         $ 9,132          $ 9,126
----------------------------------------------------------------------------------------------------------

     Net Income (Loss):
     Electric utility(1)                         $ 651         $    172       $      81         $    441
     Unregulated power generation               (1,026)             191          (1,018)             161
     Capital and financial services                 14               36              50              113
     Corporate and other                           (52)             (39)           (245)            (108)
----------------------------------------------------------------------------------------------------------

     Consolidated Edison International        $   (413)        $    360        $ (1,132)        $    607
----------------------------------------------------------------------------------------------------------


     (1) Net income (loss) available for common stock.

The net loss reported for unregulated power generation in 2001 includes a $1.2 billion after-tax charge related
to the announced sale of two coal-fired generating stations, as discussed in Note 7.

Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.  The
net loss reported in 2001 includes a $127 million charge (after tax) related to the sale of assets discussed in
Note 7.

Total segment assets as of September 30, 2001, were: electric utility, $20 billion; unregulated power generation,
$13 billion; capital and financial services, $4 billion.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4.  Contingencies

In addition to the matters disclosed in these notes, Edison International is involved in 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 proceedings will not materially affect
its results of operations or liquidity.

Energy Crisis Issues

In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.  As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections.  The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001.  A consolidated class
action complaint was filed on August 3, 2001.  On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim.  The motion is scheduled for hearing on December 3, 2001.  SCE believes
that the current and past accounting for the TRA undercollections and related items is appropriate and in
accordance with accounting principles generally accepted in the United States.

Lawsuits have been filed against SCE by various QFs, including geothermal, wind and cogeneration suppliers.  The
lawsuits are seeking payments of at least $833 million for energy and capacity supplied to SCE under QF
contracts, and in some cases for additional damages as well.  Many of these QF lawsuits also seek an order
allowing the suppliers to stop providing power to SCE so that they may sell the power to other purchasers.  The
state court cases have been coordinated before a single trial judge.  SCE has reached agreements with QFs
representing about 97% of the QF renewable and cogeneration capacity provided to SCE.  The agreements provide for
stays of litigation, payments to the QFs upon occurrence of specified conditions, modifications in some cases to
the contract prices going forward, releases and dismissals of the litigation upon payment by SCE.

SCE and Edison International cannot predict the outcome of any of these matters.

Environmental Protection

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 records its environmental 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 deferred credits) at undiscounted amounts.

Edison International's recorded estimated minimum liability to remediate its 42 identified sites is
$114 million.  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


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded
liability by up to $269 million.  The upper limit of this range of costs was estimated using assumptions least
favorable to Edison International among a range of reasonably possible outcomes.  SCE has sold all of its
gas-fueled generation plants and has retained some liability associated with the divested properties.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $45 million of its
recorded liability, through an incentive mechanism. Under this mechanism, SCE will recover 90% of cleanup costs
through customer rates; and shareholders fund the remaining 10%, with the opportunity to recover these costs from
insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible
carriers.  Costs incurred at SCE's remaining sites are expected to be recovered through customer rates.  SCE has
recorded a regulatory asset of $60 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 now be made for these sites.

Edison International expects to clean up its identified sites over a period of up to 30 years.  Remediation
expenditures in each of the next several years are expected to range from $10 million to $25 million.  Recorded
expenditures for the twelve-month period ended September 30, 2001, were $20 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 and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, 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.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $9.5 billion.  SCE and other owners of the
San Onofre and Palo Verde nuclear plants have purchased the maximum private primary insurance available ($200
million).  The balance is covered by the industry's retrospective rating plan that uses deferred premium charges
to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or
costs which exceed the primary insurance at that plant site.  Federal regulations require this secondary level of
financial protection.  The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level,
effective June 1994.  The maximum deferred premium for each nuclear incident is $88 million per reactor, but not
more than $10 million per reactor may be charged in any one year for each incident.  Based on its ownership
interests, SCE could be required to pay a maximum of $176 million per nuclear incident.  However, it would have
to pay no more than $20 million per incident in any one year.  Such amounts include a 5% surcharge if additional
funds are needed to satisfy public liability claims and are subject to adjustment for inflation.  If the public
liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay
claims.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and
Palo Verde.  Decontamination liability and property damage coverage exceeding the primary $500 million also has
been purchased in amounts greater than federal requirements.  Additional insurance covers part of replacement
power expenses during an accident-related nuclear unit outage.  These policies are issued primarily by mutual
insurance companies owned by utilities with nuclear facilities.  If losses at any nuclear facility covered by the
arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed
retrospective premium adjustments of up to $18 million per year.  This amount is expected to increase to
$35 million on November 15, 2001.  Insurance premiums are charged to operating expense.


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Spent Nuclear Fuel

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

SCE, as operating agent, has primary responsibility for the interim storage of its spent nuclear fuel at San
Onofre.  Current capability to store spent fuel is estimated to be adequate through 2005.  SCE is conducting
engineering studies and evaluating the cost of constructing an interim storage facility for Units 2 and 3.  The
development and construction of an interim fuel storage facility for Unit 1 is in progress as part of the
decommissioning project.  Costs for the interim fuel storage facility for Unit 1 are fully funded from the
decommissioning trust.

Extended delays by the DOE could lead to consideration of costly alternatives involving siting and environmental
issues.  SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through
April 6, 1983 (approximately $24 million, plus interest).  SCE is also paying the required quarterly fee equal to
one mill per kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.

Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003 for Unit 2, and until 2004 for
Units 1 and 3.  Arizona Public Service Company, operating agent for Palo Verde, is constructing an interim fuel
storage facility that is expected to be completed in 2002.

Paiton Project

A wholly owned subsidiary of EME (Paiton Energy) owns a 40% interest and has a $495 million investment (at
September 30, 2001) in the Paiton project, a 1,230-MW coal-fired power plant in Indonesia.  As discussed more
fully in Edison International's 2000 Annual Report on Form 10-K, Paiton Energy is in continuing negotiations on a
long-term restructuring of the revenue schedule under a long-term power purchase agreement with the state-owned
electricity company.  Paiton Energy and the state-owned electricity company agreed on a Phase I Agreement for the
period from January 1, 2001, through June 30, 2001.  This agreement provided for fixed monthly payments totaling
$108 million over its six-month duration and for the payment for energy delivered to the state-owned electricity
company from the plant during this period.  The state-owned electricity company made all fixed payments due under
the Phase I Agreement totaling $108 million as scheduled.  Paiton Energy received lender approval of the Phase I
Agreement and has also entered into a lender interim agreement under which lenders have agreed to interest-only
payments and to deferral of principal payments while Paiton Energy and the state-owned electricity company seek a
long-term restructuring.  The lenders have agreed to extend that agreement through December 31, 2001.

Paiton Energy and the state-owned electricity company intended to complete the negotiations of the future phases
of a new long-term revenue schedule during the six-month duration of the Phase I Agreement.  Although Paiton
Energy and the state-owned electricity company did not complete negotiations on a long-term restructuring of the
revenue schedule by June 30, 2001, Paiton Energy and the state-owned electricity company signed an agreement
providing for an extension of the Phase I Agreement from July 1, 2001, to September 30, 2001.  The lenders
approved this extension of the Phase I Agreement.  All fixed payments totaling $59 million due under that
extension of the Phase I Agreement have been made by the state-owned electricity company.  Paiton Energy and the
state-owned electricity company have been actively negotiating a long-term restructuring of the revenue schedule
and have made substantial progress.  However, that long-term restructuring was not completed prior to the
expiration of the extended Phase I Agreement.  Paiton Energy and the state-owned electricity company have
therefore signed an agreement providing for an additional extension of this Phase I Agreement to December 31,
2001.  Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes
that the state-owned electricity company will continue to agree to make payments for electricity on an interim
basis


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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

beyond September 30, 2001, while negotiations regarding the long-term restructuring of revenue schedule
continue.  Although completion of negotiations may be delayed, Paiton Energy continues to believe that
negotiations on the long-term restructuring of the revenue schedule will be successful.

Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new
long-term revenue schedule could require a renegotiation of the Paiton project's debt agreements.  The impact of
any such renegotiations with the state-owned electricity company, the Indonesian government or the project's
creditors on EME's expected return on its investment in the Paiton project is uncertain at this time; however,
EME believes that it will ultimately recover its investment in the project.

Note 5.  Derivative Instruments and Hedging Activities

Effective January 1, 2001, Edison International adopted a new accounting standard for derivative instruments and
hedging activities.  The standard establishes accounting and reporting standards requiring that all derivative
instruments be recognized on the balance sheet at their fair value unless they meet an exception.  The standard
requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge
accounting criteria are met.  For derivatives that qualify for hedge accounting, depending on the nature of the
hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or
firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized
in earnings.  The ineffective portion of a derivative's change in fair value is immediately recognized in
earnings.  The majority of EME's physical long-term power and fuel contracts, and the similar business activities
of EME's affiliates, qualify under this exception.

EME's primary risk exposures arise from changes in electricity and fuel prices, interest rates and fluctuations
in foreign currency exchange rates.  These risks are managed, in part, by using derivative financial instruments
in accordance with established policies and procedures.  On the implementation date, all derivatives were
recorded at fair value unless the derivatives qualify for the normal sales and purchases exception.  This
exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery
will occur, the pricing provisions are clearly and closely related to the contracted prices and the documentation
requirements of the new accounting standard are met.

The majority of EME's remaining risk management activities, including forward sales contracts from the Homer City
plant, qualify for treatment under the new accounting standard as cash flow hedges with appropriate adjustments
made to other comprehensive income.  The hedge agreement EME has with the State Electricity Commission of
Victoria for electricity prices from the Loy Yang B project in Australia qualifies as a cash flow hedge.  This
contract could not qualify under the normal sales and purchases exception because financial settlement of the
contract occurs without physical delivery.  Some of EME's derivatives did not qualify for either the normal sales
and purchases exception or as cash flow hedges.  These derivatives are recorded at fair value with subsequent
changes in fair value recorded in the income statement.  The majority of EME's risk management activities related
to the Ferrybridge and Fiddler's Ferry power plants in the United Kingdom and fuel contracts related to the
Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash flow
hedges.  In both these situations, EME could not conclude, based on information available at September 30, 2001,
that the timing of generation from these power plants met the probable requirement for a specific forecasted
transaction under the new accounting standard.  Accordingly, the majority of these contracts are recorded at fair
value, with subsequent changes in fair value reflected in nonutility power generation revenue in the consolidated
income statement.

As a result of the adoption of the new standard, Edison International expects its quarterly earnings from its EME
subsidiary to be more volatile than earnings reported under the prior accounting policy.  On January 1, 2001, EME
recorded a $6 million (after tax) increase to net income and a $230 million (after tax) decrease to other
comprehensive income as a cumulative change in the accounting for derivatives.  During the quarter ended
September 30, 2001, EME recorded an $18 million (after tax) decrease to other comprehensive income resulting from
unrealized holding losses on interest rate swap of its affiliates.


Page 16


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EME has recorded net gains of $0.5 million and $2 million in the three and nine months ended September 30, 2001,
respectively, representing the amount of cash flow hedges' ineffectiveness reflected in nonutility power
generation revenue in the consolidated income statement.

The new accounting standard provides guidance on the normal sales and purchases exception that affects
classification of commodity contracts.  EME did not use the normal sales and purchases exception for forward
sales contracts from the Homer City plant (as defined in the accounting standard) due to net settlement
procedures with counterparties for the period between January 1, 2001, and June 30, 2001.  Effective July 1,
2001, accounting guidance modified the normal sales and purchases exception to include electricity contracts,
which include terms that require physical delivery by the seller in quantities that are expected to be sold in
the normal course of business.  Accordingly, EME qualified to use the normal sales and purchases exception for
its Homer City forward sales contracts commencing July 1, 2001.  Based on this accounting guidance, on July 1,
2001, EME eliminated the value of its Homer City forward sales contracts from its consolidated balance sheet.
The cumulative effect of this change in accounting is reflected as a $16 million (after tax) decrease to other
comprehensive income.

EME had previously applied the normal sales and purchases exception for long-term commodity contracts entered
into by its First Hydro plant to buy and sell electricity for the period between January 1, 2001, and June 30,
2001.  However, the criteria applicable to the buyer of power outlined under the implementation guidance
precluded the contracts from qualifying under the normal sales and purchases exception as of July 2001.
Accordingly, EME recorded a $15 million (after tax) increase to net income as the cumulative effect of change in
accounting for derivatives in the consolidated income statement as of July 1, 2001.  All subsequent changes in
the fair value of these contracts will be reflected in nonutility power generation in the consolidated income
statement.

Currently, EME is using the normal sales and purchases exception for the majority of its fuel supply agreements.
However, recently issued accounting guidance precludes contracts, which have variable quantities from qualifying
under the normal sales and purchases exception.  EME is evaluating the impact of this implementation guidance,
which will be effective April 1, 2002.

The unrealized losses on cash flow hedges at September 30, 2001, included losses on interest rate swaps of EME's
affiliates and the hedge agreement EME has with the State Electricity Commission of Victoria for electricity
prices from the Loy Yang B project in Australia.  This contract also could not qualify under the normal sales and
purchases exception because financial settlement of the contract occurs without physical delivery.  Approximately
69% of EME's accumulated other comprehensive loss at September 30, 2001, related to unrealized losses on cash
flow hedges resulting from the Loy Yang B contract.  These losses arise from current forecasts of future
electricity prices in these markets greater than EME's contract prices.  Although the contract prices are below
the current market prices, EME believes that prices included in its contract mitigates price risk associated with
future changes in market prices and are at prices that meet EME's profit objectives.  Assuming the long-term
contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future
changes in the forecast of market prices for contract volumes included in this agreement will increase or
decrease EME's other comprehensive income without significantly affecting EME's net income.

SCE recorded its interest rate swap agreement (terminated January 5, 2001) and its block forward power-purchase
contracts at fair value on its balance sheet effective January 1, 2001.  Due to downgrades in SCE's credit
ratings and SCE's failure to pay its obligations to the PX, the PX suspended SCE's market trading privileges and
sought to liquidate SCE's remaining block forward contracts.  Before the PX could do so, on February 2, 2001, the
state seized the contracts, which at that time had an unrealized gain of approximately $500 million.  On
September 30, 2001, a federal appeals court ruled that the Governor of California acted illegally when he seized
the power contracts held by SCE.  In conjunction with its settlement agreement with the CPUC, SCE has agreed to
release any claim for compensation against the state for these contracts.  As of September 30, 2001, SCE did not
have any derivatives as defined by the new accounting standard.


page 17


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6.  Purchased Power

SCE purchased power through the PX from April 1998 through mid-January 2001.  Since January 18, 2001, power
purchased by the CDWR or through the ISO for SCE's customers is not considered a cost to SCE, since SCE is acting
as an agent for these transactions.  Further, amounts billed to and collected from its customers for these power
purchases are being remitted to the CDWR and are not considered revenue to SCE.  See further discussion in
Note 2.  SCE also has bilateral forward contracts with other entities and power-purchase contracts with other
utilities and QFs' Purchased power detail is provided below:

                                                                 3 Months Ended          9 Months Ended
                                                                  September 30,           September 30,
---------------------------------------------------------------------------------------------------------

         In millions                                           2001        2000         2001       2000
---------------------------------------------------------------------------------------------------------

         PX/ISO:
         Purchases                                           $   26      $ 3,079      $   660    $ 5,121
         Generation sales                                         2        2,019          324      3,737
---------------------------------------------------------------------------------------------------------

         Purchased power - PX/ISO - net                          24        1,060          336      1,384
         Purchased power - bilateral contracts                   53           --          142         --
         Purchased power - interutility/QF contracts            682          855        2,812      1,719
---------------------------------------------------------------------------------------------------------

         Total                                               $  759      $ 1,915      $ 3,290    $ 3,103
---------------------------------------------------------------------------------------------------------


Note 7.  Acquisitions and Dispositions

EME

In October 2001, EME announced the sale of two of its United Kingdom based coal stations, Fiddler's Ferry and
Ferrybridge, to two wholly owned subsidiaries of American Electric Power for an aggregate purchase price of 650
million pounds Sterling.  EME recorded a charge of $1.9 billion ($1.15 billion after tax) in the third quarter of
2001 to reduce the carrying value of the assets held for sale to reflect estimated fair value less the cost to
sell and related currency adjustments.  EME expects the transaction to close before the end of 2001. The plants
were acquired in 1999 for 1.3 billion pounds Sterling.

