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

                                                   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                                  June 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 August 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 Six Months
                        Ended June 30, 2001, and 2000                                               1

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

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

                   Consolidated Statements of Cash Flows - Six Months
                        Ended June 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                                      23

Part II.  Other Information:

  Item 1.          Legal Proceedings                                                               53

  Item 4.          Submission of Matters to Vote of Security Holders                               56

  Item 6.          Exhibits and Reports on Form 8-K                                                56







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                    6 Months Ended
                                                                   June 30,                          June 30,
-------------------------------------------------------------------------------------------------------------------
                                                            2001              2000             2001           2000
-------------------------------------------------------------------------------------------------------------------
                                                                                (Unaudited)
Electric utility                                         $ 1,590           $ 1,853          $ 3,101         $ 3,683
Nonutility power generation                                  815               755            1,596           1,506
Financial services and other                                 222               141              392             283
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Total operating revenue                                    2,627             2,749            5,089           5,472
-------------------------------------------------------------------------------------------------------------------

Fuel                                                         329               259              657             594
Purchased power                                              807               687            2,531           1,187
Provisions for regulatory adjustment clauses - net           (90)              (97)            (119)              6
Other operation and maintenance                              886               827            1,715           1,556
Depreciation, decommissioning and amortization               267               486              527             980
Writedown of nonutility assets                               184                --              184              --
Property and other taxes                                      29                30               59              70
Net gain on sale of utility plant                             (6)               --               (7)             (7)
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Total operating expenses                                   2,406             2,192            5,547           4,386
-------------------------------------------------------------------------------------------------------------------

Operating income (loss)                                      221               557             (458)          1,086
Interest and dividend income                                  47                38               96              63
Other nonoperating income                                     19                75               31             112
Interest expense - net of amounts capitalized               (370)             (338)            (779)           (665)
Other nonoperating deductions                                (52)              (73)             (53)           (107)
Dividends on preferred securities                            (23)              (25)             (46)            (51)
Dividends on utility preferred stock                          (6)               (5)             (11)            (10)
-------------------------------------------------------------------------------------------------------------------

Income (loss) before taxes                                  (164)              229           (1,220)            428
Income taxes                                                 (62)               92             (501)            181
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Net income (loss)                                       $   (102)          $   137          $  (719)        $   247
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Weighted-average shares of common stock
   outstanding                                               326               332              326             338
Basic earnings (loss) per share                         $   (.31)         $    .41          $ (2.21)       $    .73
Weighted-average shares, including effect
    of dilutive securities                                   326               332              326             339
Diluted earnings (loss) per share                       $   (.31)         $    .41          $ (2.21)       $    .73
Dividends declared per common share                     $     --          $    .28          $    --        $    .56


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
                                                                3 Months Ended                    6 Months Ended
                                                                   June 30,                          June 30,
-------------------------------------------------------------------------------------------------------------------

                                                            2001              2000             2001           2000
-------------------------------------------------------------------------------------------------------------------
                                                                               (Unaudited)
Net income (loss)                                         $ (102)           $  137          $  (719)         $  247
Other comprehensive income, net of tax:
   Cumulative translation adjustments - net                   (6)             (100)            (109)           (147)
   Unrealized gain (loss) on securities - net                 --                 2               --              (5)
   Cumulative effect of change in accounting for derivatives  --                --              167              --
   Unrealized loss on cash flow hedges                       121                --             (283)             --
   Reclassification adjustment for losses on derivatives
      included in net income (loss)                            2               (24)             (26)            (24)
-------------------------------------------------------------------------------------------------------------------

Comprehensive income (loss)                               $  (15)          $    15          $  (970)        $    71
-------------------------------------------------------------------------------------------------------------------


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


Page 1


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS
In millions

                                                                              June 30,              December 31,
                                                                                2001                    2000
-------------------------------------------------------------------------------------------------------------------

                                                                             (Unaudited)
ASSETS
Cash and equivalents                                                         $  3,229               $  1,973
Receivables, less allowances of $50 and $40 for uncollectible
  accounts at respective dates                                                  1,426                  1,099
Accrued unbilled revenue                                                          477                    377
Fuel inventory                                                                    265                    220
Materials and supplies, at average cost                                           217                    210
Accumulated deferred income taxes - net                                         1,385                  1,350
Trading and price risk management assets                                          166                    252
Prepayments and other current assets                                              190                    185
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Total current assets                                                            7,355                  5,666
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Nonutility property - less accumulated provision for
  depreciation of $865 and $774 at respective dates                            10,441                 10,084
Nuclear decommissioning trusts                                                  2,406                  2,505
Investments in partnerships and unconsolidated subsidiaries                     2,368                  2,700
Investments in leveraged leases                                                 2,321                  2,345
Other investments                                                                 107                     92
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Total investments and other assets                                             17,643                 17,726
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Utility plant, at original cost
   Transmission and distribution                                               13,332                 13,129
   Generation                                                                   1,722                  1,745
Accumulated provision for depreciation and decommissioning                     (7,914)                (7,834)
Construction work in progress                                                     623                    636
Nuclear fuel, at amortized cost                                                   141                    143
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Total utility plant                                                             7,904                  7,819
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Regulatory assets - net                                                         2,741                  2,390
Other deferred charges                                                          1,755                  1,499
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Total deferred charges                                                          4,496                  3,889
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Total assets                                                                 $ 37,398               $ 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

                                                                              June 30,             December 31,
                                                                                2001                   2000
-------------------------------------------------------------------------------------------------------------------

                                                                             (Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt                                                              $  4,153              $  3,920
Long-term debt classified as due within one year                                4,544                 2,260
Preferred stock to be redeemed within one year                                    105                    --
Accounts payable                                                                3,460                 1,228
Accrued taxes                                                                      60                   593
Regulatory liabilities - net                                                      197                   195
Trading and risk management liabilities                                           125                   282
Other current liabilities                                                       2,381                 2,322
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Total current liabilities                                                      15,025                10,800
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Long-term debt                                                                 10,717                12,150
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Accumulated deferred income taxes - net                                         5,444                 5,328
Accumulated deferred investment tax credits                                       177                   183
Customer advances and other deferred credits                                    1,807                 1,692
Power-purchase contracts                                                          411                   467
Accumulated provision for pensions and benefits                                   520                   438
Other long-term liabilities                                                        98                    94
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Total deferred credits and other liabilities                                    8,457                 8,202
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Commitments and contingencies (Notes 1, 2 and 4)
Minority interest                                                                 344                    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                                    949                   949
Other preferred securities                                                        176                   176
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Total preferred securities of subsidiaries                                      1,405                 1,510
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Common stock (325,811,206 shares outstanding at each date)                      1,960                 1,960
Accumulated other comprehensive income (loss)                                    (390)                 (139)
Retained earnings (deficit)                                                      (120)                  599
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Total common shareholders' equity                                               1,450                 2,420
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Total liabilities and shareholders' equity                                   $ 37,398              $ 35,100
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                    The accompanying notes are an integral part of these financial statements.



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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In millions

                                                                                        6 Months Ended
                                                                                           June 30,
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                                                                                  2001                      2000
-------------------------------------------------------------------------------------------------------------------

                                                                                          (Unaudited)
Cash flows from operating activities:
Net income (loss)                                                            $    (719)                  $   247
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
   Depreciation, decommissioning and amortization                                  527                       980
   Other amortization                                                               40                        90
   Deferred income taxes and investment tax credits                                (68)                        8
   Equity in income from partnerships and unconsolidated subsidiaries             (200)                      (95)
   Income from leveraged leases                                                    (62)                      (97)
   Regulatory assets - long-term - net                                            (236)                     (543)
   Writedown of nonutility assets                                                  184                        --
   Net gain on sale of marketable securities                                        --                       (57)
   Other assets                                                                    (81)                      (75)
   Other liabilities                                                                (9)                      (43)
   Changes in working capital:
     Receivables and accrued unbilled revenue                                       86                      (224)
     Regulatory liabilities - short-term - net                                       7                       396
     Fuel inventory, materials and supplies                                         (5)                        7
     Prepayments and other current assets                                          243                        (1)
     Accrued interest and taxes                                                   (450)                      150
     Accounts payable and other current liabilities                              1,621                       259
Distributions and dividends from unconsolidated entities                            59                        67
-------------------------------------------------------------------------------------------------------------------

Net cash provided by operating activities                                          937                     1,069
-------------------------------------------------------------------------------------------------------------------

Cash flows from financing activities:
Long-term debt issued                                                            1,742                     2,558
Long-term debt repaid                                                           (1,289)                   (2,184)
Bonds repurchased and funds held in trust                                         (130)                       --
Issuance of preferred securities                                                    14                        --
Common stock repurchased                                                            --                      (386)
Rate reduction notes repaid                                                       (112)                     (113)
Short-term debt financing - net                                                    497                       532
Dividends paid                                                                      --                      (188)
Nuclear fuel financing - net                                                       (10)                      (22)
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Net cash provided by financing activities                                          712                       197
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Cash flows from investing activities:
Additions to property and plant                                                   (472)                     (721)
Proceeds from sale of nonutility property                                          172                        25
Funding of nuclear decommissioning trusts                                           20                       (59)
Investments in partnerships and unconsolidated subsidiaries                       (127)                     (168)
Proceeds from sales of marketable securities                                        --                        58
Investments in leveraged leases                                                     69                        13
Sales of investments in other assets                                                15                       (16)
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Net cash used by investing activities                                             (323)                     (868)
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Effect of exchange rate changes on cash                                            (70)                      (41)
Net increase in cash and equivalents                                             1,256                       357
Cash and equivalents, beginning of period                                        1,973                       507
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Cash and equivalents, end of period                                          $   3,229                   $   864
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                    The accompanying notes are an integral part of these financial statements.



Page 4


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 June 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 and external financings.

The increasing 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 continued regulatory uncertainty regarding SCE's ability to recover its current and future
power procurement costs, have 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 temporarily suspended payments of certain
obligations for principal and interest on outstanding debt and for purchased power.  As of July 31, 2001, SCE had
$3.3 billion in obligations that were unpaid and overdue including: (1) $878 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) $230 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.  As
applicable, unpaid obligations will continue to accrue interest.  At July 31, 2001, SCE had estimated cash
reserves of approximately $1.7 billion (after deducting $419 million of designated funds), which is approximately
$1.6 billion less than its outstanding unpaid obligations and preferred stock dividends in arrears (see below).
If SCE is found responsible for purchases of power by the California Department of Water Resources (CDWR) or the
ISO for sale to SCE's customers on or after January 18, 2001, SCE's unpaid obligations as of July 31, 2001, could
increase by as much as $1.9 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 the 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 is 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.  If the Memorandum of Understanding (MOU) is implemented (as further
discussed in Note 2), it is expected to allow SCE to recover its undercollected costs and help to restore SCE's
creditworthiness, which would allow SCE to pay all of its past due obligations.

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 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.

Based on these decisions, the uncertainty about the amount of revenue the CDWR will require to pay its bond and
energy procurement costs, and how much of the revenue requirement will be allocated to SCE (as further discussed
in Note 2), SCE estimates that future cash may not be sufficient to cover retained generation, purchased-power
and transition costs.  In comments filed with the CPUC in March and April  2001, SCE provided a forecast showing
that the net effects of the rate increase, the payment ordered to be made to the CDWR, and the QF decision could
result in a shortfall to the CPA calculation during 2001.  To implement the MOU, it will be necessary for the
CPUC to modify or rescind these decisions.