In September 2001, EME completed the sale of its 50% interest in the Saguaro project.  Proceeds from the sale
were approximately $67 million.  EME recorded a gain on sale of $43 million ($24 million after tax).

During the second quarter of 2001, EME completed the purchase of additional shares of Contact Energy Ltd. for
NZ$152 million, increasing its ownership interest from 43% to 51%.  Accordingly, EME began accounting for Contact
Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest.  Prior to
June 1, 2001, EME used the equity method of accounting for Contact Energy.  To finance this purchase, EME obtained
a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility, which is to be syndicated
by the bank.  In addition to other security arrangements, a security interest over all Contact Energy shares held
has been provided as collateral.  From June 2001 to September 2001, EME issued through one of its subsidiaries
new preferred securities to primarily repay the bridge loan.  In October 2001, EME announced its intention to
acquire the remaining 49% of Contact Energy, thereby increasing its ownership interest to 100%.

In June 2001, EME sold a 50% interest in its Sunrise project to Texaco for $84 million (50% of the project costs,
prior to commercial operation).  Commercial operation commenced in late June 2001.

Also in June 2001, EME completed the sale of its 25% interest in the Hopewell project to the existing partner.
Proceeds from the sale were $27 million.  EME recorded a gain on the sale of $5 million ($2 million after tax).


page 18


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Edison Enterprises

During second quarter 2001, Edison Enterprises, a wholly owned subsidiary of Edison International, decided to
sell most of its assets.  On August 1, 2001, it sold a subsidiary (principally engaged in the business of
providing residential security services and residential electrical warranty repair services) to ADT Security
Services, Inc., a unit of Tyco International Ltd.

In June 2001, another Edison Enterprises subsidiary (engaged in the business of commercial energy management)
entered into a letter of intent to sell substantially all of its assets to its current management.  The sale was
completed October 18, 2001.

The carrying amount of the net assets held for sale was $380 million at June 30, 2001.  Edison International
recorded a charge of $117 million (after tax) in the second quarter 2001 to reduce the carrying value of the
assets of the businesses held for sale based on estimated proceeds from the sales.  The carrying amount of the
net assets held for sale was $48 million at September 30, 2001.  Edison International recorded an additional
charge of $10 million (after tax) in the third quarter 2001 upon completion of the Edison Enterprises subsidiary
sale.  The businesses held for sale incurred net operating losses of $17 million and $23 million in the
nine-month periods ended September 30, 2001, and 2000, respectively.

Note 8.  New Accounting Standards

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets.  Although the statement supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived
assets to be disposed of by sale.  Under the new accounting standard, asset write-downs from discontinuing a
business segment will be treated the same as other assets held for sale.  The new standard also broadens the
financial statement presentation of discontinued operations to include the disposal of an asset group (rather
than a segment of a business).  The standard is effective for Edison International beginning January 1, 2002,
unless early adoption is implemented.

In July and August 2001, three new accounting standards were issued: Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (record goodwill for excess of
costs over the net assets acquired).

The new Goodwill and Other Intangibles standards requires that companies cease amortizing goodwill, effective
January 1, 2002.  Goodwill initially recognized after June 30, 2001, will not be amortized.  Goodwill on the
balance sheet at June 30, 2001, will be amortized until January 1, 2002.  Under the new standard, goodwill will
be tested for impairment using a fair-value approach when events or circumstances occur indicating that
impairment might exist.  Also, a benchmark assessment for goodwill is required within six months of the date of
adoption of the standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred. When the liability is
initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived
asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles
the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application encouraged.


Page 19



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Edison International is studying the impact of the new Asset Retirement Obligations, Asset Impairment and
Goodwill and Other Intangibles standards, and is unable to predict at this time the impact on its financial
statements.  Edison International does not anticipate any material impact on its results of operations or
financial position from the Business Combinations standard.




Page 20



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

California's investor-owned electric utilities, including Southern California Edison Company (SCE), have been
facing a crisis resulting from deregulation of the generation side of the electric industry through legislation
enacted by the California Legislature and decisions issued by the California Public Utilities Commission (CPUC).
Under the legislation and CPUC decisions, prices for wholesale purchases of electricity from power suppliers are
set by markets while the retail prices paid by utility customers for electricity delivered to them remain frozen
at June 1996 levels except for the 10% residential rate reduction starting in 1998 and the 4(cent)-per-kWh surcharge
effective in 2001.  See further discussion of the CPUC rate increases in Rate Stabilization Proceedings.
Beginning in May 2000, SCE's costs to obtain power (at wholesale electricity prices) for resale to its customers
substantially exceeded revenue from frozen rates.  The shortfall was accumulated in the transition revenue
account (TRA), a CPUC-authorized regulatory asset, prior to the retroactive transfer of the TRA balance to the
transition cost balancing account (TCBA), as discussed below.  SCE has borrowed significant amounts of money to
finance its electricity purchases, creating a severe liquidity crisis at SCE.

On October 5, 2001, a federal district court in California entered a stipulated judgment approving an October 2,
2001, agreement between the CPUC and SCE to settle a lawsuit.  SCE expects that the settlement agreement and the
CPUC actions contemplated in the agreement should enable SCE to recover its previously undercollected power
procurement costs and repay its outstanding overdue obligations.  According to the terms of the settlement
agreement, in the fourth quarter of 2001, it is expected that SCE will establish (retroactive to August 31, 2001)
a $3.6 billion account for these previously incurred procurement costs which will be called the
procurement-related obligations account (PROACT).  During a period beginning on September 1, 2001, and ending on
the earlier of the date that SCE has recovered all of its procurement-related obligations recorded in the PROACT
or December 31, 2005, SCE will apply to the PROACT the difference between SCE's revenue from retail electric
rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric
rates.  The settlement also calls for the end of the TCBA mechanism as of August 31, 2001, and continuation of
the rate freeze (including surcharges) until the earlier of December 31, 2003, or the date that SCE recovers the
account balance.  If SCE has not recovered the entire balance by the end of 2003, the remaining balance will be
amortized in retail rates for up to an additional two years.  For further details on the settlement with the
CPUC, see CPUC Litigation Settlement Agreement.  On October 26, 2001, a California consumer group asked a federal
court of appeals for a stay of judgment pending appeal of the federal district court's judgment approving the
settlement.  The group alleged that it was denied due process and that the CPUC had no authority to agree with
SCE to violate the statutory rate freeze.  On October 30, 2001, the court of appeals granted a temporary stay,
and instructed the consumer group to return to district court to argue the merits of the stay.  On November 9,
2001, the district court denied the consumer group's request for a stay.  The consumer group indicated that it
intends to ask the court of appeals for a stay of judgment pending appeal.  If the stay of judgment pending
appeal is granted, or the settlement is successfully challenged on appeal, the ability of SCE and the CPUC to
implement the settlement agreement would be affected adversely, which in turn would have an adverse effect on
SCE's ability to restore its financial condition, repay its creditors and avoid an involuntary bankruptcy petition.

Accounting principles generally accepted in the United States permit SCE to defer costs and record regulatory
assets if those costs are determined to be probable of recovery in future rates.  When SCE determines that
regulatory assets, such as the TRA and the TCBA, are no longer probable of recovery through future rates, they
are written off.  The TCBA is a regulatory balancing account that tracks the recovery of generation-related
transition costs, including stranded investments.  SCE assessed the probability of recovery of the undercollected
costs that were previously recorded in the TCBA in light of the CPUC's March 27, 2001, and April 3, 2001,
decisions, including the retroactive transfer of balances from SCE's TRA to its TCBA and related changes that are
discussed in more detail in Rate Stabilization Proceedings.  These decisions and other regulatory and legislative
actions did not meet SCE's prior expectation that the CPUC would provide adequate cost recovery mechanisms.  As a
result, Edison International's financial results for the year ended December 31, 2000, included an after-tax
charge at SCE of approximately $2.5 billion ($4.2 billion on a pre-tax basis), reflecting a write-off of the TCBA
and net regulatory assets to be recovered through the TCBA mechanism, as of December 31, 2000.  Transition costs
in excess of transition revenue were also incurred during the first six months of 2001,


page 21


resulting in a charge against earnings in the amount of $724 million (after tax) through June 30, 2001.  This
resulted in further material declines in reported common shareholders' equity, particularly in light of the
CPUC's failure to provide SCE with sufficient rate increases to cover its ongoing costs and obligations during
that period.

The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the
significantly negative effect on the financial condition of SCE of undercollections recorded in the TRA and TCBA,
the current status of the undercollections, the impact of the CPUC's March 27, 2001, decisions and related
matters, and the expected resolution of the current crisis through implementation of the CPUC litigation
settlement agreement.

Results of Operations

Earnings

Edison International recorded losses of $1.27 per share and $3.47 per share, respectively, for the three and nine
months ended September 30, 2001.  The losses reflect a one-time charge at Edison Mission Energy (EME) of
$1.15 billion (after tax), or $3.54 per share, as a result of the decision to sell the Ferrybridge and Fiddler's
Ferry generating stations.  The year-to-date loss also reflects a one-time charge at Edison Enterprises in second
quarter 2001 of $117 million (after tax), or 36(cent)per share, as a result of the decision to sell two wholly owned
subsidiaries.  In addition, the year-to-date loss reflects $724 million (after tax), or $2.22 per share, of SCE's
transition costs in excess of transition revenue during the first six months of 2001, partially offset by
recovery of $518 million (after tax), or $1.59 per share, of previously undercollected transition costs during
the third quarter of 2001 due to the CPUC-approved surcharges (1(cent) per kWh in January and 3(cent)per kWh in June) that
were billed in 2001.  For financial reporting purposes, these undercollected or overcollected costs are no longer
accumulated in the TCBA.  Excluding the charge at EME, SCE's net undercollected transition costs, and the charge
at Edison Enterprises, Edison International earned 68(cent)and $1.06 per share for the three and nine months ended
September 30, 2001, respectively, compared to $1.11 and $1.81 per share for the year-earlier periods.  Excluding
the net undercollected transition costs, SCE's earnings were 41(cent)and 88(cent)per share, respectively, compared with
53(cent)and $1.32 per share for the same periods last year.  The quarterly and year-to-date decreases for SCE were
primarily due to higher interest expense resulting from SCE's deteriorated financial condition, as well as lower
kWh sales.  The year-to-date decrease at SCE was also due to lower earnings related to the February 2001 fire and
resulting outage at San Onofre Nuclear Generating Station, partially offset by lower operation and maintenance
costs.  Excluding its one-time charge, EME earned 39(cent)and 42(cent)per share in the three- and nine-month periods
ended September 30, 2001, respectively, compared to earnings of 59(cent)and 48(cent)per share for the prior-year
periods.  The decreased earnings reflect lower pool prices and capacity payments in the United Kingdom and a
stock plan adjustment in 2000, partially offset by higher energy prices for EME's domestic projects and increased
earnings from oil and gas activities.  Edison Capital's earnings were 4(cent)and 15(cent)per share, respectively,
compared with 11(cent)and 34(cent)per share for the year-earlier periods.  The decreases were primarily due to lower
earnings from leveraged lease transactions and affordable housing portfolios and the termination of mezzanine
financing, partially offset by a net gain on asset sales and lower general and administrative expenses.  Mission
Energy Holding Company (parent only), which was formed earlier this year, recorded a loss of 8(cent)per share for
both the three and nine months ended September 30, 2001, due to the issuance of new debt during the third quarter
of 2001.  Edison Enterprises and Edison International (parent company) incurred losses of 8(cent)and 67(cent)per share in
the three and nine months ended September 30, 2001, respectively, compared to losses of 12(cent)and 33(cent)per share for
the comparable periods in 2000.  The decreased quarterly loss in 2001 reflects lower operating expenses at the
parent company.  The year-to-date loss in 2001 reflects Edison Enterprises' one-time, after-tax adjustment
against earnings of $117 million, or 36(cent)per share, to reflect the decision to sell two wholly owned subsidiaries
of Edison Enterprises.  See discussion in Acquisitions and Dispositions. Excluding the one-time adjustment, the
decreased year-to-date losses in 2001 reflect lower operating expenses at Edison Enterprises.

Operating Revenue

From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider (thus becoming direct access customers) or continue to have


Page 22


SCE purchase power on their behalf.  Most direct access customers were billed by SCE, but given a credit for the
generation portion of their bills.  On September 20, 2001, the CPUC suspended the ability of retail customers to
select alternative providers of electricity until the California Department of Water Resources (CDWR) stops
buying power for retail customers.

During 2000, as a result of the power shortage in California, SCE's customers on interruptible rate programs
(which provide for a lower generation rate with a provision that service can be interrupted if needed, with
penalties for noncompliance) were asked to curtail their electricity usage at various times.  As a result of
noncompliance with SCE's requests, those customers were assessed significant penalties.  On January 26, 2001, the
CPUC waived the penalties assessed to noncompliant customers after October 1, 2000, until the interruptible
programs can be reevaluated.

Electric utility revenue increased for the three months ended September 30, 2001, and decreased for the nine
months ended September 30, 2001, compared to the same periods in 2000.  Because SCE no longer supplies its
customers with all of their electricity needs (since mid-January 2001), electric utility revenue was reduced by
$664 million and $1.4 billion, respectively, for the three and nine months ended September 30, 2001.  Amounts SCE
bills to and collects from its customers for electric power purchased and sold by the CDWR or through the
Independent System Operator (ISO) on behalf of SCE's customers (beginning January 18, 2001) are being remitted to
the CDWR and are not considered revenue to SCE.  See CDWR Power Purchases discussion.  The quarterly increase was
primarily due to the effects of the 4(cent)-per-kWh (1(cent)in January and 3(cent)in June) surcharge effective in 2001, as
well as the credit given to direct access customers during third quarter 2000. The direct access credits
decreased during the third quarter of 2001 due to a fewer number of direct access customers in 2001, as well as a
lower basis used in calculating the amount of the credit.  The lower basis in 2001 relates to SCE's frozen rates,
as opposed to the California Power Exchange (PX) market price, which was the basis in 2000.  These increases were
partially offset by an 8% decrease in retail sales volume.  The year-to-date decrease in electric utility revenue
was the result of a decrease in retail sales volume primarily attributable to conservation efforts, as well as a
decrease in revenue related to operation and maintenance services.  SCE is no longer providing these services to
the independent power companies who now own the generating stations SCE sold in 1998.  The effect of the reduced
credits given to direct access customers partially offsets the decreases discussed above for the year-to-date
period.