In light of SCE's liquidity crisis, its Board of Directors did not declare quarterly common stock dividends to
SCE's parent, Edison International, in December 2000, March 2001 or June 2001; and Edison International's Board of
Directors did not declare 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.  The total
SCE's preferred stock dividends in arrears were $11 million as of July 31, 2001.  As a result of SCE's
$2.5 billion charge to earnings as of December 31, 2000, SCE's retained earnings are now in a deficit position and
therefore under California law, SCE will be unable to pay dividends as long as a deficit remains, unless SCE
meets certain conditions under which dividends can be paid from sources other than retained earnings.  SCE does
not meet these conditions.  As long as accumulated dividends on SCE's preferred stock remain unpaid, SCE cannot
pay any dividends on its common stock.

In addition to the above, SCE has implemented cost-cutting measures which, together with previously announced
actions, such as freezing new hires, postponing certain capital expenditures and ceasing new charitable
contributions, are aimed at reducing general operating costs.  SCE's current cost-cutting measures are intended
to allow it to continue to operate while efforts to reach a regulatory solution, involving both state and federal
authorities, are underway.  Additional actions by SCE may be necessary if the energy and liquidity crisis is not
resolved in the near future.

SCE's future liquidity depends, in large part, on whether action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow deficit created by the current rate
structure and the volatility in the price of wholesale electricity and natural gas.  Without a change in



Page 6


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

circumstances, resolution of SCE's liquidity crisis and its ability to continue to operate outside of bankruptcy
is uncertain.

The parent company 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

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 SCE's nuclear
plants.  Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract.  Most of the remaining transition costs may be recovered through the end of the transition period (not
later than March 31, 2002).  Although the MOU provides for, among other things, SCE to be entitled to sufficient
revenue to cover its costs associated with retained generation and existing power contracts since January 2001,
the implementation of the MOU requires the CPUC to modify various decisions.  Until the regulatory and
legislative actions that make such recovery probable are taken, SCE is 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 net regulatory assets related to certain generating assets are probable of recovery through the
rate-making process.  As a result, these balances were written off as a charge to earnings as of December 31,
2000.

During the rate freeze period, there are three sources of revenue available to SCE for transition cost recovery:
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 sale or valuation of generation assets in excess of book values (state legislation enacted in
January 2001 prohibits the sale of SCE's remaining generation assets until 2006) and from the sale of
SCE-controlled generation into the ISO and PX markets is no longer available to SCE.  Net proceeds of the 1998
plant sales were used to reduce transition costs, which otherwise were expected to be collected through the TCBA
mechanism.

Net market revenue from sales of power and capacity from SCE-controlled generation sources was also applied to
transition cost recovery.  Increases in market prices for electricity affected SCE in two fundamental ways prior
to the CPUC's March 27, 2001, rate stabilization decision.  First, CTC revenue decreased because there was less
or no residual revenue from frozen rates due to higher cost PX and ISO power purchases.  Second, transition costs
decreased because there was increased net market revenue due to sales from SCE-controlled generation sources to
the PX at higher prices (accumulated as an overcollection in the coal and hydroelectric balancing accounts).
Although the second effect mitigated the first to some extent, the overall impact on transition cost recovery was
negative because SCE purchased more power than it sold to the PX.  In addition, higher market prices for
electricity adversely affected SCE's ability to recover non-transition costs during the rate freeze period.

CTC revenue is determined residually (i.e., CTC revenue is 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 applies to all customers who are using or begin using utility services on or after the CPUC's 1995
restructuring decision date.  Residual CTC revenue is calculated through the TRA mechanism.  Under CPUC decisions
in existence prior to March 27, 2001, positive residual CTC revenue (TRA overcollections) was transferred to the
TCBA monthly; TRA undercollections were to remain in the TRA until they were offset by overcollections, or the
rate freeze ended, whichever came first.  Between May 2000 and June 2001, market prices for electricity were
extremely high and there was insufficient revenue from customers under the frozen rates to cover all costs of



Page 7


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

providing service during that period, and therefore there was no positive residual CTC revenue transferred into
the TCBA.  In accordance with the March 27, 2001, rate stabilization decision, both positive and negative
residual CTC revenue is transferred to the TCBA on a monthly basis, retroactive to January 1, 1998.

Recalculating the TCBA balance based on the March 2001 decision resulted in positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover SCE's transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000.  Between May 2000 and January 18, 2001 (when the CDWR began making power purchases
for SCE's customers), SCE's costs to provide power exceeded revenue from frozen rates.  Even though SCE is no
longer supplying its customers with all their electricity needs, SCE's total transition cost have continued to
exceed revenue from frozen rates through June 30, 2001.  As a result, the cumulative positive residual CTC
revenue flowing into the TCBA mechanism has been reduced from $4.7 billion to $2.7 billion as of June 30, 2001.
The cumulative TCBA undercollection (as recalculated) was $2.9 billion as of December 31, 2000, and $4.2 billion
as of June 30, 2001.  A summary of the components of this cumulative undercollection as of June 30, 2001, is as
follows:

         In millions
-----------------------------------------------------------------------------------------------------
         Transition costs recorded in the TCBA:
           QF and interutility costs                                                   $    5,590
           Amortization of nuclear-related regulatory assets                                3,561
           Depreciation of plant assets                                                       656
           Other transition costs                                                             760
-----------------------------------------------------------------------------------------------------

              Total costs                                                                  10,567
         Revenue available to recover transition costs                                     (6,331)
-----------------------------------------------------------------------------------------------------

              TCBA undercollections                                                    $    4,236
-----------------------------------------------------------------------------------------------------


Unless the regulatory and legislative actions that make recovery probable are taken, SCE is unable to conclude
that the recalculated TCBA net undercollection is 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 December 31,
2000, and an additional $1.4 billion in TCBA undercollections was charged to earnings for the six months ended
June 30, 2001.  In its interim rate stabilization decision of March 27, 2001, the CPUC denied SCE's motion to end
the rate freeze, and stated that it will not end until recovery of all specified transition costs (including TCBA
undercollections as recalculated) or March 31, 2002.

Rate Stabilization Proceedings

In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
current rate freeze ends 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.  SCE's plan included a trigger mechanism allowing for rate
increases of 5% every six months if SCE's TRA undercollection balance exceeds $1 billion.

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 covers, 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.  On April 3, 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



Page 8



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.  The MOU calls for the CPUC to adopt
a decision clarifying that the first priority condition in SCE's 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.  SCE cannot provide assurance that the CPUC will adopt such a decision, or
predict what effects any investigation or any subsequent actions by the CPUC may have on SCE.

On March 27, 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.  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 on June 3, 2001.  The CPUC also
ordered that the 3(cent)surcharge be added to the rate paid to the CDWR.

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.  SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs in the TCBA.  However, the CPUC
characterized the accounting changes as merely reducing the prior residual CTC revenue recorded in the TCBA, thus
only affecting the amount of transition cost recovery achieved to date.  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
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.  If the
CPUC does not modify this decision in a manner acceptable to SCE, SCE intends to challenge this decision through
all appropriate means.

Although the CPUC has authorized a substantial rate increase in its March 2001, order, it has allocated the
revenue from the increase entirely to future purchased-power costs without addressing SCE's past undercollections
for the costs of purchased power.  The CPUC's decisions do not assure that SCE will be able to meet its ongoing
obligations or repay past due obligations.  By ordering immediate payments to the CDWR and QFs, the CPUC impacted
SCE's future cash flow and liquidity problems.  Additionally, the CPUC stated that Assembly Bill 1 (First
Extraordinary Session, AB 1X) continues the utilities' obligations to serve their customers, and stated that it
cannot assume that the CDWR will purchase all the electricity needed above what the utilities either generate or
have under contract (the net short position) and cannot order the CDWR to do so.  This could result in additional
purchased power costs with no allowed means of recovery.  To take action that will restore SCE's
creditworthiness, it will be necessary for the CPUC to modify or rescind these decisions.  SCE cannot provide any
assurance that the CPUC will do so.

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.  On December 15, 2000, the FERC released a final order
containing remedies and other actions in response to the problems in the California electricity market.  The
order, among other things, eliminated the requirement for California utilities to buy and sell power exclusively
through the ISO and PX; created a benchmark price for wholesale bilateral power contracts; created penalties for
under-scheduling power loads; provided for an independent governing board for the ISO; and established a




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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

breakpoint of $150/MWh so that bids below $150 may clear at a single market-clearing price at or below $150/MWh
and bids above $150 will be paid as bid.  On December 18, 2000, SCE filed with the FERC an emergency request for
rehearing of the December 15 order.  On January 12, 2001, the FERC issued an order granting rehearing for the
purpose of further consideration.  The PX did not immediately implement the $150/MWh breakpoint and on February
26, 2001, made a compliance filing with the FERC, which requested the FERC's guidance on an acceptable
recalculation methodology.

In December 2000, 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.  On January 5, 2001, the court denied
SCE's petition.  SCE's petition for rehearing remains pending.  SCE is considering the possibility of judicial
appeals and other actions.

In December 2000, the ISO announced that generators of electricity were refusing to sell into the California
market due to concerns about the financial stability of SCE and Pacific Gas and Electric Company.  In response to
this announcement, on December 14, 2000, the United States Secretary of Energy issued an order requiring power
companies to make arrangements to generate and deliver electricity as requested by the ISO after the ISO
certifies that it has been unable to acquire adequate supplies of electricity in the market.  After being renewed
multiple times, the order expired on February 6, 2001.  However, on February 7, 2001, a federal court judge
issued a temporary restraining order requiring power suppliers to sell to the California grid.  On March 21,
2001, a federal court judge ordered one of the power suppliers to continue to sell power to the California grid.
Three other power suppliers have signed an agreement with the judge voluntarily agreeing to continue to sell
power to the grid while awaiting a review of the issue by the FERC.  On April 6, 2001, the United States Court of
Appeals issued a stay order, suspending the lower court's March 21 order until a final appeals ruling can be
issued.

In December 2000, the FERC established a penalty applicable to scheduling coordinators that do not schedule
sufficient resources to supply 95% of their respective loads.  SCE has sought a suspension of the so-called
"underscheduling penalty."  SCE has also sought a rehearing of a FERC order, issued in May 2001, which rejected
the ISO's proposal for suspension of the underscheduling penalty.  In the May 2001 order, the FERC also indicated
that it will make a determination regarding the suspension of the underscheduling penalty in a future order on a
complaint filed by SCE and PG&E that asked the FERC to eliminate the penalty.  As of July 2001, the statewide
accumulated penalties were estimated by the ISO to be approximately $1 billion.  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, 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.  The new approach replaces the $150/MWh
breakpoint discussed above.

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 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.  A prehearing conference
is scheduled for August 13, 2001.