More than 94% of electric utility revenue was from retail sales.  Retail rates are regulated by the CPUC and
wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC).

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

Nonutility power generation revenue increased for both the quarter and year-to-date period ended September 30,
2001, primarily due to increases at EME related to its cogeneration projects, its oil and gas activities, its
trading activities and its increased ownership in Contact Energy (see discussion in Acquisitions and Dispositions
section), partially offset by decreases at its Ferrybridge, Fiddler's Ferry and First Hydro plants due to lower
energy prices in the UK.  The quarterly increase was partially offset by lower revenue from EME's Illinois plants
due to lower dispatch of the coal units as a result of lower market prices during third quarter 2001.

Due to warmer weather during the summer months, EME's nonutility power generation revenue related to its Homer
City plant and the Illinois plants is usually higher during the third quarter of each year.  Higher summer
pricing for EME's energy projects located on the western coast of the United States generally causes materially
higher third quarter nonutility power generation revenue than other quarters of the year.  EME's First Hydro,
Ferrybridge and Fiddler's Ferry plants, and Iberian Hy-Power plants are expected to contribute more to nonutility
power generation revenue during the winter months.

Financial services and other revenue decreased for the three months ended September 30, 2001, and increased for
the nine months ended September 30, 2001.  The quarterly decrease was mostly due to the sale of an Edison
International nonutility subsidiary in August 2001 and a decrease at Edison Capital related to lower revenue from
leveraged leases and affordable housing projects and the termination of the Ferrybridge and Fiddler's Ferry
financing.  These decreases were partially offset by increases at two other


Page 23


Edison International nonutility subsidiaries resulting from the selling of real estate and providing operation
and maintenance services.  Beginning in January 2001, an Edison International nonutility subsidiary began
providing operation and maintenance services to the independent power companies who now own the generation
stations SCE sold in 1998.  From 1998 through December 2000, SCE was providing these services.  The year-to-date
increase was primarily due to the selling of real estate and providing operation and maintenance services,
partially offset by a decrease in Edison Capital's revenue from leveraged lease transactions.

Operating Expenses

Fuel expense increased for both the three and nine months ended September 30, 2001, compared to the prior-year
periods.  The increases were primarily due to increases at EME resulting from its increased ownership in Contact
Energy and its Ferrybridge and Fiddler's Ferry plants.  The quarterly increase was partially offset by a decrease
at EME's Illinois plants.  The year-to-date increase also reflects an increase in fuel costs from EME's Doga
plant during the first six months of 2001.  A fuel-related refund resulting from a settlement with another
utility that SCE recorded in the second quarter of 2000 caused lower fuel expense in 2000.

Purchased-power expense decreased for the three months ended September 30, 2001, and increased for the nine
months ended September 30, 2001, compared to the same periods in 2000.  The quarterly decrease was primarily due
to the absence of purchases from the PX and ISO in 2001, as well as a reduction in qualifying facilities (QF)
power costs. In December 2000, the FERC eliminated the requirement that SCE buy and sell all power through the PX
and ISO.  Due to SCE's noncompliance with the PX's tariff requirement for posting collateral for all transactions
in the day-ahead and day-of markets as a result of the downgrade in its credit rating, the PX suspended SCE's
market trading privileges effective mid-January 2001.  See further discussion of SCE's liquidity crisis in
Financial Condition. These quarterly decreases were partially offset by an increase related to interutility
contracts.  The year-to-date increase was the result of increased purchased-power expenses related to QFs,
bilateral contracts and interutility contracts, partially offset by the absence of PX/ISO purchased-power expense
in 2001.  See Purchased Power table in Note 6 to the Consolidated Financial Statements.  See further discussion
in CDWR Power Purchases.

Prior to April 1998, federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs
at CPUC-mandated prices even though energy and capacity prices under many of these contracts are generally higher
than other sources.  These contracts expire on various dates through 2025.  Purchased-power expense related to
QFs decreased for the three months ended September 30, 2001, and increased for the nine months ended September
30, 2001, compared to the year-earlier periods.  The decrease is primarily due to lower priced natural gas, which
impacts the short-run avoided cost factor of the QF contracts.  The increase was primarily due to the short-run
avoided cost factor of the QF contracts causing a significant increase in the payments to QFs.  The increases
related to bilateral contracts were the result of SCE not having these contracts in 2000.  The quarterly decrease
in purchased-power expense related to interutility contracts, as well as the year-to-date increase related to
interutility contracts were volume-driven.

PX/ISO purchased-power expense increased significantly between May 2000 and mid-January 2001, due to increased
demand for electricity in California, dramatic price increases for natural gas (a key input of electricity
production), and structural problems within the PX and ISO.

Provisions for regulatory adjustment clauses increased for the three and nine months ended September 30, 2001,
compared to the year-earlier periods.  The increases resulted from SCE no longer accumulating undercollected
transition costs in the TCBA for financial reporting purposes.  The increases were partially offset by
undercollections related to the administration of energy conservation programs and other public benefits programs
in 2001 and undercollections related to the coal generation and hydroelectric balancing accounts in 2001.

Other operation and maintenance expense increased for both the three and nine months ended September 30, 2001,
compared to the same periods in 2000, primarily due to increased plant operating expenses at EME's Illinois
plants and from its increased ownership in Contact Energy, as well as


Page 24


increased expenses at a nonutility subsidiary related to the sale of real estate.  These increases also reflect a
decrease in third quarter 2000 at EME related to accrued compensation expense reflecting lower valuation of the
exchange offer for the affiliate stock option plan.

Depreciation, decommissioning and amortization expense decreased significantly for the three and nine months
ended September 30, 2001, primarily due to a decrease in SCE's nuclear investment amortization expense.  SCE's
unamortized nuclear investment regulatory asset was included in the December 31, 2000, write-off.

The write-down of nonutility assets was recorded by EME in third quarter 2001 to primarily reflect the decision
to sell the Ferrybridge and Fiddler's Ferry generating stations.  In second quarter 2001, a write-down of
nonutility assets was recorded by Edison Enterprises to reflect the decision to sell two wholly owned
subsidiaries.  See further discussion in Acquisitions and Dispositions.

Other Income and Deductions

Interest and dividend income decreased for the three months ended September 30, 2001, compared to the
year-earlier period, primarily due to lower balancing account undercollections at SCE.

Other nonoperating income increased for the three months ended September 30, 2001, and decreased for the nine
months ended September 30, 2001, compared to the year-earlier periods.  The quarterly increase was primarily due
to gain on sale of interest in an energy project at EME.  The year-to-date decrease was primarily due to SCE's
second quarter 2000 gains on sales of equity investments and the result of CPUC-approved shareholder incentives
related to QF contract restructurings in first quarter 2000. The year-to-date decrease also reflects the gain on
sale of an equity investment at Edison International's insurance subsidiary in first quarter 2000, partially
offset by an increase at EME resulting from gains on sales of interests in energy projects in 2001.

Interest expense - net of amounts capitalized increased for both the three and nine months ended September 30,
2001, compared to the year-earlier periods, reflecting additional long-term debt at SCE and Mission Energy
Holding (parent only), and higher short-term debt balances at both SCE and the parent company.  Decreases in
interest expense at EME reflecting payments on long-term debt and favorable changes in foreign exchange rates
partially offset the increases in interest expense for the year-to-date period ended September 30, 2001.

Other nonoperating deductions decreased for both the quarter and year-to-date period ended September 30, 2001,
compared to the same periods in 2000.  The decreases were mostly due to lower accruals at SCE for regulatory
matters in 2001, partially offset by an increase in EME's minority interest arising from its increased ownership
of Contact Energy.

Income Taxes

Income taxes decreased for the three and nine months ended September 30, 2001, compared to the year-earlier
periods.  The decreases were the result of income tax benefits at EME ($745 million) arising from the third
quarter 2001 one-time charge reflecting the decision to sell the Ferrybridge and Fiddler's Ferry generating
stations.  The quarterly decrease was partially offset by the recovery of previously undercollected transition
costs at SCE due to the CPUC-approved surcharges (1(cent)per kWh in January and 3(cent)per kWh in June) that were billed
in 2001.  The year-to-date decrease also reflects income tax benefits at Edison Enterprises arising from the
one-time charge in second quarter 2001 to reflect the decision to sell two wholly owned subsidiaries and at SCE
($203 million) arising from the net transition costs in excess of transition revenue.

Financial Condition

Edison International's liquidity has been primarily affected by debt maturities, access to capital markets,
dividend payments, capital expenditures, asset sales, investments in partnerships and unconsolidated
subsidiaries, and SCE's power purchases. Capital resources include cash from operations, asset sales and external
financings.  As a result of SCE's financial condition (further discussed in Liquidity Issues), at


Page 25


September 30, 2001, the fair market value of approximately $1.6 billion of Edison International's short-term debt
was approximately 90% of its carrying value.

Liquidity Issues

SCE

Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001.  This resulted in
undercollections in the TRA and TCBA.  Undercollections, coupled with SCE's anticipated near-term capital
requirements (detailed in the Cash Flows from Investing Activities section of Financial Condition) and the
adverse reaction of the credit markets to regulatory uncertainty regarding SCE's ability to recover its power
procurement costs, materially and adversely affected SCE's liquidity.  As a result of its liquidity crisis, SCE
has taken and is taking steps to conserve cash so that it can continue to provide service to its customers.  As a
part of this process, beginning in January 2001, SCE suspended payments of certain obligations for principal and
interest on outstanding debt and for purchased power.  As of October 31, 2001, SCE had $3.3 billion in
obligations that were unpaid and overdue including: (1) $940 million to the PX or ISO; (2) $1.2 billion to QFs;
(3) $231 million in PX energy credits for energy service providers; (4) $531 million of matured commercial paper;
and (5) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the
energy crisis.  As applicable, unpaid obligations will continue to accrue interest.

SCE's failure to pay when due the principal amount of the 5-7/8% and 6-1/2% senior unsecured notes constituted a
default on each series, entitling those noteholders to exercise their remedies.  Such failure and the failure to
pay commercial paper when due could also constitute an event of default on all the other series of senior
unsecured notes (totaling $2.2 billion of outstanding principal) if the trustee or holders of 25% in principal
amount of the notes give a notice demanding that the default be cured, and SCE does not cure the default within
30 days.  Such failures are also an event of default under SCE's credit facilities and bilateral credit
agreements, entitling those lenders to exercise their remedies including potential acceleration of the
outstanding borrowings of $1.65 billion.  If a notice of default is received, SCE could cure the default only by
paying $931 million in overdue principal to holders of commercial paper and the 5-7/8% and 6-1/2% senior
unsecured notes.  Making such payment would further impact SCE's liquidity and could result in a termination of
the forbearance agreements with bank lenders discussed below.  If a notice of default were received and not
cured, and the trustee or noteholders were to declare an acceleration of the outstanding principal amount of the
senior unsecured notes, SCE would not have the cash to pay the obligation and could be forced to declare
bankruptcy.  As a result of the default on the two series of senior unsecured notes, SCE's other senior unsecured
notes and subordinated debentures ($1.85 billion) have been classified as due within one year in the accompanying
financial statements.  If SCE is found responsible for purchases of power by the ISO for delivery to SCE's
customers on or after January 18, 2001, SCE's unpaid obligations as of October 31, 2001, could increase by as
much as $1.6 billion.  This amount could increase or decrease depending on CPUC or FERC decisions regarding
payments and refunds.  See additional discussion in CDWR Power Purchases.  These stated amounts representing past
or future obligations for purchased power, PX energy credits and certain other items include amounts that are in
dispute, and the publishing of these amounts is not an admission by SCE of liability for any disputed amounts.

Subject to certain conditions, the bank lenders under SCE's credit facilities totaling $1.65 billion agreed to
forbear until March 29, 2002, from exercising remedies, including acceleration of borrowed amounts, against SCE
with respect to the event of default arising from the failure to pay the 5-7/8% and 6-1/2% senior unsecured notes
and commercial paper when due.  Under the forbearance agreements, the maturity date of SCE's $200 million
short-term bank credit facility and $400 million in bilateral credit agreements has been extended until March 29,
2002.  The maturity date of the $1.05 billion, five-year bank credit facility is May 22, 2002.  At October 31,
2001, SCE had estimated cash reserves of approximately $2.7 billion (after deducting $530 million of designated
funds), which was approximately $650 million less than its outstanding unpaid obligations (discussed above) not
including its credit facilities that are subject to forbearance agreements, and overdue amounts of preferred
stock dividends (see below).  As of March 31, 2001, SCE resumed payment of interest on its debt obligations.
However, since June 30, 2001, SCE has deferred the interest payments on its quarterly income debt securities
(subordinated debentures), as allowed by the terms of the securities.  All interest in arrears must be paid


Page 26


in full at the end of the deferral period.  The settlement agreement with the CPUC, if implemented, is expected
to allow SCE to obtain financing which, combined with an increase in cash reserves, would give SCE sufficient
funds to pay all of its past due obligations by the end of first quarter 2002.

On March 27, 2001, the CPUC issued decisions ordering SCE and other investor-owned utilities to pay QFs for power
deliveries on a going forward basis, commencing with April 2001 deliveries, and on the California Procurement
Adjustment (CPA) calculation including the approval of a 3(cent)-per-kWh rate increase.  One of the CPUC decisions
also modified the formula used in calculating payments to QFs by substituting natural gas index prices based on
deliveries at the Oregon border rather than the index prices at the Arizona border.  The changes apply to all
QFs, where appropriate, regardless of whether they use natural gas or other resources such as solar or wind.

In light of SCE's liquidity crisis, its Board of Directors has not declared quarterly common stock dividends to
SCE's parent, Edison International, since September 2000 and Edison International's Board of Directors has not
declared a common stock dividend to Edison International's shareholders.  Also, SCE's Board has not declared the
regular quarterly dividends for any of SCE's cumulative preferred stock in 2001.  As of October 31, 2001, SCE's
preferred stock dividends in arrears were $17 million.  Dividends are additionally restricted as detailed in the
CPUC Litigation Settlement discussion.

SCE has implemented other cost-cutting measures, such as freezing new hires and postponing certain capital
expenditures.  SCE's current cost-cutting measures are intended to allow it to continue to operate while efforts
to restore its creditworthiness (such as that contemplated in the CPUC litigation settlement agreement) are
underway.  See further discussion in Status of Transition and Power-Procurement Cost Recovery.

For additional discussion on the impact of California's energy crisis on SCE's liquidity, see Cash Flows from
Financing Activities.  For a discussion on the settlement agreement with the CPUC to resolve SCE's crisis, see
CPUC Litigation Settlement Agreement.

The 2001 rate surcharges have allowed SCE's cash reserves (excluding designated funds) to grow by $1.0 billion
for the three-month period from July 31, 2001, to October 31, 2001.  Unless the federal court of appeals issues a
stay of judgment pending appeal or the settlement is successfully challenged on appeal, SCE's litigation
settlement agreement with the CPUC is expected to allow SCE to obtain financing which, combined with SCE's
expected additional increases in cash reserves, should allow SCE to pay all of its past due obligations by the
end of first quarter 2002.  Until these obligations are paid, resolution of SCE's liquidity crisis and its
ability to continue to operate outside of bankruptcy is uncertain.

EME

In September 2001, EME entered into a new $750 million corporate credit facility.  EME used this new credit
facility, together with other corporate funds, to replace and repay its existing corporate credit facilities
scheduled to mature in October 2001.  As of September 30, 2001, EME had borrowed or issued letters of credit
aggregating $709 million under the new facility and had an unused capacity of approximately $41 million.  The new
credit facility includes a one-year $538 million component that expires on September 16, 2002, and a three-year
$212 million component that expires on September 17, 2004.  EME's corporate cash requirements for the next 12
months include:  debt service under its senior notes and intercompany notes resulting from sale-leaseback
transactions which total $286 million; equity and capital requirements for projects in development and under
construction of $189 million; principal repayment of $100 million of senior notes due June 2002; dividends
payable to Mission Energy Holding Company of $130 million; a tax-sharing payment to the parent company of
$55 million; and general and administrative expenses.

In addition, to provide additional liquidity, EME may sell its interest in certain projects.  EME has entered
into agreements for the sale of some of its non-core partnership interests in the United States and Puerto Rico,
and is offering for sale certain other interests.  There is no assurance that EME will be able to sell its
interests in such projects on favorable terms or that the sale of an individual interest will not result in a
loss.  EME is also planning a sale-leaseback of its Homer City project.  EME believes that its existing cash


Page 27


resources and corporate financing plans will provide it sufficient liquidity to meet its cash requirements during
the next twelve months, although no assurance can be provided in this regard.

To isolate EME from the severe credit downgrades suffered by SCE, Edison Capital and the parent company, and to
help preserve the value of EME, EME has adopted certain amendments to its articles of incorporation and bylaws
(see additional discussion in Cash Flows from Financing Activities).

The financial performance of the Ferrybridge and Fiddler's Ferry plants has not met EME's expectations, largely
due to lower power prices resulting from increased competition, climatic effects and uncertainties surrounding
the new electricity trading arrangements discussed in the EME Issues section of Market Risk Exposures.  As a
result, EME's UK subsidiary has defaulted on its financing documents related to the acquisition of the plants.
As a result of the reduced financial performance, EME's UK subsidiary deferred some environmental capital
expenditure milestone requirements in the original capital expenditure program set forth in the financing
documents.  The original capital expenditure program has been revised, and this revision has been agreed to by
the financing parties.  In addition, in July 2001, the financing parties waived technical defaults under the
financing documents and a default under the financing documents resulting from the fact that, due to this reduced
financial performance, EME's UK subsidiary's debt service coverage ratio during 2000 declined below the threshold
set forth in the financing documents.  There is no assurance that EME's UK subsidiary's creditors will continue
to waive its non-compliance with the requirements under the financing documents or that EME's UK subsidiary will
satisfy its financial ratios in the future.

The financing documents state that a breach of the financial ratio covenant constitutes an immediate event of
default and, if the event of default is not waived, the financing parties are entitled to enforce their security
over the affiliate's assets, including the power plants.  Despite the breaches under the financing documents, the
subsidiary's debt service coverage ratio for 2000 exceeded 1:1.  Due to the timing of its cash flows and debt
service payments, EME's UK subsidiary utilized its debt service reserve to meet its debt service requirements in
2000.  In March 2001, EME's UK subsidiary met its semi-annual debt service requirements.  In September 2001,
EME's UK subsidiary utilized a portion of its debt service reserve to meet its semi-annual debt service
requirements.

As a result of the change in the prices of power in the UK, EME offered for sale through a competitive bidding
process the Ferrybridge and Fiddler's Ferry power plants (see additional discussion in Acquisitions and
Dispositions).  EME plans to use the proceeds from the sale, if it closes, to repay the acquisition financing of
the project.  The early repayment of the project's existing debt facility related to the acquisition of the power
plants is expected to result in a loss of approximately $30 million, attributable to the write-off of unamortized
debt issuance costs.  The new buyer of the plants needs to obtain certain regulatory clearances before completing
the plant purchase.  Although the relevant applications are currently being processed, there is no guarantee that
these will be granted.  In August 2000, EME commenced arbitration proceedings against the seller of the
Ferrybridge and Fiddler's Ferry power plants primarily related to the purchase price of the power plants. The
seller denies all of the claims. In July 2001, the arbitration hearing took place and a ruling is anticipated to
be made before the end of 2001. The proceeds, if any, from this matter will be recorded when the matter is
resolved and used to repay borrowings under a facility currently made available for the purposes of funding coal
and capital expenditures at the power plants. EME plans to repay this facility from cash flows generated from
foreign subsidiaries prior to its maturity in 2004.

Edison Capital

As of September 30, 2001, Edison Capital was fully drawn on its $150 million bank facility, which matures on
June 30, 2002.  Edison Capital historically received cash from Edison International for the federal and state tax
benefits and incentives flowing from Edison Capital's investments that are actually utilized on the Edison
International consolidated tax return.  However, these tax benefits and incentives are not currently being
utilized by Edison International and Edison Capital is not currently receiving cash for them.  Without such cash,
Edison Capital must meet its current obligations out of existing cash resources and/or by liquidating some of its
investments.  Any failure by Edison Capital to meet its obligations as they become due could be expected to have
a material adverse effect on Edison Capital's financial position and ability to conduct future operations.  Under
the current circumstances, Edison Capital is not pursuing any new investment opportunities.


Page 28


Edison International

In order to reduce its cash requirements, in May 2001, the parent company deferred the interest payments in
accordance with the terms of its outstanding quarterly income debt securities issued to an affiliate.  This
caused a corresponding deferral of distributions on quarterly income preferred securities issued by that
affiliate.  Interest payments may be deferred for up to 20 consecutive quarters.  During the deferral period, the
principal of the debt securities and each unpaid interest installment will continue to accrue interest at the
applicable coupon rate.  All interest in arrears must be paid in full at the end of the deferral period.  The
parent company cannot pay dividends on or purchase its common stock while interest is being deferred.  The parent
company expects to continue to pay all other obligations as they are due.

On July 2, 2001, Mission Energy Holding Company, a wholly owned indirect subsidiary of the parent company issued
$800 million of 13.50% senior secured notes due 2008 and entered into an agreement for a $385 million senior
secured term loan due 2006.  Both of these issuances are non-recourse to the parent company and EME.  The common
stock of EME was pledged to secure the new debt.  Both the senior secured notes and the term loan have security
interests in interest reserve accounts covering the interest payable on those obligations for the first two
years.  Proceeds of the notes and term loan were used by the parent company to repay the entire outstanding
principal amount of $618 million of its existing bank credit facility, plus interest of approximately $6 million,
as well as a portion of the $250 million of senior unsecured notes maturing July 18, 2001.  The credit facility
was originally due on May 14, 2001, but the bank lenders had agreed to extend the maturity date to June 30, 2001,
and to forbear exercising remedies under the credit facility due to cross-defaults by SCE.  The bank credit
facility has not been renewed.

As a result of SCE's $2.5 billion charge to earnings as of December 31, 2000, and Edison International's
$1.1 billion loss in the nine months of 2001 (discussed in Earnings section), Edison International's retained
earnings are now in a deficit position and therefore under California law, Edison International will be unable to
pay dividends as long as a deficit remains, unless Edison International meets certain conditions under which
dividends can be paid from sources other than retained earnings.  Edison International does not meet such
conditions.

Cash Flows from Operating Activities

Despite the $1.1 billion loss Edison International incurred for the nine months ended September 30, 2001, net
cash provided by operating activities was $2.3 billion, primarily due to SCE suspending payments for interest on
outstanding debt, purchased power beginning in January 2001 and other obligations.  Cash provided by operating
activities also reflects the CPUC-approved surcharges (1(cent)per kWh in January and 3(cent) per kWh in June) that SCE
billed in 2001.

Beginning first quarter 2001, the cash flow coverage of dividends quarterly calculation is no longer meaningful
due to Edison International not paying dividends to its common stock shareholders (discussed above in Liquidity
Issues).

Estimated noncancelable lease payments for the next five years are:  2001 - $185 million; 2002 - $214 million;
2003 - $212 million; 2004 - $234 million; and 2005 - $271 million.

Cash Flows from Financing Activities

At September 30, 2001, Edison International and its subsidiaries had $41 million of borrowing capacity available
under lines of credit totaling $2.6 billion.  The parent company, SCE and Edison Capital have drawn on their
entire lines of credit.  EME had total lines of credit of $750 million, with $41 million available to finance
general cash requirements.  These unsecured lines of credit have various expiration dates and, when available,
can be drawn down at negotiated or bank index rates.  SCE has successfully negotiated with bank lenders to extend
its 364-day credit facility and its $400 million bilateral credit agreements until March 29, 2002.  Although
SCE's remaining $1.05 billion, five-year bank credit facility expires on May 22, 2002, it is also subject to a
forbearance agreement which expires on March 29, 2002.


page 29


The parent company's short-term and long-term debt is used for general corporate purposes, including investments
in nonutility business activities.  EME uses its short-term and long-term debt to finance acquisitions and
development, as well as for general corporate purposes.  Edison Capital's short-term and long-term debt is used
for general corporate purposes, as well as investments.  SCE's short-term debt is used to finance balancing
account undercollections, fuel inventories and general cash requirements, including purchased-power payments.
Long-term debt is used mainly to finance capital expenditures.  External financings are influenced by market
conditions and other factors.  Because of the $2.5 billion charge to earnings, SCE does not currently meet the
interest coverage ratios that are required for SCE to issue additional first mortgage bonds or preferred stock.
In addition, because of its liquidity and credit problems, SCE has been unable to obtain financing of any kind.

As a result of investors' concerns regarding the California energy crisis and its impact on SCE's liquidity and
overall financial condition, SCE had to repurchase $550 million of pollution-control bonds that could not be
remarketed in accordance with their terms.  These bonds may be remarketed in the future if SCE's credit status
improves sufficiently.  In addition, the parent company, SCE and Edison Capital have been unable to sell their
commercial paper and other short-term financial instruments.

In January 2001, Fitch IBCA, Standard & Poor's and Moody's Investors Service lowered their credit ratings of
Edison International, Edison Capital and SCE to substantially below investment grade.

California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.  Additionally,
the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special
purpose entity.  These notes were issued to finance the 10% rate reduction mandated by state law.  The proceeds
of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as
transition property.  Transition property is a current property right created by the restructuring legislation
and a financing order of the CPUC and consists generally of the right to be paid a specified amount from
non-bypassable rates charged to residential and small commercial customers.  The rate reduction notes are being
repaid over 10 years through these non-bypassable residential and small commercial customer rates, which
constitute the transition property purchased by SCE Funding LLC.  The remaining series of outstanding rate
reduction notes have scheduled maturities beginning in 2002 and ending in 2007, with interest rates ranging from
6.22% to 6.42%.  The notes are secured by the transition property and are not secured by, or payable from, assets
of SCE or Edison International.  SCE used the proceeds from the sale of the transition property to retire debt
and equity securities.  Although, as required by accounting principles generally accepted in the United States,
SCE Funding LLC is consolidated with SCE and the rate reduction notes are shown as long-term debt in the
consolidated financial statements, SCE Funding LLC is legally separate from SCE.  The assets of SCE Funding LLC
are not available to creditors of SCE or Edison International and the transition property is legally not an asset
of SCE or Edison International.  Due to its credit rating downgrade in late 2000, in January 2001, SCE began
remitting its customer collections related to the rate-reduction notes on a daily basis.

To isolate EME from the credit downgrades of Edison International and SCE and to help preserve the value of EME,
EME's certificate of incorporation and bylaws include provisions requiring the appointment of an independent EME
director whose consent is required for EME to: consolidate or merge with any entity that does not have
substantially similar provisions in its organizational documents; institute or consent to bankruptcy, insolvency
or similar proceedings or actions; or declare or pay dividends unless certain conditions exist.  Such conditions
are:  EME has investment grade rating and receives rating agency confirmation that the dividend or distribution
will not result in a downgrade, or such dividends do not exceed $32.5 million in any quarter and EME meets a
certain interest coverage ratio for the immediately preceding four quarters.  Similarly, Mission Energy Holding's
certificate of incorporation includes provisions that require the unanimous approval of Mission Energy Holding's
Board of Directors, including at least one independent director, before Mission Energy Holding can take certain
actions.  Such actions include:  consolidate or merge with or into any other entity; transfer all or
substantially all of its assets and properties to any other entity; institute or consent to bankruptcy,
insolvency or similar proceedings or actions; declare or pay dividends or distributions other than dividends
permitted under the terms of the indenture for its senior secured notes; or liquidate or otherwise wind up.


Page 30


EME has entered into a support agreement that commits it to contribute up to $300 million in equity to its
trading operation unit.  EME has firm commitments related to the Italian wind projects to make equity
contributions of $2 million and $9 million for asset purchases, as well as $116 million related to the Sunrise
project and $59 million related to its CBK acquisition (see Acquisitions and Dispositions discussion).  EME also
has contingent obligations to make additional contributions of $47 million, primarily for equity support
guarantees related to the ISAB project in Italy and the Paiton project in Indonesia.  EME has capital commitments
of $986 million related to the turbine lease agreement and $300 million related to the Illinois plants.

EME may incur additional obligations to make equity and other contributions to projects in the future.  EME has
interests in eight partnerships that own power plants (or QFs) in California and have power purchase agreements
with Pacific Gas and Electric Company (PG&E) and/or SCE.  As previously discussed, due to its current liquidity
crisis, SCE did not make payments to QFs, among others, for power delivered between November 1, 2000, and March
26, 2001; however, in response to a March 27, 2001, CPUC order, SCE has been paying the QFs for power delivered
after March 27, 2001.  Also, following the execution of standstill agreements, SCE has paid the QFs 10% of the
past due amounts (for power delivered between November 2000 and March 2001) and has also begun making monthly
interest payments on the past due amounts.  At September 30, 2001, EME's share of accounts receivable due from
SCE was $200 million.