Memorandum of Understanding with the CDWR

On April 9, 2001, Edison International and SCE signed an MOU with the CDWR regarding the California energy crisis
and its effects on SCE.  The Governor of California and his representatives participated in the negotiation of
the MOU, and the Governor endorsed implementation of all the elements of the MOU.  The MOU sets forth a



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

comprehensive plan calling for state legislation and regulatory action and definitive agreements to resolve
important aspects of the energy crisis, and which, if implemented, is expected to help restore SCE's
creditworthiness and liquidity.  Key elements of the MOU include:

o    SCE will sell its transmission assets to the CDWR, or another authorized state agency, at a price equal to
     2.3 times their aggregate book value, or approximately $2.76 billion.  If a sale of the transmission assets
     is not completed under certain circumstances, SCE's hydroelectric assets and other rights may be sold to the
     state in their place.  SCE will use the proceeds of the sale in excess of book value to reduce its
     undercollected costs and retire outstanding debt incurred in financing those costs.  SCE will agree to
     operate and maintain the transmission assets for at least three years, for a fee to be negotiated.

o    Two dedicated rate components will be established to assist SCE in recovering the net undercollected amount
     of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion.  The
     first dedicated rate component will be used to securitize the excess of the undercollected amount over the
     expected gain on sale of SCE's transmission assets, as well as certain other costs.  Such securitization
     will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of
     other conditions of the MOU.  The second dedicated rate component would not be securitized and would not
     appear in rates unless the transmission sale failed to close within a two-year period.  The second component
     is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be
     recovered through the gain on the transmission sale.

o    SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through
     2010.  SCE will be entitled to collect revenue sufficient to cover its costs from January 1, 2001,
     associated with the retained generation assets and existing power contracts.  The MOU calls for the CPUC to
     adopt cost recovery mechanisms consistent with SCE obtaining and maintaining an investment grade credit
     rating.

o    The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers
     within SCE's service territory through December 31, 2002, to the extent that those needs are not met by
     generation sources owned by or under contract to SCE.  (The unmet needs are referred to as SCE's net short
     position.)  SCE will resume procurement of its net short position after 2002.  The MOU calls for the CPUC to
     adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility.

o    SCE's authorized return on equity will not be reduced below its current level of 11.6% before December 31,
     2010.  Through the same date, a rate-making capital structure for SCE will not be established with different
     proportions of common equity or preferred equity to debt than set forth in current authorizations.  These
     measures are intended to enable SCE to achieve and maintain an investment-grade credit rating.

o    Edison International and SCE will commit to make capital investments in the utility of at least $3 billion
     through 2006, or a lesser amount approved by the CPUC.  The equity component of the investments will be
     funded from SCE's retained earnings or, if necessary, from equity investments by Edison International.

o    EME will execute a contract with the CDWR for the provision of power from a designated project to the state
     at cost-based rates for 10 years.  The Sunrise power project, which meets this obligation, began commercial
     operation on June 27, 2001.

o    SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with
     SCE's Big Creek and Eastern Sierra hydroelectric facilities.  The easements initially will be held by a trust
     for the benefit of the state, but ultimately may be assigned to nonprofit entities or certain governmental
     agencies.  SCE will be permitted to continue utility uses of the subject lands.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

o    After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its
     federal district court lawsuit against the CPUC seeking recovery of past undercollected costs.  The
     settlement or dismissal will include related claims against the state or any of its agencies, or against the
     federal government.

The sale of SCE's transmission system and other elements of the MOU must be approved by the FERC.  Edison
International, SCE and the CDWR committed in the MOU to proceed in good faith to sponsor and support the required
state legislation and to negotiate in good faith the necessary definitive agreements.  The MOU may be terminated
by either SCE or the CDWR if required legislation is not adopted and definitive agreements executed by August 15,
2001, or if certain other adverse changes occur.  Since the required legislation will not be enacted, necessary
regulatory actions will not be taken, and definitive agreements will not be executed before the applicable
deadlines, the MOU will be terminable unless the parties choose to extend the deadlines.

Since the execution of the MOU, SCE has made several filings with the CPUC addressing elements of the MOU.
Although the CPUC did not adopt the implementing decisions contemplated by the MOU within the projected timeframe
set out in the MOU, the CPUC continues to process SCE's filings.  However, SCE cannot assure that the necessary
implementing decisions will be passed, nor whether any decisions ultimately adopted will be acceptable to SCE.

Legislation to address the MOU and issues relating to SCE's creditworthiness has been introduced in both the
California State Senate and Assembly as part of the 2001-02 Second Extraordinary Session.

Senate Bill 78XX was introduced in May 2001.  As introduced, the bill would have implemented the MOU in its
entirety.  However, Senate Bill 78XX was significantly amended in July.  As amended, Senate Bill 78XX would allow
SCE to securitize a significant portion of the past procurement undercollections, but would not allow SCE to
recover from ratepayers unpaid PX and ISO costs aggregating approximately $1 billion, or interest accruing on the
past procurement undercollections after January 31, 2001 (estimated to be approximately $400 million by year end
2001).  The bill would provide the State of California with a five-year option to purchase SCE's transmission
system at book value, and contains provisions for conservation easements similar to the MOU.  SCE opposed Senate
Bill 78XX on the grounds that SCE did not believe that the bill would provide the elements necessary to return
SCE to investment grade credit status and it believed that other provisions of the bill were also objectionable.
Senate Bill 78XX was approved by the Senate on July 20, 2001, and was referred to the State Assembly.  The
leadership of the Assembly has indicated its intent to amend the bill.  If amended by the Assembly, the amended
bill would return to the State Senate for a concurrence vote (the Senate must accept the bill as passed by the
Assembly or the bill is rejected).  The bill would reach the Governor's desk only if agreed to by the Senate.  In
the alternative, the Senate and Assembly could agree to refer the bill to a Conference Committee.

The Assembly introduced two bills, Assembly Bill 82XX and Assembly Bill 50XX.  Assembly Bill 50XX would have
allowed for recovery of all but $300 million of SCE's past procurement-related debt with no sale of SCE's
transmission assets or grant of conservation easements.  SCE supported this bill as most likely to return SCE to
investment grade credit status.  However, Assembly Bill 50XX was not passed by the Assembly Appropriations
Committee.  Assembly Bill 82XX was approved by both the Assembly Policy and Appropriations Committees, and is
currently on the floor of the Assembly.  That bill would allow SCE to securitize all of its net past procurement
undercollection except for $500 million, and would authorize the sale of SCE's transmission assets.  In
committee, SCE was supportive of Assembly Bill 82XX, but advocated amendments.

The Legislature is in recess until August 20, 2001.  During the summer interim recess, a working group of certain
Assembly members has been formed to identify additional amendments to Assembly Bill 82XX and/or to propose
amendments to Senate Bill 78XX.  SCE continues to work with the authors of all the bills.  However, SCE cannot
assure that legislation will be passed, nor whether any such legislation will ultimately be acceptable to SCE or
would be signed by the Governor.




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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Utility Retained Generation

In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
ratemaking for utility retained generation through the end of 2002.  The 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.  SCE proposed a
fifth balancing account to track generation-related undercollections incurred before January 31, 2001.  Hearings
were held in July 2001.  A final decision is expected later in 2001.

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.  On February 1, 2001, 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 revenue bonds to finance electricity purchases.  On May 10, 2001,
the Governor signed a bill authorizing the CDWR to issue up to $13.4 billion in bonds.  The law became effective
August 8, 2001.  AB 1X directed the CPUC to determine the amount of the CPA as a residual amount of SCE's
generation-related revenue, after deducting the cost of SCE-owned generation, QF contracts, existing bilateral
contracts and ancillary services.  AB 1X also directed the CPUC to determine the amount of the CPA that is
allocable to the power sold by the CDWR, which will be payable to the CDWR when received by SCE.  On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's purchases are not subject to prudency
review by the CPUC, and that the CPUC must approve and impose, either as a part of existing rates or as
additional rates, rates sufficient to enable the CDWR to recover its revenue requirements.

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 July 23, 2001, the CDWR submitted a proposed $13.1 billion revenue requirement to the CPUC (revised to $12.6
billion on August 7, 2001) to pay its bonds' costs and energy procurement costs for 2001 and 2002.  In comments
filed with the CPUC on August 3, 2001, SCE indicated that based on the CDWR methodology, SCE's share of the $13.1
billion revenue requirement would be approximately $5.8 billion, which would require SCE to increase its current
payment to the CDWR from 10.277(cent)per kWh to 15.9(cent)per kWh.  SCE requested that the CPUC refrain from adopting a
final revenue requirement until all parties receive information that is essential to understanding how the
revenue requirement was calculated and its relationship to the utilities' revenue requirement.  SCE also
requested that the CPUC adopt fundamental principles, such as cost of service, to guide its view of the CDWR
revenue requirement.  The CPUC will allow parties to file supplemental comments on the CDWR's revised revenue
requirement on August 14, 2001.  To take actions that will make SCE creditworthy, the CPUC will need to provide
reasonable assurance that SCE will be able to recover its ongoing costs, including the costs associated with
CDWR's revenue requirement.




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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 is only purchasing 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, takes 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 CDWR or ISO for sale to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs (and pre-tax loss) for the six months ended June 30, 2001, could increase by as much as
$1.9 billion (which includes bills received for January through May 2001, and an estimate for June 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.  On April 6, 2001,
the FERC issued an order confirming its February 14, 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.
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, the day after the Governor signed the order authorizing the CDWR to begin purchasing
power for utility customers.  SCE cannot predict the outcome of any of these proceedings or issues.  The MOU
states that the CDWR will assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the extent those needs are not met by
generation sources owned by or under contract to SCE (SCE's net short position).  Under the MOU, SCE will resume
buying power for its net short position after 2002.  The MOU calls for the CPUC to adopt cost-recovery mechanisms
to make it financially practicable for SCE to reassume this responsibility.

Hydroelectric Market Value Filing

In 1999, SCE filed an application with the CPUC establishing a market value for its hydroelectric
generation-related assets at approximately $1.0 billion (almost twice the assets' book value) and proposing to
retain and operate the hydroelectric assets under a performance-based, revenue-sharing mechanism.  If approved by
the CPUC, SCE would be allowed to recover an authorized, inflation-indexed operations and maintenance allowance,
as well as a reasonable return on capital investment.  A revenue-sharing arrangement would be activated if
revenue from the sale of hydroelectricity exceeds or falls short of the authorized revenue requirement.  SCE
would then refund 90% of the excess revenue to ratepayers or recover 90% of any shortfall from ratepayers.  If
the MOU is implemented, SCE's hydroelectric assets will be retained through 2010 under cost-based rates, or they
may be sold to the state if a sale of SCE's transmission assets is not completed under certain circumstances.

Note 3.  Business Segments

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



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the three and six months ended June 30, 2001, and 2000, was:

                                                     3 Months Ended                   6 Months Ended
                                                        June 30,                         June 30,
----------------------------------------------------------------------------------------------------------

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

     Operating Revenue:
     Electric utility                          $ 1,590          $ 1,853         $ 3,101          $ 3,683
     Unregulated power generation                  815              755           1,596            1,506
     Capital and financial services                 73               68             116              134
     Corporate and other                           149               73             276              149
----------------------------------------------------------------------------------------------------------

     Consolidated Edison International         $ 2,627          $ 2,749         $ 5,089          $ 5,472
----------------------------------------------------------------------------------------------------------

     Net Income (Loss):
     Electric utility(1)                          $ 28         $    156         $  (570)        $    270
     Unregulated power generation                   --              (19)              9              (31)
     Capital and financial services                 24               39              36               77
     Corporate and other                          (154)             (39)           (194)             (69)
----------------------------------------------------------------------------------------------------------

     Consolidated Edison International         $  (102)        $    137         $  (719)        $    247
----------------------------------------------------------------------------------------------------------


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

Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.  The
net loss reported in 2001 includes a $117 million charge (after tax) related to the sale of assets discussed in
Note 7.