Some of the QFs owed by SCE, in which EME has interests, have sought to minimize their exposure by reducing
deliveries under power purchase agreements during the period in which SCE failed to make payments.  Although four
of these partnerships filed lawsuits against SCE, they have now entered into agreements with SCE (see further
discussion in the Litigation section of SCE's Regulatory Environment).  On April 6, 2001, PG&E filed for Chapter
11 bankruptcy protection.  As of that date, EME's share of accounts receivable due from PG&E was $23 million.  It
is unclear at this time what additional actions, if any, the partnerships will take in regard to the position
taken by SCE under the standstill agreements or to any future utilities' suspension of payments, or in the event
that the standstill agreements cease to be in effect.  As a result of the deferral of payments to these QFs, the
partnerships in which EME has interests have called on the partners to provide additional capital to fund
operating costs of the power plants.  Between January 1, 2001, and October 31, 2001, EME subsidiaries have made
equity contributions of approximately $134 million to meet capital calls by the partnerships.  EME's subsidiaries
and the other partners may be required to make additional capital contributions to the partnerships.

Edison Capital has firm commitments of $106 million to fund affordable housing, and energy and infrastructure
investments.  At September 30, 2001, as a result of Edison Capital's financial condition, it has deposited
approximately $19 million as collateral for its commitments.

Long-term debt maturities and sinking fund requirements for the five twelve month periods following September 30,
2001, are: 2002 - $2.3 billion; 2003 - $872 million; 2004 - $2.7 billion; 2005 - $2.4 billion; and 2006 -
$1.2 billion.  These projections assume no acceleration of payments arising from default.  See further discussion
in Liquidity Issues.

Preferred stock redemption requirements for the five twelve-month periods following September 30, 2001, are:
2002 - $105 million; 2003 - $9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.

Cash Flows from Investing Activities

Cash flows from investing activities are affected by additions to property and plant, sales of assets, and
funding of nuclear decommissioning trusts.  Decommissioning costs are recovered in utility rates.  These costs
are expected to be funded from independent decommissioning trusts that receive SCE contributions of approximately
$25 million per year.  In 1995, the CPUC determined the restrictions related to the investments of these trusts.
They are: not more than 50% of the fair market value of the qualified trusts may be invested in equity
securities; not more than 20% of the fair market value of the trusts may be invested in international equity
securities; up to 100% of the fair market values of the trusts may be invested in investment grade fixed-income
securities including, but not limited to, government, agency, municipal, corporate, mortgage-backed,
asset-backed, non-dollar, and cash equivalent securities; and derivatives of all descriptions are prohibited.
Contributions to the decommissioning trusts are reviewed


Page 31


every three years by the CPUC.  The contributions are determined from an analysis of estimated decommissioning
costs, the current value of trust assets and long-term forecasts of cost escalation and after-tax return on trust
investments.  Favorable or unfavorable investment performance in a period will not change the amount of
contributions for that period.  However, trust performance for the three years leading up to a CPUC review
proceeding will provide input into future contributions.  SCE's costs to decommission San Onofre Unit 1 are paid
from the nuclear decommissioning trust funds.  These withdrawals from the decommissioning trusts are netted with
the contributions to the trust funds in the Statements of Cash Flows.

Cash used for the nonutility subsidiaries' investing activities was $154 million for the nine-month period ended
September 30, 2001, compared to $513 million provided by investing activities for the same period in 2000.  The
decrease in 2001 was primarily the result of EME's sale-leaseback transactions in 2000.

Market Risk Exposures

Edison International's primary market risk exposures arise from fluctuations in energy prices, oil and gas
prices, interest rates and foreign currency exchange rates.  Edison International's risk management policy allows
the use of derivative financial instruments to manage its financial exposures, but prohibits the use of these
instruments for speculative or trading purposes, except at EME's trading operations unit.

SCE Issues

Changes in interest rates and in energy prices can have a significant impact on SCE's results of operations.
Additionally, natural gas is a key input for the prices that all QFs (including non-gas QFs) may charge to SCE.
SCE is exposed to changes in the spot market price for natural gas.

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as to finance capital expenditures.  The nature
and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors.  As the result of California's energy crisis, SCE has been
exposed to significantly higher interest rates, which has intensified its liquidity crisis (further discussed in
the Liquidity Issues section of Financial Condition).

SCE does not believe that its short-term debt is subject to interest rate risk.  However, SCE does believe that
the fair market value of its fixed-rate long-term debt is subject to interest rate risk.

Since April 1998, the price SCE paid to acquire power on behalf of customers was allowed to float, in accordance
with the 1996 electric utility restructuring law.  Until May 2000, retail rates were sufficient to cover the cost
of power and other SCE costs.  However, between May 2000 and June 2001 market power prices escalated, creating a
substantial gap between costs and retail rates.  In response to the dramatically higher prices, the ISO and the
FERC have placed certain caps on the price of power (see further discussion in Wholesale Electricity Markets).

During the period when market power prices were escalating, SCE attempted to hedge a portion of its exposure to
increases in power prices.  However, the CPUC approved a very limited amount of hedging during the period.  In
November 2000, SCE began purchases of energy through bilateral forward contracts.  At September 30, 2001, the
nominal value of SCE's bilateral forward contracts was $291 million.  Under the terms of the CPUC settlement
agreement, SCE purchased $209 million in hedging instruments in October and November 2001 to hedge a majority of
SCE's gas price exposure for 2002 and 2003.

In accordance with a new accounting standard for derivatives, on January 1, 2001, SCE recorded its block forward
contracts at fair value on the balance sheet.  Because SCE has suspended payments for purchased power since
January 16, 2001, the PX sought to liquidate SCE's remaining block forward contracts.  Before the PX could do so,
on February 2, 2001, the state seized the contracts, which at that time had an unrealized gain of approximately
$500 million.  On September 20, 2001, a federal appeals court ruled that the governor of California acted
illegally when he seized the power contracts held by SCE.


Page 32


In conjunction with its settlement agreement with the CPUC (discussed in CPUC Litigation Settlement Agreement),
SCE has agreed to release any claim for compensation against the state for these contracts. Due to its
speculative grade credit ratings, SCE has been unable to purchase additional bilateral forward contracts, and
some of the existing contracts were terminated by the counterparties.

In January 2001, the CDWR began purchasing power for delivery to utility customers.  On March 27, 2001, the CPUC
issued a decision directing SCE, among other things, to immediately pay amounts owed to the CDWR for certain past
purchases of power for SCE's customers.  See additional discussion of regulatory proceedings related to CDWR
activities in the Generation and Power Procurement section of SCE's Regulatory Environment.

EME Issues

Fluctuations in electricity prices, fuel prices, interest rates, and foreign currency exchange rates can have a
significant impact on EME's results of operations.

Changes in interest rates affect the cost of capital needed to finance the construction and operation of EME's
projects.  EME does not believe that its short-term debt is subject to interest rate risk, due to the fair market
value being approximately equal to the carrying value.  However, EME's long-term debt with fixed interest rates
is subject to interest rate risk.

EME has mitigated a portion of the risk of interest rate fluctuations by arranging for fixed rate or variable
rate financing with interest rate swaps or other hedging mechanisms for a number of its project financings.
Several of EME's interest rate swap agreements mature prior to their underlying debt.

EME hedges a portion of the electric output of its merchant plants in order to lock in desirable outcomes.  EME
also manages the margin between electricity prices and fuel prices when deemed appropriate.  EME uses forward
contracts, swaps, futures or option contracts to achieve these objectives.

Electric power generated at the Homer City plant is sold under bilateral arrangements with domestic utilities and
power marketers under short-term contracts (two years or less) or to the Pennsylvania-New Jersey-Maryland Power
Pool (PJM) or the New York Independent System Operator (NYISO).  These pools have short-term markets, which
establish an hourly clearing price.  The Homer City plant is located in the PJM control area and is physically
connected to high-voltage transmission lines serving both the PJM and NYISO markets.  The Homer City plant can
also transmit power to the mid-western United States.

Electric power generated at the Illinois plants is sold under three power purchase agreements with Exelon
Generation Company (ExGen).  The agreements, which began in December 1999, and have a term of up to five years,
provide for capacity and energy payments.  ExGen will be obligated to make a capacity payment for the units under
contract and an energy payment for the electricity produced by these units and taken by ExGen.  The capacity
payments provide the Illinois plants revenue for fixed charges, and the energy payments compensate the Illinois
plants for variable costs of production.  ExGen has the option to terminate two of the three agreements in their
entirety or with respect to any generating unit or units in each of 2002, 2003 and 2004.  ExGen provided EME
notice to continue the agreements related to the coal plants and the Collins Station for 2002.  Effective
January 1, 2002, ExGen terminated the power purchase agreement for the peaker units with respect to 309 MW of oil
peakers but continued the agreement for all other peaker plants for 2002.  If ExGen does not order all the power
from the units under contract, the Illinois plants may sell, subject to specified conditions, the excess energy
at market prices to neighboring utilities, municipalities, third-party electric retailers, large consumers and
power marketers on a spot basis.

EME's trading and price risk management activities give rise to market risk, which represents the potential loss
that can be caused by a change in the market value of a particular commitment.  Market risks are actively
monitored to ensure compliance with the risk management policies of EME, which limit its total net exposure.  EME
performs a value at risk analysis daily to monitor its overall market risk exposure.  Value at risk measures the
worst expected 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


Page 33


measurement tool, EME supplements this approach with other techniques, including the use of stress testing and
worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.

Since 1989, EME's projects in the UK sold their electric energy and capacity through a centralized electricity
pool, which establishes a half-hourly clearing price, or pool price, for electric energy.  On March 27, 2001,
this system was replaced with a bilateral physical trading system, referred to as the new electricity trading
arrangements.

The new electricity trading arrangements provide for, among other things, the establishment of a spot market or
voluntary short-term power exchanges operating from a year or more in advance to 3-/2 hours before a trading
period of 1/2 hour; a balancing mechanism to enable the system operator to balance generation and demand and
resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted
and metered volumes with strong incentives for being in balance; and a Balancing and Settlement Code Panel to
oversee governance of the balancing mechanism.  Contracting over time periods longer than the day-ahead market is
not directly affected by the proposals. Physical bilateral contracts have replaced the prior financial contracts
for differences, but function in a similar manner.  However, it remains difficult to evaluate the future impact
of the new electricity trading arrangements.  A key feature of the new arrangements is to require firm physical
delivery, which means that a generator must deliver, and a consumer must take delivery, against their contracted
positions or face assessment of energy imbalance penalty charges by the system operator.  A consequence of this
should be to increase greatly the motivation of parties to contract in advance and develop forwards and futures
markets of greater liquidity than at present.  Recent experience has been that the new electricity trading
arrangements have placed a significant downward pressure on forward contract prices.  In addition, another
consequence may be that counterparties may require additional credit support, including parent company guarantees
or letters of credit. Legislation in the form of the Utilities Act, which was approved July 28, 2000, provided
for the implementation of the new electricity trading arrangements and the necessary amendments to generators'
licenses.

The Utilities Act sets a principal objective for the Gas and Electric Market Authority to "protect the interests
of consumers...where appropriate by promoting competition..."  This objective represents a shift in emphasis toward
consumer interest, but is qualified by the recognition that license holders should be able to finance their
activities.  The Act also contains new powers for the Secretary of State to issue guidance to the Gas and
Electric Market Authority on social and environmental matters, changes to the procedures for modifying licenses,
and a new power for the Gas and Electric Market Authority to impose financial penalties on companies for breach
of license conditions.  EME will be monitoring the operation of these new provisions.

The Loy Yang B project in Australia sells its electric energy through a centralized electricity pool, which
provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market
for each half-hour of every day.  The National Electricity Market Management Company, operator and administrator
of the pool, determines a system marginal price each half-hour.  To mitigate the exposure to price volatility of
the electricity traded in the pool, Loy Yang B has entered into a number of financial hedges.  The State hedge
with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price
commencing May 1997 and terminating in October 2016.  The State government guarantees the State Electricity
Commission of Victoria's obligations under the State hedge.  From January 2001 to July 2014, approximately 77% of
the plant output sold is hedged under the State hedge.  From August 2014 to October 2016, approximately 56% of
the plant output sold is hedged under the State hedge.  Additionally, the Loy Yang B plant has entered into a
number of derivative contracts to further mitigate against price volatility inherent in the electricity pool.
These contracts consist of fixed forward electricity contracts commencing either in 2001 or 2002, which expire on
various dates through December 31, 2002, and a five-year cap contract commencing January 1, 2002, and expiring
December 31, 2006.

A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers
and forward contracts with other wholesale electricity counterparties.  Contact Energy has entered into forward
contracts and option contracts of varying terms that expire on various dates through September 30, 2003. The New
Zealand government commissioned an inquiry into the electricity industry in February 2000.  Following the inquiry
report the New Zealand government released a Government


Page 34


Policy Statement, at the center of which was a call for the industry to rationalize the three existing industry
codes, form a single governance structure and address transmission pricing methodology. The Government Policy
Statement also requested a model use of system agreement be agreed, that is a framework by which the retailers
contract for services from each of the distribution networks, and a consumer complaints ombudsman be
established.  An essential theme perpetuated throughout the Government Policy Statement was the desire that the
industry retain a private multilateral self-governing structure.  During 2001, an amendment to the Electricity
Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the
government's call.  Progress on the single governance code is well underway and the Chairs of the three existing
codes report to the Minister of Energy every two months on progress. The new code is likely to be introduced in
July 2002.

Foreign currencies in Australia, New Zealand, and the UK decreased in value compared to the US dollar by 11%, 8%
and 2%, respectively (determined by the change in the exchange rates from December 31, 2000, to September 30,
2001).  The decrease in value of these currencies was the primary reason for EME's foreign currency translation
loss of $58 million during the nine-month period ended September 30, 2001.

In December 2000, EME entered into foreign currency forward exchange contracts, in the ordinary course of
business, to protect itself from adverse currency rate fluctuations on anticipated foreign currency commitments.
The periods of the foreign currency forward exchange contracts correspond to the periods of the hedged
transactions.  At September 30, 2001, the outstanding notional amount of the contracts was $57 million,
consisting of contracts to exchange US dollars to pounds Sterling with varying maturities ranging from October
2001 to July 2002.  During the third quarter of 2001, EME recognized a foreign exchange gain (less than $100,000)
related to the fuel purchases underlying the contracts that matured in July, August and September 2001.  EME will
continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging
strategies in the future.

In addition, EME entered into foreign currency forward exchange contracts in the ordinary course of business to
offset certain operational and balance sheet exposures from changes in the value of the New Zealand dollar. The
contracts are primarily in Australian and US dollars with varying maturities through September 2002.  At
September 30, 2001, the net sold position of the foreign exchange contracts totaled $1.1 million. During the
four-month period ended September 30, 2001, EME recognized a foreign exchange gain of $547,000 related to the
contracts that matured during the same period.

Fluctuations in foreign currency exchange rates can affect the amount of EME's equity contributions to, and
distributions from its international projects.  As EME continues to expand into foreign markets, fluctuations in
foreign currency exchange rates can be expected to have a greater impact on EME's results of operations in the
future.  At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates
through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying
project agreements to US dollars or other indices reasonably expected to correlate with foreign exchange
movements.  Statistical forecasting techniques are used to help assess foreign exchange risk and the
probabilities of various outcomes.  There can be no assurance, however, that fluctuations in exchange rates will
be fully offset by hedges or that currency movements and the relationship between macroeconomic variables will
behave in a manner that is consistent with historical or forecasted relationships.

Edison Capital Issues

Changes in interest rates can have an impact on Edison Capital's results of operations.

Edison Capital is exposed to changes in interest rates primarily as a result of its borrowing and investing
activities used for general corporate purposes, as well as investments.  The nature and amount of Edison
Capital'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 Capital does not believe that its short-term debt is subject to interest rate risk, due to the fair market
value being approximately equal to the carrying value.  However, Edison Capital does believe that the fair market
value of its fixed rate long-term debt is subject to interest rate risk.


Page 35


Edison Capital has entered into interest rate swap agreements to reduce actual or expected exposure to interest
rate fluctuations.

Edison International Issues

The parent company is exposed to changes in interest rates primarily as a result of its borrowing and investing
activities used for general corporate purposes, including investments in nonutility business activities.  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.

The parent company believes that, due to the liquidity issues it faces, its short-term debt and the fair market
value of its fixed rate long-term debt are subject to interest rate risk.

Paiton Project

A wholly owned subsidiary of EME (Paiton Energy) owns a 40% interest and has a $495 million investment (at
September 30, 2001) in the Paiton project, a 1,230-MW coal-fired power plant in Indonesia.  As discussed more
fully in Edison International's 2000 Annual Report on Form 10-K, Paiton Energy is in continuing negotiations on a
long-term restructuring of the revenue schedule under a long-term power purchase agreement with the state-owned
electricity company.  Paiton Energy and the state-owned electricity company have agreed on a Phase I Agreement
for the period from January 1, 2001, through June 30, 2001.  This agreement provided for fixed monthly payments
totaling $108 million over its six-month duration and for the payment for energy delivered to the state-owned
electricity company from the plant during this period.  The state-owned electricity company made all fixed
payments due under the Phase I Agreement totaling $108 million as scheduled.  Paiton Energy received lender
approval of the Phase I Agreement and has also entered into a lender interim agreement under which lenders have
agreed to interest-only payments and to deferral of principal payments while Paiton Energy and the state-owned
electricity company seek a long-term restructuring.  The lenders have agreed to extend that agreement through
December 31, 2001.

Paiton Energy and the state-owned electricity company intended to complete the negotiations of the future phases
of a new long-term revenue schedule during the six-month duration of the Phase I Agreement.  Although Paiton
Energy and the state-owned electricity company did not complete negotiations on a long-term restructuring of the
revenue schedule by June 30, 2001, Paiton Energy and the state-owned electricity company signed an agreement
providing for an extension of the Phase I Agreement from July 1, 2001, to September 30, 2001.  The lenders
approved this extension of the Phase I Agreement.  All fixed payments totaling $59 million due under that
extension of the Phase I Agreement have been made by the state-owned electricity company.  Paiton Energy and the
state-owned electricity company have been actively negotiating a long-term restructuring of the revenue schedule
and have made substantial progress.  However, that long-term restructuring was not completed prior to the
expiration of the extension of the Phase I Agreement.  Paiton Energy and the state-owned electricity company have
therefore signed an agreement providing for an additional extension of this Phase I Agreement to December 31,
2001.  Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes
that the state-owned electricity company will continue to agree to make payments for electricity on an interim
basis beyond September 30, 2001, while negotiations regarding the long-term restructuring of the revenue schedule
continue.  Although completion of negotiations may be delayed, Paiton Energy continues to believe that
negotiations on the long-term restructuring of the revenue schedule will be successful.

Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new
long-term revenue schedule could require a renegotiation of the Paiton project's debt agreements.  The impact of
any such renegotiations with the state-owned electricity company, the Indonesian government or the project's
creditors on EME's expected return on its investment in the Paiton project is uncertain at this time; however,
EME believes that it will ultimately recover its investment in the project.


Page 36


Acquisitions and Dispositions

EME

In October 2001, EME announced the sale of the Ferrybridge and Fiddler's Ferry power plants in the UK for an
aggregate purchase price of 650 million pounds Sterling.  As a result, EME recorded a charge of $1.9 billion
($1.15 billion after tax) to write down the carrying amount of the power plants to the estimated fair value less
the cost to sell and related currency adjustments.  This charge was recorded in the third quarter of 2001.  The
sale is expected to close before the end of 2001.

In September 2001, EME completed the sale of its 50% interest in the Saguaro project.  Proceeds from the sale
were approximately $67 million.  EME recorded a gain on sale of $43 million ($24 million after tax).

In June 2001, EME completed the sale of its 25% interest in the Hopewell project. Proceeds from the sale were
approximately $27 million.  EME recorded a gain on the sale of $5 million ($2 million after tax).

Also in June 2001, EME completed the sale of a 50% interest in the Sunrise project.  Proceeds from the sale were
$84 million.  Commercial operation commenced in late June 2001.

During the second quarter of 2001, EME completed the purchase of additional shares of Contact Energy Ltd. for
approximately NZ$152 million.  EME now has a controlling 51% ownership interest in Contact Energy.  In October
2001, EME announced its intention to acquire the remaining 49% of Contact Energy, thereby increasing its
ownership interest to 100%.

During first quarter 2001, EME completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for
$20 million.  CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with
National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in
the Philippines.  Financing for this $460 million project comprises equity commitments of $117 million (EME's
share is $59 million) required to be made upon completion of the rehabilitation and expansion, currently
scheduled in 2003 and debt financing which is in place for the remainder of the cost for this project.

Edison Enterprises

During second quarter 2001, Edison Enterprises, a wholly owned subsidiary of Edison International, decided to
sell most of its assets.  On August 1, 2001, it sold a subsidiary (principally engaged in the business of
providing residential security services and residential electrical warranty repair services) to ADT Security
Services, Inc.

In June 2001, another Edison Enterprises subsidiary (engaged in the business of commercial energy management)
entered into a letter of intent to sell substantially all of its assets to its current management.  The sale was
completed October 18, 2001.

In second quarter 2001, Edison International recorded a charge of $117 million (after tax) to reduce the carrying
value of its investments in the businesses held for sale based on estimated proceeds from the sales.  In third
quarter 2001, Edison International recorded an additional charge of $10 million (after tax) upon completion of
the Edison Enterprises' subsidiary sale.

SCE's Regulatory Environment

SCE operates in a highly regulated environment and has an exclusive franchise within its service territory.  SCE
has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to
provide just and reasonable rates.  In the mid-1990s, state lawmakers and the CPUC initiated the electric
industry restructuring process.  SCE was directed by the CPUC to divest the bulk of its generation portfolio.
Today, independent power companies own the divested generating plants.  The electric industry restructuring plan
also instituted a multi-year freeze on the rates that SCE could charge its customers and transition cost recovery
mechanisms (as described in Status of Transition and


Page 37


Power-Procurement Cost Recovery) designed to allow SCE to recover its stranded costs associated with
generation-related assets.  California's electric industry restructuring statute included provisions to finance a
portion of the stranded costs that residential and small commercial customers would have paid between 1998 and
2001, which allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998.  These
frozen rates (except for the surcharge effective in 2001) were to remain in effect until the earlier of March 31,
2002, or the date when the CPUC-authorized costs for utility-owned generation assets and obligations are
recovered.  However, between May 2000 and June 2001, the prices charged by sellers of power escalated far beyond
what SCE could charge its customers.  As a result, SCE has incurred $2.7 billion (after tax), or $4.6 billion on
a pre-tax basis, in write-offs and net undercollected transition costs during the past 12 months (see Earnings).
As indicated below, implementation of the PROACT mechanism and CPUC approval of SCE's Utility-Retained Generation
(URG) application is expected to allow SCE to recover substantially all of the $4.6 billion.

Generation and Power Procurement

During the rate freeze, recovery of generation-related transition costs has been tracked through the TCBA
mechanism.  Revenue from generation-related operations was determined through the market and transition cost
recovery mechanisms, which included the nuclear rate-making agreements.  During fourth quarter 2001, it is
expected that the TCBA will become inactive retroactive to September 1, 2001, and a $3.6 billion PROACT
regulatory asset will be created in accordance with the October 2001 settlement agreement with the CPUC.  In
accordance with a state law passed in January 2001, SCE will continue to own its remaining generation assets,
which would be subject to cost-based ratemaking, through 2006 (see further discussion in URG Proceeding).

Through December 31, 2000, SCE had been recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return on investment.  SCE's nuclear assets were earning an
annual rate of return on investment of 7.35%.  However, due to the various unresolved regulatory and legislative
issues (as discussed in Status of Transition and Power-Procurement Cost Recovery), as of December 31, 2000, SCE
was no longer able to conclude that the $610 million balance of unamortized nuclear investment regulatory assets
was probable of recovery through the rate-making process.  As a result, this balance was written off as a charge
to earnings at that time (see further discussion in Earnings).  SCE requested in its URG application to recover
the unamortized cost of its nuclear investment regulatory asset over a ten-year period, retroactive to January 1,
2001.  Should this application be approved, SCE expects to reestablish for financial reporting purposes its
unamortized nuclear investment and related flow-through taxes as regulatory assets, with a corresponding credit
to earnings.

The San Onofre incentive pricing plan authorizes a fixed rate of approximately 4(cent)per kWh generated for operating
costs including incremental capital costs, nuclear fuel and nuclear fuel financing costs.  The San Onofre plan
started in April 1996 and ends in December 2003 for the incentive-pricing portion.  The Palo Verde Nuclear
Generating Station's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel
financing costs, were subject to balancing account treatment.  The Palo Verde plan started in January 1997 and
was to end in December 2001.  The benefits of operation of the San Onofre units and the Palo Verde units were
required to be shared equally with ratepayers beginning in 2004 and 2002, respectively. In a June 2001 decision,
the CPUC granted SCE's request to eliminate the San Onofre post-2003 benefit sharing mechanism based on
compliance with a recently enacted state law.  In a September 2001 decision, the CPUC granted SCE's request to
eliminate the Palo Verde post-2001 benefit sharing mechanism and continue the current rate treatment for Palo
Verde, including the continuation of the existing nuclear incentive procedure with a 5(cent)per kWh cap on
replacement power costs, until resolution of SCE's General Rate Case or further CPUC action.  Beginning January
1, 1998, both the San Onofre and Palo Verde rate-making plans became part of the TCBA mechanism.  These
rate-making plans and the TCBA mechanism were to continue for rate-making purposes at least through the end of
the rate freeze period.  However, in its URG application, SCE proposed to move the recovery of nuclear costs to
another balancing account mechanism (see discussion in URG Proceeding section).


Page 38


CPUC Litigation Settlement Agreement

In November 2000, SCE filed a lawsuit against the CPUC in federal court in California, seeking a ruling that SCE
is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with
the FERC.  By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought
implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's
related financial and liquidity problems.  On October 5, 2001, a federal district court in California entered a
stipulated judgment approving an October 2, 2001, agreement between the CPUC and SCE to settle the pending
lawsuit.

Key elements of the settlement agreement include the following items:

o    The CPUC will establish an account called the PROACT, as of September 1, 2001, which will have an
     opening balance equal to the amount of SCE's procurement-related liabilities as of August 31, 2001
     (approximately $6.4 billion), less SCE's cash and cash equivalents as of that date (approximately
     $2.5 billion), and less $300 million.

o    During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has
     recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will
     apply to the PROACT, on a monthly or other basis established by the CPUC, the difference between SCE's
     revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC
     to recover in retail electric rates.  Unrecovered obligations in the PROACT will accrue interest from
     September 1, 2001.

o    The parties agree that SCE will recover in retail electric rates its procurement-related obligations in
     the PROACT, with interest, by December 31, 2005.  Subject to certain adjustments, the CPUC will maintain
     current rates (including surcharges) in effect until December 31, 2003, or, if earlier, until the date that
     SCE recovers the entire PROACT balance.  If SCE has not recovered the entire balance by December 31, 2003,
     the unrecovered balance will be amortized for up to an additional two years.  The parties currently project
     that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will
     likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior
     to the end of 2003.

o    If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
     procurement-related obligations, the parties will work together to achieve the securitization.  Proceeds of
     any securitization will be credited to the PROACT when they are actually received.

o    During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed
     by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.

o    SCE intends to apply for CPUC approval to incur up to $250 million of recoverable costs to acquire
     financial instruments and engage in other transactions intended to hedge fuel cost risks associated with
     SCE's retained generation assets and power purchase contracts with qualifying facilities and other
     utilities.  The CPUC indicated that it will schedule proceedings reasonably promptly and consider SCE's
     application on an expedited basis.

o    SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
     by Edison International) prior to the earlier of the date SCE has recovered all of its procurement-related
     obligations in the PROACT or January 1, 2005.  However, if SCE has not recovered all of its
     procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common
     stock dividends, and the CPUC will not unreasonably withhold its consent.

o    To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's
     next general rate case, SCE may make capital expenditures above the level contained in current rates, up to
     $900 million per year, which will be treated as recoverable costs.


Page 39


o    Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General to pursue
     and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to claims
     arising from any failure to make payments to the PX or ISO, and similar claims by the State of California or
     its agencies against the same adverse parties.  During the recovery period discussed above, refunds obtained
     by SCE related to its procurement-related liabilities will be applied to the balance in the PROACT.

The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past.  SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.

The settlement agreement states that the CPUC shall adopt such decisions or orders it deems necessary to
implement and carry out the provisions of the agreement, with the understanding that the agreement and stipulated
judgment shall be binding and irrevocable upon the parties.  SCE expects that these implementing decisions or
orders will be issued during fourth quarter 2001.

The minimum beginning balance of the PROACT, as verified by the CPUC, is calculated as follows:

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

         PX or ISO                                                                     $    924
         QFs  1,219
         PX energy credits                                                                  236
         Imbalance energy (CDWR)                                                            383
         Ancillary services for resale cities                                                30
---------------------------------------------------------------------------------------------------

              Total past due bills                                                        2,792
         Credit facilities                                                                1,298
         Bilateral credit facilities                                                        415
         Defaulted commercial paper                                                         563
         Floating rate notes due May 2002                                                   313
         Variable rate notes due November 2003                                            1,043
---------------------------------------------------------------------------------------------------

              Total procurement-related liabilities                                       6,424
         Less:  Cash and cash equivalents on hand                                        (2,547)
         Less:  Amount stipulated in agreement                                             (300)
---------------------------------------------------------------------------------------------------

         Net PROACT balance as of August 31, 2001                                      $  3,577
---------------------------------------------------------------------------------------------------


On October 26, 2001, a California consumer group asked a federal court of appeals for a stay of judgment pending
appeal of the federal district court's judgment approving the settlement.  The group alleged that it was denied
due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze.  On
October 30, 2001, the court of appeals granted a temporary stay, and instructed the consumer group to return to
district court to argue the merits of the stay.  On November 9, 2001, the district court denied the consumer
group's request for a stay.  The consumer group indicated that it intends to ask the court of appeals for a stay
of judgment pending appeal.  If the stay of judgment pending appeal is granted, or the settlement is successfully
challenged on appeal, the ability of SCE and the CPUC to implement the settlement agreement would be affected
adversely, which in turn would have an adverse effect on SCE's ability to restore its financial condition, repay
its creditors and avoid an involuntary bankruptcy petition.