Total segment assets as of June 30, 2001, were: electric utility, $18 billion; unregulated power generation, $15
billion; capital and financial services, $4 billion.

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.  SCE and Edison International have until September 17, 2001, to
respond to the consolidated complaint.  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 largely been coordinated before a single trial judge. SCE has reached agreements with QFs
representing about 95% of the QF renewable and cogeneration energy provided to SCE.  The agreements provide for



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 other long-term liabilities) at
undiscounted amounts.

Edison International's recorded estimated minimum liability to remediate its 44 identified sites is $116
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 that, due to
these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to
$272 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 $46 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 $75 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 $20 million.  Recorded
expenditures for the twelve-month period ended June 30, 2001 were $19 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



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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $19 million per year. Insurance premiums are charged to operating
expense.

Spent Nuclear Fuel

Under federal law, the Department of Energy 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.



Page 17



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Paiton Project

A wholly owned subsidiary of EME (Paiton Energy) owns a 40% interest and has a $503 million investment (at June
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 have signed an agreement
providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 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 June 30,
2001, while negotiations regarding the long-term restructuring of the tariff 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.




Page 18


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 through 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 June 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.  In the three and six
months ended June 30, 2001, EME has recorded net losses of $0.3 million and $7.4 million, respectively (after
tax), as the changes in the fair value of derivatives required under the new accounting standard that previously
qualified for hedge accounting.  EME recorded a $6 million (after tax) increase to net income as a cumulative
change in the accounting for derivatives during the six months ended June 30, 2001.  In addition, EME recorded a
$230 million (after tax) unrealized holding loss upon adoption of a change in accounting principle reflected in
accumulated other comprehensive income in the consolidated balance sheet.  During the quarter ended June 30,
2001, EME recorded a $120 million (after tax), unrealized holding gain reflected in accumulated other
comprehensive income in the consolidated balance sheet.  EME has recorded net gains of $1.5 million and $1.6
million in the three and six months ended June 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, through June 30, 2001.  Effective July 1,
2001, recently issued accounting guidance extended the normal sales and purchases exception to include forward
sales contracts subject to net settlement procedures with counterparties.  Accordingly, EME intends to use the
normal sales and purchases exception for its Homer City forward sales contracts commencing July 1, 2001, and
plans to record a cumulative change in the accounting for derivatives during the quarter ended September 30,
2001.  EME is currently evaluating the impact of the implementation guidance on its remaining commodity contracts
which would be accounted for on a prospective basis.

The unrealized gains (losses) on cash flow hedges at June 30, 2001, included forward sales contracts from EME's
Homer City plant that did not meet the normal sales and purchases exception under the new accounting standard due
to EME's net settlement procedures with counterparties.  In addition, 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 also could not quality under the normal sales and purchases exception because
financial settlement of the contract occurs without physical delivery.  Approximately 93% of EME's accumulated
other comprehensive loss at June 30, 2001, related to unrealized losses on cash flow hedges resulting from the
Homer City and Loy Yang B contracts.  These net 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 contracts mitigate price risk associated with future changes in
market prices and are at prices that meet EME's profit objectives.  Assuming the long-term contracts with the




Page 19



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

State Electricity Commission of Victoria continue 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 also 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.  If the MOU is implemented, SCE will relinquish all claims against the state for seizing these
contracts.  If the MOU is not implemented, SCE believes that it should be compensated for the reasonable value of
these contracts under law, and would pursue the matter.  Edison International's June 30, 2001, balance sheet does
not include these contracts.  As of June 30, 2001, SCE did not have any derivatives as defined by the new
accounting standard that were not considered normal purchases or sales.

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 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 contracts with other utilities and QFs.  Purchases and
generation sales amounts for the quarter ended June 30, 2001, reflect billing adjustments.  Purchased power
detail is provided below:

                                                                 3 Months Ended          6 Months Ended
                                                                    June 30,                June 30,
---------------------------------------------------------------------------------------------------------

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

         PX/ISO:
         Purchases                                           $ (446)     $ 1,529      $   635    $ 2,041
         Generation sales                                      (382)       1,277          323      1,717
---------------------------------------------------------------------------------------------------------

         Purchased power - PX/ISO - net                         (64)         252          312        324
         Purchased power - bilateral contracts                   37           --           89         --
         Purchased power - interutility/QF contracts            834          435        2,130        863
---------------------------------------------------------------------------------------------------------

         Total                                               $  807      $   687      $ 2,531    $ 1,187
---------------------------------------------------------------------------------------------------------


Note 7.  Acquisitions and Dispositions

Edison Mission Energy

During the second quarter of 2001, EME completed the purchase of additional shares of Contact Energy for
NZ$152 million, increasing its ownership interest from 42.6% to 51.2%.  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.  In June and July 2001, EME issued through one of its subsidiaries
new preferred securities to repay the bridge loan.

On June 25, 2001, EME sold a 50% interest in its Sunrise project to Texaco for $84 million (50% of the project
costs, prior to commercial operations).  Commercial operation commenced on June 27, 2001.




Page 20


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 29, 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 ($3 million after tax).

Edison Enterprises

During second quarter 2001, Edison Enterprises, a wholly owned subsidiary of Edison International, decided to
sell some of its assets.  On August 2, 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 subsidiary of Tyco International Ltd.

On June 7, 2001, another Edison Enterprises subsidiary (engaged in the business of integrated energy outsourcing)
entered into a letter of intent to sell substantially all of its assets to its current management.  The sale is
anticipated to be completed in late 2001.

The carrying amount of the Edison Enterprises operations' 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
businesses held for sale had net losses of $9 million and $18 million for the six-month periods ended June 30,
2001 and 2000, respectively.

Note 8.  New Accounting Standards

In July and August 2001, the Financial Accounting Standards Board issued three new accounting standards:
"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.

Edison International is studying the impact of the new Asset Retirement Obligations 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 21


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.  Subsequent Events

On August 10, 2001, EME issued $400 million of 10% senior notes, due in 2008.  EME used the proceeds to repay
indebtedness under its corporate credit facilities, reducing the outstanding commitments under these facilities
to $823 million.

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.  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.

On July 2, 2001, EME redeemed NZ$400 million of retail redeemable preference shares at their issuance price.
Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility
scheduled to mature in July 2005.  The financing documents governing the credit facility provide that the credit
facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit
facility.  The NZ$400 million was originally funded as a revolving credit facility.



Page 22




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), are currently
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 1(cent)-per-kWh and 3(cent)-per-kWh surcharges effective first quarter 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 financial drain on SCE.

On April 9, 2001, Edison International, SCE and the California Department of Water Resources (CDWR) executed a
memorandum of understanding (MOU) which sets forth a comprehensive plan calling for legislation, regulatory
action and definitive agreements to resolve important aspects of the energy crisis, and which is expected to help
restore SCE's creditworthiness and liquidity.  The Governor of California and his representatives participated in
the negotiation of the MOU, and the Governor endorsed implementation of all the elements of the MOU.  SCE and the
CDWR committed in the MOU to proceed in good faith to sponsor and support the required legislation and to
negotiate in good faith the necessary definitive agreements.  The legislation required to implement the MOU is in
doubt and a number of alternative measures have been proposed in the legislature.  See further discussion in
Memorandum of Understanding with the CDWR.

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 determined that
regulatory assets, such as the TRA and the TCBA, were no longer probable of recovery through future rates, they
were 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.
Until legislative and regulatory actions are taken, SCE is unable to conclude that its undercollected costs that
are recovered through the TCBA mechanism are probable of recovery in future rates.  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.  In addition, SCE
currently does not have regulatory authority to recover any purchased-power costs it incurs during 2001 in excess
of revenue from retail rates.  Transition costs in excess of transition revenue are charged against earnings in
2001 absent a regulatory or legislative solution, such as implementation of the actions called for in the MOU
that make recovery of such costs probable.  Unrecovered transition costs charged to earnings were $724 million
(after tax) for the six months ended June 30, 2001.  This has 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.  The December 31, 2000, write-off also caused SCE to be
unable to meet an earnings test that must be met before SCE can issue additional first mortgage bonds.  If a rate
mechanism provided by legislation or regulatory authority is established that makes recovery from regulated rates
probable as to all or a portion of the amounts that were previously charged against earnings, accounting
standards provide that a regulatory asset would be reinstated with a corresponding increase in earnings.




Page 23



The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the
devastating 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 possible resolution of the current crisis through implementation of the MOU or other corrective action.

Results of Operations

Earnings

Edison International recorded losses of 31(cent)per share and $2.21 per share, respectively, for the three and six
months ended June 30, 2001.  The quarterly loss reflects $63 million (after tax), or 19(cent)per share, of SCE's
transition costs in excess of transition revenue during the second quarter of 2001. 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.  For financial reporting purposes, these undercollected costs are no longer
accumulated in the TCBA and instead are expensed as incurred.  A one-time charge of 36(cent)per share at Edison
Enterprises to reflect the decision to sell two wholly owned subsidiaries is also included in Edison
International's quarterly and year-to-date losses.  Excluding SCE's undercollected transition costs (19(cent)and $2.22
per share, respectively), and the charge at Edison Enterprises, Edison International earned 24(cent)and 37(cent)per share
for the three and six months ended June 30, 2001, respectively, compared to 41(cent)and 73(cent)per share for the
year-earlier periods.  Excluding the undercollected transition costs, SCE's earnings were 28(cent)and 47(cent)per share,
respectively, compared with 47(cent)and 80(cent)per share for the same periods last year.  The quarterly and year-to-date
decreases for SCE were primarily due to lower earnings resulting from the February 2001 fire and resulting outage
at the San Onofre Nuclear Generating Station (see further discussion of the San Onofre fire in the San Onofre
Nuclear Generating Station section) and higher interest expense resulting from SCE's deteriorated financial
condition, as well as lower kWh sales.  Edison Mission Energy (EME) earned less than 1(cent)and 3(cent)per share in the
three- and six-month periods ended June 30, 2001, respectively, compared to losses of 6(cent)and 9(cent)per share for the
prior-year periods.  The increased earnings reflect higher energy prices for EME's domestic projects and
increased earnings from oil and gas activities, partially offset by lower pool prices in the United Kingdom.
Edison Capital's earnings were 8(cent)and 11(cent)per share, compared with 12(cent)and 23(cent)per share for the year-earlier
periods.  The decreases were primarily due to lower earnings from leveraged lease transactions and affordable
housing portfolios, partially offset by a net gain on asset sale.  Edison Enterprises and Edison International
(parent company) incurred losses of 48(cent)and 60(cent)per share, respectively, compared to losses of 12(cent)and 21(cent)per
share for the comparable periods in 2000.  The increased losses in 2001 were primarily due to 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 36(cent)one-time adjustment, Edison Enterprises and the parent company's second quarter earnings were
unchanged from the prior year due to improved operating performance at Edison Enterprises, partially offset by
higher interest expense at the parent company.  Excluding the one-time adjustment, the decrease at Edison
Enterprises and the parent company for year-to-date June 30, 2001, was mainly the result of higher interest
expense in 2001 and a first quarter 2000 gain on the sale of marketable securities at Edison International's
insurance subsidiary, partially offset by improved operating performance at Edison Enterprises in 2001.