CDWR Power Purchases

In accordance with an emergency order signed by the Governor, the CDWR began making emergency power purchases for
SCE's customers on January 18, 2001.  Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not considered
revenue to SCE.  In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts


Page 40


to purchase electric power and sell power at cost directly to retail customers being served by SCE, and
authorized the CDWR to issue bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5, 2001),
for each kWh the CDWR sells to SCE's customers.  The CPUC determined that the generation-related retail rate
should be equal to the total bundled electric rate (including the 1(cent)-per-kWh temporary surcharge adopted by the
CPUC on January 4, 2001) less certain nongeneration-related rates or charges.  For the period January 19 through
January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277(cent)per kWh for power delivered to SCE's
customers.  The CPUC determined that the applicable rate component is 7.277(cent)per kWh (which increased to 10.277(cent)
per kWh for electricity delivered after March 27, 2001, due to the 3(cent)-surcharge discussed in Rate Stabilization
Proceedings), for electricity delivered by the CDWR to SCE's retail customers after February 1, 2001, until more
specific rates are calculated.  The CPUC ordered SCE to pay the CDWR within 45 days after the CDWR supplies power
to retail customers, subject to penalties for each day the payment is late.

On September 4, 2001, the CPUC issued a proposed decision authorizing a CDWR revenue requirement of $12.1 billion
to pay its bonds' costs and energy procurement costs for 2001 and 2002.  The proposed decision states that SCE's
allocated share of this revenue requirement (based on a cost-of-service approach) would be approximately $4
billion, and changes SCE's payment from 10.277(cent)per kWh to 10.03(cent)per kWh.  A balancing account would be
established to record the difference between the two rates, with the difference to be trued up in a subsequent
CPUC order.  In comments filed with the CPUC on September 12, 2001, SCE requested that the CPUC refrain from
adopting a final revenue requirement until hearings are held to determine how the revenue requirement was
calculated and its relationship to SCE's revenue requirement to be determined in the URG proceeding.  In a
November 5, 2001, filing with the CPUC, the CDWR reduced its revenue requirement to $10.0 billion, due to
conservation efforts, lower natural gas prices, and other changes in market conditions.  The CPUC has not
determined SCE's share of the $10.0 billion.  A final decision on the URG and CDWR matters is not expected until
early 2002.

SCE believes that the intent of AB 1X was for the CDWR to assume full responsibility for purchasing all power
needed to serve the retail customers of electric utilities, in excess of the output of generating plants owned by
the electric utilities and power delivered to the utilities under existing contracts.  However, the CDWR stated
that it would only purchase power that it considers to be reasonably priced, leaving the ISO to purchase in the
short-term market the additional power necessary to meet system requirements.  The ISO, in turn, took the
position that it will charge SCE for the costs of power it purchases in this manner.  If SCE is found responsible
for purchases of power by the ISO for delivery to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs for the nine months ended September 30, 2001, could increase by as much as $1.6 billion
(which includes bills received for January through July 2001, and an estimate for August and September 2001).
This amount could increase or decrease depending on CPUC or FERC decisions regarding payments and refunds.  In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that the CDWR will pay for the ISO
purchases and that it does not have the authority to order the CDWR to do so.  Litigation among certain power
generators, the ISO and the CDWR (to which SCE is not a party), and proceedings before the FERC (to which SCE is
a party), may result in rulings clarifying the CDWR's financial responsibility for purchases of power.  In April
2001, the FERC issued an order confirming its February 2001 order that the ISO must have a creditworthy buyer for
any transactions.  SCE has not met the ISO's creditworthiness requirements since its credit ratings were
downgraded in mid-January 2001.  As a result, SCE has protested and returned the bills it received from the ISO.
On November 7, 2001, the FERC issued an order directing the ISO to invoice CDWR (within 15 days of the date of
the order) for all transactions it entered into on behalf of SCE's customers.  The ISO was also directed to file
a report with the FERC within 15 days from the date of the order indicating overdue amounts from CDWR and a
schedule for payments of those amounts within three months of the date of the order.  In any event, SCE takes the
position that it is not responsible for purchases of power by the CDWR or the ISO on or after January 18, 2001.
SCE cannot predict the outcome of any of these proceedings or issues.



page 41


Status of Transition and Power-Procurement Cost Recovery

SCE's transition costs include power purchases from QF contracts (which are the direct result of prior
legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide
service to customers.  Other costs include the recovery of income tax benefits previously flowed through to
customers, postretirement benefit transition costs and accelerated recovery of investment in nuclear generating
units.  Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract.  Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most
of the remaining transition costs to be recovered through the end of the four-year transition period (not later
than March 31, 2002).  Because regulatory and legislative actions that make such recovery probable were not taken
in a timely manner during the energy crisis, as of December 31, 2001, SCE was unable to conclude that the net
regulatory assets related to purchased-power settlements, the unamortized loss on SCE's generating plant sales in
1998, and various other generation regulatory assets were probable of recovery through the rate-making process.
As a result, these balances were written off as a charge to earnings at that time (see further discussion in
Earnings).

There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001.  Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism.  However, state legislation enacted in January 2001 prohibits the sale of SCE's remaining generation
assets until 2006.  SCE stopped selling power from its generation into the ISO and PX markets in January 2001,
after SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges (see discussion in
Generation and Power Procurement).

As discussed in the Status of Transition and Power-Procurement Cost Recovery in Note 2 to the Consolidated
Financial Statements, CTC revenue has been determined residually, the CTC applied to all customers who were using
or began using utility services on or after the CPUC's 1995 restructuring decision date, and residual CTC revenue
was calculated through the TRA mechanism.  In accordance with the March 27, 2001, rate stabilization decision,
both positive and negative residual CTC revenue was transferred from the TRA to the TCBA on a monthly basis,
retroactive to January 1, 1998 (see further discussion in Rate Stabilization Proceedings).  A previous decision
had called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had
not been any positive residual CTC revenue between May 2000 and June 2001.  The cumulative transition cost
undercollection (as recalculated) was $4.0 billion as of September 30, 2001, and $2.9 billion as of December 31,
2000.

Because the regulatory and legislative actions that made such recovery probable were not taken, SCE was unable to
conclude as of December 31, 2000, that the recalculated TCBA net undercollection was probable of recovery through
the rate-making process.  As a result, the $2.9 billion TCBA net undercollection was written off as a charge to
earnings as of that date (see further discussion in Earnings), and an additional $1.1 billion in TCBA
undercollections were charged to earnings during 2001.  For more details on the matters discussed above, see Rate
Stabilization Proceedings.

Litigation

In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.  As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections.  The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001.  A consolidated class
action complaint was filed on August 3, 2001.  On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim.  The motion is scheduled for hearing on December 3, 2001.  SCE believes
that its current and past accounting for the TRA undercollections and related items is appropriate and in
accordance with accounting principles generally accepted in the United States.


Page 42


In addition to the lawsuits filed against SCE and discussed above, SCE is involved in a number of state and
federal lawsuits filed by QFs.  The lawsuits have been filed by various parties, including geothermal, wind and
cogeneration suppliers.  The lawsuits are seeking payments of at least $833 million for energy and capacity
supplied to SCE under QF contracts, and in some cases for additional damages as well.  Many of these QF lawsuits
also seek an order allowing the suppliers to stop providing power to SCE so that they may sell the power to other
purchasers.  The state court cases have been coordinated before a single trial judge.  SCE has reached agreements
with QFs representing about 97% of the QF renewable and cogeneration capacity provided to SCE.  The agreements
provide for stays of litigation, payments to the QFs upon occurrence of specified conditions, modifications in
some cases to the contract prices going forward, releases and dismissals of the litigation upon payment by SCE.
In light of the settlement agreement with the CPUC, SCE is seeking to negotiate amendments to the agreements with
QFs.

Edison International and SCE cannot predict the outcome of any of these matters.

Rate Stabilization Proceedings

In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery.  In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.

In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates.  The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition.  The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates. In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into: whether the holding companies violated CPUC requirements to give priority to the capital
needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the requirements to give priority to the
capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary.  SCE believes the holding company
decision refers to equity investment, not working capital for operating costs.  The CPUC ordered testimony and
briefing on these matters, which SCE filed in May and June 2001.  Neither Edison International nor SCE can
predict what effects this investigation or any subsequent actions by the CPUC may have on either of them.

In March 2001, the CPUC ordered an immediate rate increase in the form of a 3(cent)-per-kWh surcharge applied only to
going-forward electric power procurement costs and affirmed that a 1(cent)interim surcharge granted in January 2001
is permanent.  The 3(cent)surcharge is to be added to the rate paid to the CDWR (see CDWR Power Purchases).  Although
the 3(cent)-increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the CPUC
established a rate design in early June 2001.

Also, in the March 2001 order, the CPUC granted a petition previously filed by The Utility Reform Network and
directed that the balance in SCE's TRA, whether over or undercollected, be transferred on a monthly basis to the
TCBA, retroactive to January 1, 1998.  Previous rules called only for TRA overcollections (residual CTC revenue)
to be transferred to the TCBA.  The CPUC also ordered SCE to transfer the coal and hydroelectric balancing
account overcollections to the TRA on a monthly basis before any transfer of residual CTC revenue to the TCBA,
retroactive to January 1, 1998.  Previous rules called for overcollections in these two balancing accounts to be
transferred directly to the TCBA on an annual basis (see further discussion of the recalculation of the TCBA in
Status of Transition and Power-Procurement Cost Recovery).  Based upon the transfer of balances into the TCBA,
the CPUC denied SCE's December 2000 filing requesting an end to the current rate freeze, and stated that the
four-year rate freeze will not end until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze.  The CPUC also said that it would
monitor the balances


Page 43


remaining in the TCBA and consider how to address remaining balances in the ongoing proceedings.  In accordance
with the October 2001 settlement with the CPUC, it is expected that the TCBA mechanism will be discontinued and
the PROACT mechanism will be established retroactive to August 31, 2001 (see further discussion in CPUC
Litigation Settlement Agreement).

URG Proceeding

In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
cost-of-service ratemaking for utility retained generation through the end of 2002.  The URG proposal calls for
balancing accounts for SCE-owned generation, QF and interutility contracts, procurement costs and ISO charges
based on either actual or CPUC-authorized revenue requirements.  Under the proposal, the four new balancing
accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for
non-capital-related costs.  In addition, SCE's unamortized nuclear investment would be amortized and recovered in
rates over a 10-year period, effective January 1, 2001.  Should this application be approved as filed, SCE
expects to reestablish for financial reporting purposes regulatory assets related to purchased-power settlements,
unamortized nuclear investment and related flow-through taxes, with a corresponding credit to earnings.  Hearings
were held in July 2001.  A final decision is not expected until early 2002.

Accounting for Generation-Related Assets and Power Procurement Costs

In 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its generation
assets.  At that time, SCE did not write off any of its generation-related assets, including related regulatory
assets, because the electric utility industry restructuring plan made probable their recovery through a
nonbypassable charge to distribution customers.

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

As of December 31, 2000, SCE assessed the probability of recovery of its generation-related assets and power
procurement costs in light of the CPUC's March 27, 2001, and April 3, 2001, decisions, and could not conclude
that its $2.9 billion TCBA undercollection (as redefined in the March 27 decisions) and $1.3 billion (book value)
of its net generation-related regulatory assets to be amortized into the TCBA, were probable of recovery through
the rate-making process.  As a result, accounting principles generally accepted in the United States required
that the balances in the accounts be written off as a charge to earnings.  In addition to the $4.2 billion
pre-tax write-off, SCE incurred approximately $400 million in net undercollected transition costs during 2001.

In accordance with the CPUC settlement agreement, in fourth quarter 2001, it is expected that the CPUC will issue
implementing decisions or orders allowing SCE to establish a $3.6 billion regulatory asset for previously
incurred energy procurement-related costs, to be called the PROACT, retroactive to August 31, 2001.  See further
discussion in CPUC Litigation Settlement Agreement.  CPUC approval of the URG application, as filed (see URG
Proceeding), together with implementation of the PROACT mechanism is expected to allow SCE to recover
substantially all of the $4.6 billion in write-offs and undercollected transition costs incurred during the past
12 months.

Distribution

Revenue related to distribution operations is determined through a performance-based rate-making (PBR) mechanism
and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return on investment.  The
distribution PBR will extend through December 2001.  Key elements of the distribution PBR include:  distribution
rates indexed for inflation based on the Consumer Price Index less a productivity factor; adjustments for cost
changes that are not within SCE's control; a cost-of-capital trigger mechanism based on changes in a utility bond
index; standards for customer satisfaction; service


Page 44


reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will
share gains and losses from distribution operations.

Transmission

Transmission revenue is determined through FERC-authorized rates and is subject to refund.

Wholesale Electricity Markets

In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds.  In December 2000, the FERC took limited action and failed
to impose a price cap.  SCE filed an emergency petition in the federal court of appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates.  The court denied SCE's
petition in January 2001.

In its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling
coordinators that do not schedule sufficient resources to supply 95% of their respective loads.  In May 2001, the
FERC indicated that it will make a determination regarding the suspension of the underscheduling penalty in a
future order in response to a complaint filed by SCE that asked the FERC to eliminate the penalty.  As of
October 31, 2001, SCE's share of the statewide accumulated penalties were estimated to be as much as
$360 million.  The ISO has not billed SCE for any amounts associated with the underscheduling penalty.  SCE cannot
predict the outcome of this matter.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).  The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period.  Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region.  The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices.  An administrative law judge will conduct evidentiary hearings on this matter.  SCE
cannot predict the amount of any potential refunds.  Under the settlement of litigation with the CPUC, refunds
will be applied to the balance in the PROACT.

Environmental Protection

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.

As further discussed in Note 4 to the Consolidated Financial Statements, Edison International records its
environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated.  Edison International's recorded estimated minimum liability to remediate
its 42 identified sites is $114 million.  Edison International believes that, due to uncertainties inherent in
the estimation process, it is reasonably possible that cleanup costs could exceed its recorded liability by up to
$269 million.  In 1998, SCE sold all of its gas-fueled power plants but has retained some liability associated
with the divested properties.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $45 million of its
recorded liability, through an incentive mechanism, which is discussed in Note 4.  SCE has recorded a regulatory
asset of $60 million for its estimated minimum environmental-cleanup costs expected to be recovered through
customer rates.


Page 45


Edison International's identified sites include several sites for which there is a lack of currently available
information.  As a result, 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 $10 million to $25 million.  Recorded costs for the
twelve months ended September 30, 2001, were $20 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 and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, 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.

The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide.  Power companies
receive emissions allowances from the federal government and may bank or sell excess allowances.  SCE expects to
have excess allowances under Phase II of the Clean Air Act (2000 and later).  A study was undertaken to determine
the specific impact of air contaminant emissions from the Mohave Generating Station on visibility in Grand Canyon
National Park.  The final report on this study, which was issued in March 1999, found negligible correlation
between measured Mohave station tracer concentrations and visibility impairment.  The absence of any obvious
relationship cannot rule out Mohave station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze.  In June 1999, the Environmental Protection
Agency (EPA) issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at
the Grand Canyon.  SCE filed comments on the proposed rulemaking in November 1999.  In 1998, several
environmental groups filed suit against the co-owners of the Mohave station regarding alleged violations of
emissions limits.  In order to accelerate resolution of key environmental issues regarding the plant, the parties
filed, in concurrence with SCE and the other station owners, a consent decree, which was approved by the court in
December 1999.  In a letter to SCE, the EPA has expressed its belief that the controls provided in the consent
decree will likely resolve the potential Clean Air Act visibility concerns.  The EPA is considering incorporating
the decree into the visibility provisions of its Federal Implementation Plan for Nevada.

SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of
the Mohave station is estimated to be approximately $560 million over the next four years.  However, SCE has
suspended its efforts to seek approval to install the Mohave controls because it has not obtained reasonable
assurance of an adequate water supply for mining and transporting the coal required for operating Mohave beyond
2005.  Accordingly, the above amount is not included in the environmental capital expenditure projections below.
The Navajo Nation and Hopi Tribe have not been willing to agree to continued use of the current source of water
from an aquifer in their joint use area after December 31, 2005.  Efforts by the Mohave co-owners to find
alternative sources of water have been unsuccessful, and it is unlikely that water rights can be obtained before
the time when the Mohave co-owners would need to make large financial commitments towards continued operation of
the Mohave station.  If adequate water rights are not obtained, it will become necessary to shut down the Mohave
station after December 31, 2005.

Edison International's projected environmental capital expenditures are $1.6 billion for the 2001-2005 period,
mainly for undergrounding certain transmission and distribution lines at SCE and upgrading environmental controls
at EME.

San Onofre Nuclear Generating Station

In February 2001, SCE's San Onofre Unit 3 experienced a fire due to an electrical fault in the non-nuclear
portion of the plant.  The turbine rotors, bearings and other components of the turbine generator system were
damaged extensively.  In June 2001, Unit 3 returned to service.  Under the currently effective San Onofre
recovery plan (discussed in the Generation and Power Procurement section of SCE's Regulatory Environment), SCE's
lost revenue was approximately $98 million as a result of the fire and related outage.


Page 46


The San Onofre Units 2 and 3 steam generators' design allows for the removal of up to 10% of the tubes before the
rated capacity of the unit must be reduced.  Increased tube degradation was found during routine inspections in
1997.  To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service.  A decreasing
(favorable) trend in degradation has been observed in more recent inspections.

Accounting Changes

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets.  Although the statement supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived
assets to be disposed of by sale.  Under the new accounting standard, asset write-downs from discontinuing a
business segment will be treated the same as other assets held for sale.  The new standard also broadens the
financial statement presentation of discontinued operations to include the disposal of an asset group (rather
than a segment of a business).  The standard is effective for Edison International beginning January 1, 2002,
unless early adoption is implemented.

In July and August 2001, three new accounting standards were issued:  Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (record goodwill for excess of
costs over the net assets acquired).

The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective
January 1, 2002.  Goodwill initially recognized after June 30, 2001, will not be amortized.  Goodwill on the
balance sheet at June 30, 2001, will be amortized until January 1, 2002.  Under the new standard, goodwill will
be tested for impairment using a fair-value approach when events or circumstances occur indicating that
impairment might exist.  Also, a benchmark assessment for goodwill is required within six months of the date of
adoption of the standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred.  When the liability is
initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived
asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset.  Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement.  The standard is
effective for fiscal years beginning after June 15, 2002, with earlier application encouraged.

Edison International is studying the impact of the new Asset Retirement Obligations, Goodwill and Other
Intangibles and Asset Impairment standards, and is unable to predict at this time the impact on its financial
statements.  Edison International does not anticipate any material impact on its results of operations or
financial position from the Business Combinations standard.

On January 1, 2001, Edison International adopted a new accounting standard for derivative instruments and hedging
activities.  The new standard requires all derivatives to be recognized on the balance sheet at fair value.
Prior to adoption, hedges were not recorded on the balance sheet.  Gains or losses from changes in the fair value
of a recognized asset or liability or a firm commitment are reflected in earnings for the ineffective portion of
the hedge.  For a hedge of the cash flows of a forecasted transaction or a foreign currency exposure, the
effective portion of the gain or loss is initially recorded as a separate component of shareholders' equity under
the caption "accumulated other comprehensive income," and subsequently reclassified into earnings when the
forecasted transaction affects earnings.  The ineffective portion of the gain or loss is reflected in earnings
immediately.  Under the new standard, SCE's derivatives qualify for hedge accounting or for the normal purchase
and sales exemption from derivatives accounting rules.  As of September 30, 2001, SCE did not have any
derivatives as defined by the new accounting


Page 47


standard.  SCE does not anticipate any earnings impact from any future derivatives, since it expects that any
market price changes will be recovered in rates.  As a result of the adoption of the new standard, Edison
International expects that earnings from its EME subsidiary will be more volatile than earnings reported under
the prior accounting policy.  For Edison International's first quarter 2001 earnings, the cumulative effect on
prior years from the adoption of the new standard is an increase of approximately $6 million (after tax).  For
Edison International's third quarter 2001 earnings, the cumulative effect of a change in accounting for
derivatives (based on additional authoritative guidance) is an increase of approximately $15 million (after tax).

Effective January 1, 2000, EME changed its accounting method for major maintenance to record such expenses as
incurred.  Previously, EME recorded major maintenance costs on an accrue-in-advance method.  EME voluntarily made
the change in accounting due to guidance provided by the Securities and Exchange Commission.  The cumulative
effect of the change in accounting method was an $18 million after-tax benefit.

Forward-Looking Information

In the preceding Management's Discussion and Analysis of Results of Operations and Financial Condition and
elsewhere in this quarterly report, the words estimates, expects, anticipates, believes, and other similar
expressions are intended to identify forward-looking information that involves risks and uncertainties.  Actual
results or outcomes could differ materially as a result of such important factors as possible challenges to the
entry of the stipulated judgment or the provisions of the settlement agreement; possible ballot initiatives
attempting to undermine the provisions of the settlement agreement or otherwise adversely affecting SCE; changes
in prices of wholesale electricity and natural gas or SCE's costs, including the prices and costs that were
assumed in negotiating the settlement agreement, which could cause SCE's cost recovery to be less than
anticipated; the actions of securities rating agencies, including the determination of  whether or when to make
changes in SCE's credit ratings; the possible inability of SCE to refinance existing obligations and obtain new
financing on reasonable terms as needed; the possibility that SCE's creditors may file an involuntary bankruptcy
petition against SCE or pursue other remedies against SCE or its assets; the outcome of negotiations for
solutions to SCE's liquidity problems; further actions by state and federal regulatory bodies setting rates,
adopting or modifying cost recovery, accounting or rate-setting mechanisms and implementing the restructuring of
the electric utility industry; actions by lenders, investors and creditors in response to SCE's suspension of
payments for debt service and purchased power; the effects, unfavorable interpretations and applications of new
or existing laws and regulations relating to restructuring, taxes and other matters; the effects of increased
competition in energy-related businesses; the availability of credit, including Edison International's and SCE's
ability to regain an investment grade rating and re-enter the credit markets; the ability of Edison International
to obtain financing without regaining an investment grade rating; changes in financial market conditions; risks
of doing business in foreign countries, such as political changes and currency devaluations; power plant
construction and operation risks; new or increased environmental liabilities; the amount of revenue available to
recover both transition and non-transition costs; the financial viability of new businesses, such as
telecommunications; weather conditions; and other unforeseen events.



Page 48


PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

Edison International

                                              Shareholder Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's Form 10-Qs for the quarterly periods ending March 31, 2001 (First Quarter 10-Q) and June
30, 2001 (Second Quarter 10-Q), Edison International has been named as a defendant along with SCE in two
lawsuits.  These lawsuits are described more fully under Southern California Edison Company - Shareholder
Litigation.

                                       Qualifying Facilities (QF) Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's First Quarter 10-Q and Second Quarter 10-Q, Edison International along with SCE has been
named as a defendant in one of the lawsuits generally described under Southern California Edison Company -
Qualifying Facilities Litigation.

Southern California Edison Company

                                       San Onofre Personal Injury Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's First Quarter 10-Q and Second Quarter 10-Q, SCE is actively involved in four lawsuits
claiming personal injuries allegedly resulting from exposure to radiation at San Onofre.

In the case filed against SCE on March 1, 2001, the Court has approved a stipulation of the parties staying
prosecution of the case pending the outcome of appellate proceedings in the matter brought against SCE on
November 17, 1995.  In that case, on September 27, 2001, the Ninth Circuit issued a new opinion affirming the
District Court's judgment in favor of SCE and the other defendants in the action.  On October 9, 2001, plaintiffs
in the November 17, 1995, action filed a petition for rehearing.

                                              Shareholder Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's First Quarter 10-Q and Second Quarter 10-Q, two purported class actions (referred to as
the Stubblefield Action and King Action) were filed in October 2000 and March 2001, and involve securities fraud
claims arising from alleged improper accounting by Edison International and SCE for undercollections in SCE's
Transition Revenue Account (TRA).

On August 3, 2001, the plaintiffs in the Stubblefield Action and King Action filed a consolidated complaint on
behalf of alleged shareholders of Edison International, naming as defendants SCE, Edison International, and
certain officers of Edison International.  The consolidated complaint alleges that defendants engaged in
securities fraud by misrepresenting and/or failing to disclose material facts concerning the financial condition
of Edison International and SCE, including that defendants allegedly over-reported income and improperly
accounted for the TRA undercollections.  The complaint purports to be filed on behalf of a class of persons who
purchased Edison International stock between July 21, 2000, and April 17, 2001.  Plaintiffs seek damages in an
unstated amount in connection with their purchase of securities during the class period.  On September 17, 2001,
the defendants filed a motion to dismiss for failure to state a claim.  Plaintiffs filed their opposition on
October 22, 2001.  The motion is scheduled for hearing on December 3, 2001.


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                                       Qualifying Facilities (QF) Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's First Quarter 10-Q and Second Quarter 10-Q, SCE is involved in a number of legal actions
brought by various QFs, alleging SCE failed to timely pay for power deliveries made from November 2, 2000,
through March 26, 2001.  The plaintiffs include gas-fired QFs, geothermal and wind energy QFs, and owners of
cogeneration projects.  The lawsuits, in aggregate, seek payments of more than $833,000,000 for energy and
capacity supplied to SCE under QF contracts, and in some cases additional damages.  Many of these QF lawsuits
also seek an order allowing the suppliers to stop providing power to SCE so that they may sell to other
purchasers.  The California court cases have been coordinated before a single trial judge.  On September 13,
2001, the coordinated trial judge dismissed, with prejudice, five of the six remaining cases on the basis that
the issues in dispute are currently within the jurisdiction of the CPUC.  The sixth case, which was filed in
federal court and therefore was not within the September 13 ruling, was stayed for 90 days by order issued on
September 24, 2001, in order to permit the CPUC to address the issues in dispute.  SCE has reached at least
tentative settlement with four of the five QFs included in the September 13 dismissal ruling.  SCE had settled
with the fifth QF included in the September 13 order as well but that settlement was contingent upon CPUC
approval of the settlement being obtained by a particular date, a condition which did not materialize.
Accordingly, that agreement has lapsed.  This nonsettling QF, whose claim is for approximately $10,500,000, has
filed a notice of appeal from the coordination trial judge's dismissal of its case.  In addition, to protect
their rights, two of the other QFs whose cases were dismissed in the coordinated state court proceeding have also
filed appeals; however, the latter QFs and SCE have, in one of the cases, jointly requested and, in the other
case, will jointly request, a stay of the appeals from the appellate court as required under the parties'
settlement agreement.

During June, July and August 2001, SCE reached agreements with generators representing about 97% of the QF
renewable cogeneration capacity provided to SCE.  The agreements provide for stays of litigation, payments to the
QFs upon the occurrence of specified conditions, modifications in some cases to the contract prices going
forward, releases and dismissals of the litigation upon payment by SCE.

Rights to attach assets in connection with claims have been granted in four cases (Beowawe Power, L.L.C., Heber
Geothermal Company, City of Long Beach, and IMC Chemicals, Inc.) in the approximate amounts of $20,000,000,
$28,000,000, $9,000,000, and $7,500,000, respectively, contingent on the posting of bonds.  The plaintiffs in
three of these cases (Beowawe, Heber and IMC Chemicals) have not posted bonds as of this time and did not attach
any SCE assets.  Each of these four cases is now stayed pursuant to an agreement of the type referenced above.
Before entering into a stay agreement pursuant to the parties' settlement, Long Beach had attached one of SCE's
bank accounts.  As noted above, the Long Beach case has recently been dismissed without prejudice pursuant to the
dismissal order in the coordination proceeding, but the dismissal remains subject to Long Beach's appeal.  In
addition, prior to the dismissal, SCE initiated a writ proceeding before the California Court of Appeal to
challenge the right to attach order in the Long Beach case, and, in connection with that writ proceeding, SCE
obtained a temporary stay of enforcement of the attachment order.  That stay and the hearing on the writ petition
were recently continued by the Court of Appeal to January 2002, based on a joint motion of the parties in light
of the order of dismissal.  Under the parties' settlement agreement discussed above, the parties shall request
that the proceedings in the Court of Appeal related to Long Beach's attachment (which in addition to SCE's
petition for review includes an ancillary appeal by SCE and a cross appeal by Long Beach) be stayed for a period
concurrent with the standstill period specified in the settlement.

                                  Power Exchange (PX) Performance Bond Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, and in Part II, Item 1 of
Edison International's Second Quarter 10-Q, SCE was notified that due to failure to comply with its payment
obligations to the PX, the PX issued a demand to American Home Assurance Company (American Home).  As required
under the indemnity agreement between SCE and American Home, in February 2001, SCE deposited $20,200,000 in an
account in trust to be available to satisfy any judgment, should there be one, against American Home.  On or
about September 13, 2001 the PX submitted a


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demand for arbitration against American Home, asserting causes of action for breach of contract and bad faith
refusal to pay.  On September 25, 2001, American Home demanded that SCE indemnify and defend American Home in
connection with the demand for arbitration, pursuant to the operative documents between the parties.  SCE has
assumed the defense of this arbitration.


Item 6.  Exhibits and Reports on Form 8-K

(a)      Exhibits

         3.1      Restated Articles of Incorporation of Edison International dated May 7, 1998
                  (File No. 1-9936, Form 10-K for the year ended December 31, 1998)*

         3.2      Certificate of Determination of Series A Junior participating Cumulative Preferred Stock of
                  Edison International dated November 21, 1996 (Form 8-A dated November 21, 1996)*

         3.3      Amended Bylaws of Edison International as adopted by the Board of Directors on October 18, 2001

         11       Computation of Primary and Fully Diluted Earnings per Share

(b)      Reports on Form 8-K:

         Date of Report                         Date Filed                      Item(s) Reported
         --------------                         ----------                      ----------------

         June 28, 2001                         July 3, 2001                           5
         June 27, 2001                         July 11, 2001                          5
         June 27, 2001                         July 22, 2001                          5

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



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                                                    SIGNATURES


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


                                                     EDISON INTERNATIONAL
                                                              (Registrant)


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


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


November 13, 2001




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