If and when regulatory and legislative actions are taken that make recovery probable, the regulatory assets
written off as of December 31, 2000, and the undercollected costs incurred in 2001, would be restored to the
balance sheet, with a corresponding increase to earnings of approximately $3.2 billion (after tax).

Unless a rate-making mechanism is implemented in accordance with the MOU described above or other necessary
rate-making action is taken, future net undercollections of transition costs will be charged to earnings as the
losses are incurred.  SCE anticipates that the losses resulting from these undercollections will continue unless
a rate-making mechanism is established.



Page 24




Operating Revenue

SCE's customers are able to choose to purchase power directly from an energy service provider, thus becoming
direct access customers, or continue to have SCE purchase power on their behalf.  Most direct access customers
are billed by SCE, but given a credit for the generation portion of their bills.  Under Assembly Bill 1 (First
Extraordinary Session, AB 1X), enacted on February 1, 2001, the CPUC was directed (on a schedule it determines)
to suspend the ability of retail customers to select alternative providers of electricity until the CDWR stops
buying power for retail customers.  The CPUC has not yet acted on this directive.

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 a reevaluation of the
operation of the interruptible programs can be completed.

Electric utility revenue decreased for the three and six months ended June 30, 2001, compared to the same periods
in 2000, primarily because SCE no longer supplies its customers with all of their electricity needs (since
mid-January 2001).  Electric utility revenue was reduced by $461 million and $718 million, respectively, for the
three and six months ended June 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 decreases were also the result of a 6% decrease in retail sales volume,
primarily the result of conservation efforts.  The effects of the 1(cent)-per-kWh and 3(cent)-per-kWh surcharges, as well
as the credit given to customers who chose direct access during second quarter 2000 partially offset the
quarterly decreases discussed above.  The direct access credits decreased during the second 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.  The year-to-date decrease was also due to 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.

More than 93% 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 June 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 Ownership Changes section), partially
offset by decreases at its Ferrybridge, Fiddler's Ferry and First Hydro plants.  The quarterly increase was also
partially offset by lower revenue from its Illinois plants.  The year-to-date increase also reflects an increase
in revenue from EME's Illinois plants in the first quarter of 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 are expected to contribute more to nonutility power generation revenue
during the winter months.

Financial services and other revenue increased for both the three and six months ended June 30, 2001, mostly due
to increases at two other Edison International's nonutility subsidiaries.  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



Page 25


providing these services.  The increases resulted from the selling of real estate and providing these operating
and maintenance services.  The year-to-date increase was partially offset by a decrease at Edison Capital related
to lower revenue from leverage lease transactions.

Operating Expenses

Fuel expense increased for both the three and six months ended June 30, 2001, compared to the prior-year periods,
primarily due to increases at EME resulting from its Doga plant and its increased ownership in Contact Energy.  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 increased significantly for the three and six months ended June 30, 2001, compared to the
same periods in 2000.  The increases were the result of increased purchased-power expense related to qualifying
facilities (QFs), bilateral contracts and interutility contracts.  The quarterly increase was partially offset by
the absence of purchases from the PX and ISO in 2001.  In December 2000, the FERC eliminated the requirement that
SCE buy and sell its purchased and generated 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.  The year-to-date
increase was also the result of increased PX/ISO purchased-power expense.  See Purchased Power table in Note 6 to
the Consolidated Financial Statements.  See further discussion in CDWR Power Purchases.

Prior to April 1998, SCE was required under federal law and CPUC orders 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.  Purchased-power expense related to QFs increased for the three and six
months ended June 30, 2001, compared to the year-earlier periods.  The increases were primarily due to the
short-run avoided cost factor (which is based on the price of natural gas) 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 increases 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.  Since May 2000, SCE's use of risk management
instruments tools minimally offset the increased volume of higher-priced PX purchases.

Provisions for regulatory adjustment clauses decreased for the six months ended June 30, 2001, compared to the
year-earlier period.  The decrease primarily resulted from SCE no longer accumulating undercollected transition
costs in the TCBA for financial reporting purposes, as well as undercollections related to the administration of
energy conservation programs and other public benefit programs in 2001.  For the six months ended June 30, 2000,
SCE recorded overcollections related to the generation-related balancing accounts.

Other operation and maintenance expense increased for the three and six months ended June 30, 2001, compared to
the same periods in 2000, primarily due to increased plant operating expenses at EME's Illinois plants and
increased expenses at a nonutility subsidiary related to the sale of real estate.

Depreciation, decommissioning and amortization expense decreased significantly for the three and six months ended
June 30, 2001, primarily due to a decrease in SCE's amortization expense.  Since SCE's December 31, 2000,
write-off included the unamortized nuclear investment regulatory asset, SCE has not recorded any amortization
expense related to this asset during the first six months of 2001.

The writedown 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.



Page 26


Other Income and Deductions

Interest and dividend income increased for the six months ended June 30, 2001, primarily due to increases at
Edison International and Edison Capital, resulting from higher cash balances as they conserve cash due to their
liquidity issues, and an increase at EME related to foreign exchange gains on intercompany loans.

Other nonoperating income decreased for both the three and six months ended June 30, 2001, compared to the
year-earlier periods.  The decreases were primarily due to SCE's second quarter 2000 gains on sales of equity
investments and the gain on sale of EME's 50% interest in a cogeneration project in Florida in second quarter
2000.  The year-to-date decrease was also due to lower CPUC-approved shareholder incentives at SCE resulting from
fewer QF contract restructurings and the gain on sale of an equity investment at Edison International's insurance
subsidiary in first quarter 2000.

Interest expense - net of amounts capitalized increased for both the three and six months ended June 30, 2001,
compared to the year-earlier periods, reflecting additional long-term debt at SCE and Edison Capital, 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.

Other nonoperating deductions decreased for both the quarter and year-to-date period ended June 30, 2001, due to
lower accruals at SCE for regulatory matters in 2001.

Income Taxes

Income taxes decreased for the three and six months ended June 30, 2001, compared to the year-earlier periods.
The decreases were the result of income tax benefits at SCE ($51 million for the second quarter 2001 and $548
million for the six months ended June 30, 2001) arising from the transition costs in excess of transition
revenue, as well as income tax benefits arising from the one-time charge at Edison Enterprises in second quarter
2001 to reflect the decision to sell two wholly owned subsidiaries.

Financial Condition

Edison International's liquidity is primarily affected by debt maturities, access to capital markets, dividend
payments, capital expenditures, 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 deteriorating financial condition (further discussed in Liquidity Issues), at June 30, 2001, the fair
market value of approximately $1.1 billion of Edison International's short-term debt was approximately 81% of its
carrying value and the fair market value of its long-term debt was approximately 94% of its carrying value.

Liquidity Issues

SCE
---

Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001.  This resulted in
increasing undercollections in the TRA and TCBA.  The increasing 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 continued regulatory uncertainty regarding SCE's
ability to recover its current and future power procurement costs, have 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
temporarily suspended payments of certain obligations for principal and interest on outstanding debt and for
purchased power.  As of July 31, 2001, SCE had $3.3 billion in obligations that were unpaid and overdue
including: (1) $878 million to the PX or ISO; (2) $1.2 billion to QFs; (3) $230 million in PX energy credits for



Page 27



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.  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 the 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.  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 CDWR or the ISO for sale to
SCE's customers on or after January 18, 2001, SCE's unpaid obligations as of July 31, 2001, could increase by as
much as $1.9 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 agreed to forbear 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.  SCE's $200
million short-term bank credit facility's maturity date has been extended to September 15, 2001, under a
forbearance agreement that has been extended three times and currently expires on the same day.  SCE has $400
million in bilateral credit agreements that expire in late September 2001.  SCE has not entered into forbearance
agreements with the lenders under the bilateral credit agreements.  At July 31, 2001, SCE had estimated cash
reserves of approximately $1.7 billion (after deducting $419 million of designated funds), which was
approximately $1.6 billion less than its outstanding unpaid obligations (discussed above) and overdue amounts of
preferred stock dividends (see below).  As of March 31, 2001, SCE resumed payment of interest on its debt
obligations.  If the MOU is implemented, it is expected to allow SCE to recover its undercollected costs and to
help restore SCE's creditworthiness, which would allow SCE to pay all of its past due obligations.

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 and 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.

Based on these decisions, the uncertainty about the amount of revenue the CDWR will require to pay its bond and
energy procurement costs, and how much of this revenue requirement will be allocated to SCE (see CDWR Power
Purchases), SCE estimates that future cash may not be sufficient to cover retained generation, purchased-power
and transition costs.  In comments filed with the CPUC in March and April 2001, SCE provided a forecast showing
that the net effects of the rate increase, the payment ordered to be made to the CDWR, and the QF decision could
result in a shortfall to the CPA calculation during 2001.  To implement the MOU, it will be necessary for the
CPUC to modify or rescind these decisions.

In light of SCE's liquidity crisis, its Board of Directors did not declare quarterly common stock dividends to
SCE's parent, Edison International, in December 2000, March 2001 or June 2001 and Edison International's Board of




Page28



Directors did not declare 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 July 31,
2001, SCE's preferred stock dividends in arrears were $11 million.  As a result of SCE's $2.5 billion charge to
earnings as of December 31, 2000, SCE's retained earnings are now in a deficit position and therefore under
California law, SCE will be unable to pay dividends as long as a deficit remains, unless SCE meets certain
conditions under which dividends can be paid from sources other than retained earnings.  SCE does not meet these
conditions.  As long as accumulated dividends on SCE's preferred stock remain unpaid, SCE cannot pay any
dividends on its common stock.

SCE has implemented cost-cutting measures which, together with previously announced actions, such as freezing new
hires, postponing certain capital expenditures and ceasing new charitable contributions, are aimed at reducing
general operating costs.  SCE's current cost-cutting measures are intended to allow it to continue to operate
while efforts to reach a regulatory solution, involving both state and federal authorities, are underway.
Additional actions by SCE may be necessary if the energy and liquidity crisis is not resolved in the near
future.  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 an agreement to resolve SCE's crisis, see Memorandum of Understanding
with the CDWR.

SCE's future liquidity depends, in large part, on whether action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow deficit created by the current rate
structure and the volatility in the price of wholesale electricity and natural gas.  Without a change in
circumstances, resolution of SCE's liquidity crisis and its ability to continue to operate outside of bankruptcy
is uncertain.

EME
---

EME has three corporate credit facilities (totaling $1.2 billion) that are scheduled to expire on October 10,
2001.  As of July 31, 2001, EME had borrowed or issued letters of credit aggregating $1.2 billion under these
credit facilities and had an unused capacity of approximately $17 million.  Under these lines of credit, EME must
reduce the outstanding commitments to $1 billion by August 15, 2001.  On August 10, 2001, EME completed a $400
million private placement of senior notes, the net proceeds of which were sufficient to meet this commitment.
EME plans to replace the corporate credit facilities with a new credit facility with a short-term (1 year)
component and an intermediate term (3 years) component.  EME's corporate cash requirements in 2001 are expected
to exceed cash distributions from its subsidiaries.  EME's corporate cash requirements for the remainder of 2001
include:  debt service under its senior notes and intercompany notes resulting from sale-leaseback transactions
which total $123 million; equity and capital requirements for projects in development and under construction of
$67 million; dividends payable to Mission Energy Holding Company of $65 million; a tax-sharing payment to the
parent company of $51 million; and general and administrative expenses.

In addition, to provide additional liquidity, EME may sell its interest in individual projects in its project
portfolio.  Under one of EME's credit facilities, EME is required to use 50% of the net proceeds from the sale of
assets and 100% of the net proceeds from the issuance of capital markets debt to repay senior bank indebtedness
until the aggregate commitment amount under the corporate facilities is reduced to $850 million.  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.  EME expects the proceeds of the sales of its interests in such
projects, if completed, to exceed their aggregate book value.  EME is also considering sale-leaseback
transactions of certain projects, the proceeds of which would be used to repay short-term indebtedness or to meet
other capital requirements.

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).




Page 29



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.  EME cannot provide assurance that its 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.

As a result of the change in the prices of power in the UK, EME is offering the Ferrybridge and Fiddler's Ferry
power plants for sale through a competitive bidding process.  A decision has not been made regarding whether or
not the sale of these plants will ultimately occur and, accordingly, these assets are not classified as held for
sale.  However, if a decision to sell the Ferrybridge and Fiddler's Ferry plants were made, it is likely that EME
will not recover any of its investment in the subsidiary that owns these assets.  At June 30, 2001, EME's net
investment in the Ferrybridge and Fiddler's Ferry power plants was $974 million.  EME plans to use the proceeds
from the sale, if it occurs, to repay a portion or all of the indebtedness of the project. EME cannot provide
assurance that acceptable bids will be obtained or, if such bids are acceptable, that completion of the sale will
occur. In this regard, EME also cannot provide assurance that it will be able to negotiate acceptable terms and
conditions with a potential buyer or that if an agreement was reached, that EME will be able to satisfy the
conditions needed for closing, which will include, among other things, a regulatory review in the UK.

Edison Capital
--------------

As of June 30, 2001, Edison Capital was fully drawn on its $300 million bank facility, which originally matured
on June 30, 2001, but was extended until July 31, 2001.  In July 2001, Edison Capital's bank facility of $150
million was extended until June 30, 2002.  The remaining $150 million bank facility was paid off and not
renewed.  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.

Edison International
--------------------

In order to reduce current 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



Page 30



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.  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 its $570 million loss in the
first six 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 $719 million loss Edison International incurred for the six months ended June 30, 2001, net cash
provided by operating activities was $937 million, primarily due to SCE temporarily suspending payments for
interest on outstanding debt and for purchased power beginning in January 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).

SCE's estimates of cash available for operations in 2001 assume, among other things, satisfactory reimbursement
of costs incurred during California's energy crisis, the receipt of adequate and timely rate relief, and the
realization of its assumptions regarding cost increases, including the cost of capital.

Estimated noncancelable lease payments for the next five years are:  2001 - $189 million; 2002 - $213 million;
2003 - $212 million; 2004 - $233 million; and 2005 - $271 million.

Cash Flows from Financing Activities

At June 30, 2001, Edison International and its subsidiaries had $16 million of borrowing capacity available under
lines of credit totaling $3.8 billion.  The parent company, SCE and Edison Capital have drawn on their entire
lines of credit.  EME had total lines of credit of $1.2 billion, with $16 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.  Both the parent company and SCE had successfully negotiated with
bank lenders to extend their 364-day credit facilities (until June 30, 2001, for the parent company's $618
million facility and until September 15, 2001, for SCE's $200 million facility).  SCE also has $400 million
bilateral credit agreements that expire in late September 2001.  SCE's remaining $1.05 billion in credit
facilities is due to expire in May 2002.  On July 2, 2001, Mission Energy Holding issued $800 million of 13.50%
senior secured notes due 2008 and entered into an agreement for a $385 million senior secured term loan.
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 and a
portion of $250 million of senior unsecured notes maturing July 18, 2001; the bank credit facility has not been
renewed.




Page 31



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 current liquidity and credit problems, SCE is 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, 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.

Subject to the outcome of regulatory, legislative and judicial proceedings, including steps to implement the MOU,
SCE intends to pay all of its obligations.

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 has adopted certain amendments to its articles of incorporation and bylaws.  The provisions include 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



Page 32



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.

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 $1 million and $8 million for asset purchases, as well as $123 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 $42 million, primarily for equity support
guarantees related to the Paiton project in Indonesia and the ISAB project in Italy.  EME has capital commitments
of $986 million related to the turbine lease agreement and $250 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 has deferred 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.  At June 30, 2001, EME's share of accounts receivable due from SCE was $301 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 had filed lawsuits against SCE, they have now entered into settlement 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
utilities' suspension of payments.  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 July 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.

On July 2, 2001, EME redeemed NZ$400 million of retail redeemable preference shares at their issuance price.
Funding for the redemption of the shares was provided by a NZ$400 million credit facility scheduled to mature in
July 2005.

Edison Capital has firm commitments of $149 million to fund affordable housing, and energy and infrastructure
investments.  At June 30,  2001, as a result of Edison Capital's financial condition, it has deposited
approximately $11 million as collateral for its commitments.

Long-term debt maturities and sinking fund requirements for the five twelve month periods following June 30,
2001, are: 2002 - $2.7 billion; 2003 - $815 million; 2004 - $1.7 billion; 2005 - $3.1 billion; and 2006 - $941
million.  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 June 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




Page 33



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 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 $71 million for the six-month period ended
June 30, 2001, compared to $417 million for the same period in 2000.  The decrease was primarily the result of
Edison Capital's termination of its investment in a UK power project in January 2001, partially offset by an
increase at EME related to equity contributions made during the first six months of 2001 to meet capital calls by
partnerships who own QFs (see further discussion in Cash Flows from Financing Activities).

Edison International's projected construction expenditures for 2001 are $818 million.  This projection reflects
SCE's cost-cutting measures discussed above in the Liquidity Issues section.

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 have 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, but these caps are set at high levels and are
not entirely effective (see further discussion in Wholesale Electricity Markets).

SCE attempted to hedge a portion of its exposure to increases in power prices.  However, the CPUC has approved a
very limited amount of hedging.  In November 2000, SCE began purchases of energy through bilateral forward
contracts.  At June 30, 2001, the nominal value of SCE's bilateral forward contracts was $419 million.





Page 34



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 temporarily 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.  If the MOU is implemented, SCE will relinquish all claims against the state for
seizing these contracts.  If the MOU is not implemented, SCE believes that it should be compensated for the
reasonable value of these contracts under law, and would pursue the matter.  Edison International's June 30,
2001, balance sheet no longer includes 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

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

EME is exposed to changes in interest rates because they 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 agreement related to the coal 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.




Page 35



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 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 3-1/2 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, Loy Yang B entered into a number of fixed
forward electricity contracts commencing either in 2001 or 2002, which expire on various dates through December
2002, and which will further mitigate the price volatility of the electricity pool.




Page 36




The New Zealand government has been undergoing a steady process of electric industry deregulation since 1987.
Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity
distribution and provided for competition in the retail electric supply function.  The New Zealand Energy Market,
established in 1996, is a voluntary competitive wholesale market that allows for the trading of physical
electricity on a half-hourly basis.  The Electricity Industry Reform Act, which was passed in July 1998, was
designed to increase competition at the wholesale generation level by splitting up Electricity Company of New
Zealand Limited, the large state-owned generator, into three separate generation companies.  The Electricity
Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity.

The New Zealand government commissioned an inquiry into the electricity industry in February 2000.  This Inquiry
Board's report was presented to the government in mid-2000.  The main focus of the report was on the monopoly
segments of the industry, transmission and distribution, with substantial limitations being recommended in the
way in which these segments price their services in order to limit their monopoly power.  Recommendations were
also made with respect to the retail customer in order to reduce barriers to customers switching.  In addition,
the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of
streamlining them.  The recommended changes are now being progressively implemented.

Foreign currencies in the UK, Australia and New Zealand decreased in value compared to the US dollar by 6%, 8%
and 9%, respectively (determined by the change in the exchange rates from December 31, 2000, to June 30, 2001).
The decrease in value of these currencies was the primary reason for EME's foreign currency translation loss of
$101 million during the first six months of 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 June 30, 2001, the outstanding notional amount of the contracts was $73 million, consisting of
contracts to exchange US dollars to pound sterling with varying maturities ranging from July 2001 to July 2002.
During the second quarter of 2001, EME recognized a foreign exchange gain (less than $100,000) related to the
fuel purchases underlying the contracts that matured in April, May and June 2001.  EME will continue to monitor
its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.

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 and fluctuations in foreign currency exchange rates can have a significant 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.




Page 37



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.

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

Edison Capital has entered into foreign currency contracts to reduce the potential impact of changes in foreign
exchange rates and future foreign currency denominated cash flows.  At June 30, 2001, the outstanding notional
amount of the remaining contract was approximately $4 million, consisting of one contract to exchange US dollars
to pounds sterling.  This contract was settled in July 2001.

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 is subject to
interest rate risk and that the fair market value of its fixed rate long-term debt is subject to interest rate
risk.

Paiton Project

A wholly owned subsidiary of EME (Paiton Energy) owns a 40% interest and has a $503 million investment (at June
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 have signed an agreement
providing for an extension of the Phase I Agreement from July 1, 2001, to September 30, 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 June 30,
2001, while negotiations regarding the long-term restructuring of the tariff 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.




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Acquisitions and Dispositions

EME

On June 29, 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 ($3 million after tax).

On June 25, 2001, EME completed the sale of a 50% interest in the Sunrise project.  Proceeds from the sale were
$84 million.  Commercial operation commenced on June 27, 2001.

During the second quarter of 2001, EME completed the purchase of an additional shares of Contact Energy Ltd. for
approximately NZ$152 million.  EME now has a controlling 51.2% ownership interest in Contact Energy.

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 some 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.

On June 7, 2001, another Edison Enterprises subsidiary (engaged in the business of integrated energy outsourcing)
entered into a letter of intent to sell substantially all of its assets to its current management.  The sale is
anticipated to be completed in late 2001.

Edison International recorded a charge of $117 million (after-tax) in second quarter 2001 to reduce the carrying
value of its investments in the businesses held for sale based on estimated proceeds from the sales.

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 1996, 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 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 surcharges effective first
quarter 2001) are 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 have escalated far beyond what SCE can currently charge its
customers.  See further discussion in Wholesale Electricity Markets.




Page 39



Generation and Power Procurement

During the rate freeze, revenue from generation-related operations has been determined through the market and
transition cost recovery mechanisms, which included the nuclear rate-making agreements.  The portion of revenue
related to coal generation plant costs (Mohave Generating Station and Four Corners Generating Station) that was
made uneconomic by electric industry restructuring was eligible for recovery through the transition cost recovery
mechanisms.  After April 1, 1998, coal generation operating costs have been recovered through the market.  The
excess of power sales revenue from the coal generating plants over the plants' operating costs has been
accumulated in a coal generation balancing account.  SCE's costs associated with its hydroelectric plants have
been recovered through a performance-based mechanism.  The mechanism set the hydroelectric revenue requirement
and established a formula for extending it through the duration of the electric industry restructuring transition
period, or until market valuation of the hydroelectric facilities, whichever occurred first.  The mechanism
provided that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue
requirement is accumulated in a hydroelectric balancing account.  In accordance with a CPUC decision issued in
1997, the credit balances in the coal and hydroelectric balancing accounts were transferred to the TCBA at the
end of 1998 and 1999.  However, due to the CPUC's March 27, 2001, rate stabilization decision, the credit
balances in these balancing accounts were transferred to the TRA on a monthly basis, retroactive to January 1,
1998.  In addition, the TRA balance, whether over- or undercollected, was transferred to the TCBA on a monthly
basis, retroactive to January 1, 1998.  Due to a December 2000 FERC order, SCE is no longer required to buy and
sell power exclusively through the ISO and PX.  In mid-January 2001, the PX suspended SCE's trading privileges
for failure to post collateral due to SCE's rating agency downgrades.  As a result, power from SCE's coal and
hydroelectric plants is no longer being sold through the market and these two balancing accounts have become
inactive.  As a key element of the MOU, SCE would continue to own its generation assets, which would be subject
to cost-based ratemaking, through 2010.  The MOU calls for the CPUC to adopt cost recovery mechanisms consistent
with SCE obtaining and maintaining an investment grade credit rating.

SCE has 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 are earning an annual rate of return on investment
of 7.35%.  In addition, 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 commenced in April 1996, and ends at the earlier of December 2001 or the date when
the statutory rate freeze ends for the accelerated recovery portion, and 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, are subject to balancing account treatment.
The Palo Verde plan commenced in January 1997 and ends in December 2001.  On May 4, 2001, SCE requested the CPUC
to extend the Palo Verde plan through December 2002.  The CPUC has not yet ruled on this request.  The benefits
of operation of the San Onofre units and the Palo Verde units are required to be shared equally with ratepayers
beginning in 2004 and 2002, respectively.  On May 4, 2001, SCE requested that the post-2003 and post-2001 benefit
sharing provisions of the current San Onofre and Palo Verde rate-making mechanisms be eliminated contingent upon
implementation of the MOU.  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 and not contingent upon
implementation of the MOU.  The CPUC has not yet ruled on SCE's similar request regarding Palo Verde.  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 will continue for rate-making purposes at least through the end of the
rate freeze period.  However, due to the various unresolved regulatory and legislative issues (as discussed in
Status of Transition and Power-Procurement Cost Recovery), SCE is no longer able to conclude that the unamortized
nuclear investment regulatory assets (as discussed in Accounting for Generation-Related Assets and Power
Procurement Costs) are probable of recovery through the rate-making process.  As a result, these balances were
written off as a charge to earnings as of December 31, 2000 (see further discussion in Earnings).

In 1999, SCE filed an application with the CPUC establishing a market value for its hydroelectric
generation-related assets at approximately $1.0 billion (almost twice the assets' book value) and proposing to




Page 40



retain and operate the hydroelectric assets under a performance-based, revenue-sharing mechanism.  If approved by
the CPUC, SCE would be allowed to recover an authorized, inflation-indexed operations and maintenance allowance,
as well as a reasonable return on capital investment.  A revenue-sharing arrangement would be activated if
revenue from the sale of hydroelectricity exceeds or falls short of the authorized revenue requirement.  SCE
would then refund 90% of the excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers.  If
the MOU is implemented, SCE's hydroelectric assets will be retained through 2010 under cost-based rates, or they
may be sold to the state if a sale of SCE's transmission assets is not completed under certain circumstances.  In
June 2000, SCE credited the TCBA with the estimated excess of market value over book value of its hydroelectric
generation assets and simultaneously recorded the same amount in the generation asset balancing account (GABA),
in accordance with a CPUC decision.  This balance was to remain in GABA until final market valuation of the
hydroelectric assets.  If there were a difference in the final market value, it would have been credited to or
recovered from customers through the TCBA.  Due to the various unresolved regulatory and legislative issues (as
discussed in Status of Transition and Power-Procurement Cost Recovery), the GABA transaction was reclassified
back to the TCBA, and as discussed in the Earnings section, the TCBA balance (as recalculated based on a March
27, 2001, CPUC interim decision discussed in Rate Stabilization Proceedings) was written off as of December 31,
2000.

During 2000, SCE entered into agreements to sell its interest in the Mohave, Palo Verde and Four Corners
generation stations.  The sales were pending various regulatory approvals.  Due to the shortage of electricity in
California and the increasing wholesale costs, state legislation was enacted in January 2001 barring the sale of
utility generation stations until 2006.  Under the MOU, SCE would continue to retain its generation assets
through 2010.

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.  On February 1, 2001, 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 revenue bonds to finance electricity purchases.  On May 10, 2001, the Governor
signed a bill authorizing the CDWR to issue up to $13.4 billion in bonds.  The law became effective August 8,
2001.  AB 1X directed the CPUC to determine the amount of the CPA as a residual amount of SCE's
generation-related revenue, after deducting the cost of SCE-owned generation, QF contracts, existing bilateral
contracts and ancillary services.  AB 1X also directed the CPUC to determine the amount of the CPA that is
allocable to the power sold by the CDWR, which will be payable to the CDWR when received by SCE.  On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's purchases are not subject to prudency
review by the CPUC, and that the CPUC must approve and impose, either as a part of existing rates or as
additional rates, rates sufficient to enable the CDWR to recover its revenue requirements.

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 July 23, 2001, the CDWR submitted a proposed $13.1 billion revenue requirement to the CPUC (revised to $12.6
billion on August 7, 2001) to pay its bonds' costs and energy procurement costs for 2001 and 2002.  In comments




Page 41



filed with the CPUC on August 3, 2001, SCE indicated that based on the CDWR methodology, SCE's share of the $13.1
billion revenue requirement would be approximately $5.8 billion, which would require SCE to increase its current
payment to the CDWR from 10.277(cent)per kWh to 15.9(cent)per kWh.  SCE requested that the CPUC refrain from adopting a
final revenue requirement until all parties receive information that is essential to understanding how the
revenue requirement was calculated and its relationship to the utilities' revenue requirement.  SCE also
requested that the CPUC adopt fundamental principles, such as cost of service, to guide its view of the CDWR
revenue requirement.  The CPUC will allow parties to file supplemental comments on the CDWR's revised revenue
requirement on August 14, 2001.  To take actions that will make SCE creditworthy, the CPUC will need to provide
reasonable assurance that SCE will be able to recover its ongoing costs, including the costs associated with the
CDWR's revenue requirement.

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 is only purchasing 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, takes 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 CDWR or ISO for sale to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs (and pre-tax loss) for the six months ended June 30, 2001, could increase by as much as
$1.9 billion (which includes bills received for January through May 2001, and an estimate for June 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.  On April 6, 2001,
the FERC issued an order confirming its February 14, 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.
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, the day after the Governor signed the order authorizing the CDWR to begin purchasing
power for utility customers.  SCE cannot predict the outcome of any of these proceedings or issues.  The MOU
states that the CDWR will assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the extent those needs are not met by
generation sources owned by or under contract to SCE (SCE's net short position).  Under the MOU, SCE will resume
buying power for its net short position after 2002.  The MOU calls for the CPUC to adopt cost-recovery mechanisms
to make it financially practicable for SCE to reassume this responsibility.

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.  Most of the remaining transition costs may be recovered through the end of the transition period (not
later than March 31, 2002).  Although the MOU provides for, among other things, SCE to be entitled to sufficient
revenue to cover its costs associated with retained generation and existing power contracts since January 2001,
the implementation of the MOU requires the CPUC to modify various decisions (discussed in Rate Stabilization
Proceedings).  Until regulatory and legislative actions that make such recovery probable are taken, SCE is 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 net regulatory assets related to certain generating assets are
probable of recovery through the rate-making process.  As a result, these balances were written off as a charge
to earnings as of December 31, 2000 (see further discussion in Earnings).




Page 42



During the rate freeze period, there are three sources of revenue available to SCE for transition cost recovery:
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 sale or valuation of generation assets in excess of book values (state legislation enacted in
January 2001 prohibits the sale of SCE's remaining generation assets until 2006) and from the sale of
SCE-controlled generation into the ISO and PX markets (see discussion in Generation and Power Procurement) is no
longer available to SCE.  Net proceeds of the 1998 plant sales were used to reduce transition costs, which
otherwise were expected to be collected through the TCBA mechanism.

Net market revenue from sales of power and capacity from SCE-controlled generation sources was also applied to
transition cost recovery.  Increases in market prices for electricity affected SCE in two fundamental ways prior
to the CPUC's March 27, 2001, rate stabilization decision.  First, CTC revenue decreased because there was less
or no residual revenue from frozen rates due to higher cost PX and ISO power purchases.  Second, transition costs
decreased because there was increased net market revenue due to sales from SCE-controlled generation sources to
the PX at higher prices (accumulated as an overcollection in the coal and hydroelectric balancing accounts).
Although the second effect mitigated the first to some extent, the overall impact on transition cost recovery was
negative because SCE purchased more power than it sold to the PX.  In addition, higher market prices for
electricity adversely affected SCE's ability to recover non-transition costs during the rate freeze period.

As discussed in the Status of Transition and Power-Procurement Cost Recovery section in Note 2 to the
Consolidated Financial Statements, CTC revenue is determined residually, the CTC applies to all customers who are
using or begin using utility services on or after the CPUC's 1995 restructuring decision date, and residual CTC
revenue is calculated through the TRA mechanism.  Under CPUC decisions in existence prior to March 27, 2001,
positive residual CTC revenue (TRA overcollections) was transferred to the TCBA monthly; TRA undercollections
were to remain in the TRA until they were offset by overcollections, or the rate freeze ended, whichever came
first.  Between May 2000 and June 2001, market prices for electricity have been extremely high and there was
insufficient revenue from customers under the frozen rates to cover all costs of providing service during that
period, and therefore there was no positive residual CTC revenue transferred into the TCBA.  In accordance with
the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue is transferred
to the TCBA on a monthly basis, retroactive to January 1, 1998 (see further discussion in Rate Stabilization
Proceedings).

Recalculating the TCBA balance based on the March 2001 decision resulted in positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover SCE's transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000.  Between May 2000 and January 18, 2001 (when the CDWR began making power purchases
for SCE's customers), SCE's costs to provide power exceeded revenue from frozen rates.  Even though SCE is no
longer supplying its customers with all of their electricity needs, SCE's total transition costs have continued
to exceed revenue from frozen rates.  As a result, the cumulative positive residual CTC revenue flowing into the
TCBA mechanism has been reduced from $4.7 billion to $2.7 billion as of June 30, 2001.  The cumulative TCBA
undercollection (as recalculated) was $2.9 billion as of December 31, 2000, and $4.2 billion as of June 30,
2001.  A summary of the components of this cumulative undercollection as of June 30, 2001, is as follows:

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

     Transition costs recorded in the TCBA:
         QF and interutility costs                                                     $  5,590
         Amortization of nuclear-related regulatory assets                                3,561
         Depreciation of plant assets                                                       656
         Other transition costs                                                             760
-----------------------------------------------------------------------------------------------------

         Total costs                                                                     10,567
     Revenue available to recover transition costs                                       (6,331)
-----------------------------------------------------------------------------------------------------

         TCBA undercollections                                                         $  4,236
-----------------------------------------------------------------------------------------------------


Unless the regulatory and legislative actions that make such recovery probable are taken, SCE is unable to
conclude that the recalculated TCBA net undercollection is probable of recovery through the rate-making process.




Page 43



As a result, the $2.9 billion TCBA net undercollection was written off as a charge to earnings as of December 31,
2000 (see further discussion in Earnings), and an additional $1.4 billion in TCBA undercollections was charged to
earnings for the six months ended June 30, 2001.  In its interim rate stabilization decision of March 27, 2001,
the CPUC denied SCE's motion to end the rate freeze, and stated that it will not end until recovery of all
specified transition costs (including TCBA undercollections as recalculated) or March 31, 2002.  For more details
on the matters discussed above, see Rate Stabilization Proceedings.

Litigation
----------

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.  The effect of such a ruling would be to overturn the prior decisions of the CPUC restricting recovery
of TRA undercollections.  In January 2001, the court denied the CPUC's motion to dismiss the action and also
denied SCE's motion for summary judgment without prejudice.  In February 2001, the court denied SCE's motion for
a preliminary injunction ordering the CPUC to institute rates sufficient to enable SCE to recover its past
procurement costs, subject to refund.  The court granted, in part, SCE's additional motion to specify certain
material facts without substantial controversy, but denied the remainder of the motion and declined to declare at
that time that SCE is entitled to recover the amount of its undercollected procurement costs.  In March 2001, the
court directed the parties to be prepared for trial on July 31, 2001.  Per mutual agreement of the parties, a
stay has been issued while SCE is attempting to further the MOU implementation process with the CPUC.  As
discussed in the Memorandum of Understanding with the CDWR, if the other elements of the MOU are implemented, SCE
will enter into a settlement of or dismiss its lawsuit against the CPUC seeking recovery of past undercollected
costs.  The settlement or dismissal will include related claims against California or any of its agencies, or
against the federal government.  SCE cannot predict whether or when a favorable final judgment or other
resolution would be obtained in this legal action if it were to proceed to trial.

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 (discussed below).  A
consolidated class action complaint was filed on August 3, 2001.  SCE and Edison International have until
September 17, 2001, to respond to the consolidated complaint.  SCE believes that its current and past accounting
for the TRA undercollections and related items, as described above, is appropriate and in accordance with
accounting principles generally accepted in the United States.

On March 15, 2001, a purported class action lawsuit was filed in federal district court in Los Angeles against
Edison International and SCE and certain of their officers.  The complaint alleges that the 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 the defendants allegedly over-reported income and improperly
accounted for the TRA undercollections.  The complaint is supposedly filed on behalf of a class of persons who
purchased all publicly traded securities of Edison International between May 12, 2000, and December 22, 2000.  In
accordance with an agreement with Edison International and SCE, the court has allowed the consolidation of this
lawsuit with the October 20, 2000, lawsuit discussed above.

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 more than $833 million for energy and capacity
supplied to SCE under QF contracts, and in some cases 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 largely been coordinated before a single trial judge.  SCE has reached
agreements with QFs representing about 95% of the QF renewable and cogeneration energy provided to SCE.  The
agreements provide for stays of litigation, payments to the QFs upon occurrence of specified conditions,



Page 44



modifications in some cases to the contract prices going forward, releases and dismissals of the litigation upon
payment by SCE.

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
current rate freeze ends 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.  SCE's plan included a trigger mechanism allowing for rate
increases of 5% every six months if SCE's TRA undercollection balance exceeds $1 billion.

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 covers, 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.  On April 3, 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 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.  The MOU calls for the CPUC to adopt
a decision clarifying that the first priority condition in SCE's 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.  SCE cannot provide assurance that the CPUC will adopt such a decision, or
predict what effects any investigation or any subsequent actions by the CPUC may have on SCE.

On March 27, 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.  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 on June 3, 2001.  The CPUC also
ordered that the 3(cent)-surcharge be added to the rate paid to the CDWR (see CDWR Power Purchases).

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).  SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs in the TCBA.  However, the CPUC
characterized the accounting changes as merely reducing the prior residual CTC revenue recorded in the TCBA, thus
only affecting the amount of transition cost recovery achieved to date.  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
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



Page 45



balances remaining in the TCBA and consider how to address remaining balances in the ongoing proceedings.  If the
CPUC does not modify this decision in a manner acceptable to SCE, SCE intends to challenge this decision through
all appropriate means.

Although the CPUC has authorized a substantial rate increase in its March 2001 order, it has allocated the
revenue from the increase entirely to future purchased-power costs without addressing SCE's past undercollections
for the costs of purchased power.  The CPUC's decisions do not assure that SCE will be able to meet its ongoing
obligations or repay past due obligations.  By ordering immediate payments to the CDWR and QFs, the CPUC impacted
SCE's future cash flow and liquidity problems.  Additionally, the CPUC stated that AB 1X continues the utilities'
obligations to serve their customers, and stated that it cannot assume that the CDWR will purchase all the
electricity needed above what the utilities either generate or have under contract (the net short position) and
cannot order the CDWR to do so.  This could result in additional purchased power costs with no allowed means of
recovery (see CDWR Power Purchases).  To take action that will restore SCE's creditworthiness, it will be
necessary for the CPUC to modify or rescind these decisions.  SCE cannot provide any assurance that the CPUC will
do so.

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.

Unless regulatory and legislative actions that make such recovery probable are taken, which would include
modifying or reversing recent CPUC decisions that impair recovery of SCE's power procurement and transition
costs, SCE cannot 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, are
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 as of
December 31, 2000 (see Earnings).

As discussed below, an MOU has been negotiated with representatives of the Governor as a step to resolving the
energy crisis.  If regulatory and legislative actions result in a rate-making mechanism that would make recovery
of these regulatory assets probable, the regulatory assets would be restored to the balance sheet, with a
corresponding increase to earnings.

Memorandum of Understanding with the CDWR
-----------------------------------------

On April 9, 2001, Edison International and SCE signed an MOU with the CDWR regarding the California energy crisis
and its effects on SCE.  The Governor of California and his representatives participated in the negotiation of
the MOU, and the Governor endorsed implementation of all the elements of the MOU.  The MOU sets forth a
comprehensive plan calling for state legislation and regulatory action and definitive agreements to resolve
important aspects of the energy crisis, and which, if implemented, is expected to help restore SCE's
creditworthiness and liquidity.  Key elements of the MOU include:

o    SCE will sell its transmission assets to the CDWR, or another authorized state agency, at a price equal to
     2.3 times their aggregate book value, or approximately $2.76 billion.  If a sale of the transmission assets
     is not completed under certain circumstances, SCE's hydroelectric assets and other rights may be sold to the
     state in their place.  SCE will use the proceeds of the sale in excess of book value to reduce its
     undercollected costs and retire outstanding debt incurred in financing those costs.  SCE will agree to
     operate and maintain the transmission assets for at least three years, for a fee to be negotiated.




Page 46



o    Two dedicated rate components will be established to assist SCE in recovering the net undercollected amount
     of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion.  The
     first dedicated rate component will be used to securitize the excess of the undercollected amount over the
     expected gain on sale of SCE's transmission assets, as well as certain other costs.  Such securitization
     will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of
     other conditions of the MOU.  The second dedicated rate component would not be securitized and would not
     appear in rates unless the transmission sale failed to close within a two-year period.  The second component
     is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be
     recovered through the gain on the transmission sale.

o    SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through
     2010.  SCE will be entitled to collect revenue sufficient to cover its costs from January 1, 2001,
     associated with the retained generation assets and existing power contracts.  The MOU calls for the CPUC to
     adopt cost recovery mechanisms consistent with SCE obtaining and maintaining an investment grade credit
     rating.

o    The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers
     within SCE's service territory through December 31, 2002, to the extent that those needs are not met by
     generation sources owned by or under contract to SCE.  (The unmet needs are referred to as SCE's net short
     position.)  SCE will resume procurement of its net short position after 2002.  The MOU calls for the CPUC to
     adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility.

o    SCE's authorized return on equity will not be reduced below its current level of 11.6% before December 31,
     2010.  Through the same date, a rate-making capital structure for SCE will not be established with different
     proportions of common equity or preferred equity to debt than set forth in current authorizations.  These
     measures are intended to enable SCE to achieve and maintain an investment-grade credit rating.

o    Edison International and SCE will commit to make capital investments in the utility of at least $3 billion
     through 2006, or a lesser amount approved by the CPUC.  The equity component of the investments will be
     funded from SCE's retained earnings or, if necessary, from equity investments by Edison International.

o    EME will execute a contract with the CDWR for the provision of power from a designated project to the state
     at cost-based rates for 10 years.  The Sunrise power project, which meets this obligation, began commercial
     operation on June 27, 2001.

o    SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with
     SCE's Big Creek and Eastern Sierra hydroelectric facilities.  The easements initially will be held by a trust
     for the benefit of the state, but ultimately may be assigned to nonprofit entities or certain governmental
     agencies.  SCE will be permitted to continue utility uses of the subject lands.

o    After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its
     federal district court lawsuit against the CPUC seeking recovery of past undercollected costs.  The
     settlement or dismissal will include related claims against the state or any of its agencies, or against the
     federal government.

The sale of SCE's transmission system and other elements of the MOU must be approved by the FERC.  Edison
International, SCE and the CDWR committed in the MOU to proceed in good faith to sponsor and support the required
state legislation and to negotiate in good faith the necessary definitive agreements.  The MOU may be terminated
by either SCE or the CDWR if required legislation is not adopted and definitive agreements executed by August 15,
2001, or if certain other adverse changes occur.  Since the required legislation will not be enacted, necessary
regulatory actions will not be taken, and definitive agreements will not be executed before the applicable
deadlines, the MOU will be terminable unless the parties choose to extend the deadlines.




Page 47



Since the execution of the MOU, SCE has made several filings with the CPUC addressing elements of the MOU.
Although the CPUC did not adopt the implementing decisions contemplated by the MOU within the projected timeframe
set out in the MOU, the CPUC continues to process SCE's filings.  However, SCE cannot assure that the necessary
implementing decisions will be passed, nor whether any decisions ultimately adopted will be acceptable to SCE.

Legislation to address the MOU and issues relating to SCE's creditworthiness has been introduced in both the
California State Senate and Assembly as part of the 2001-02 Second Extraordinary Session.

Senate Bill 78XX was introduced in May 2001.  As introduced, the bill would have implemented the MOU in its
entirety.  However, Senate Bill 78XX was significantly amended in July.  As amended, Senate Bill 78XX would allow
SCE to securitize a significant portion of the past procurement undercollections, but would not allow SCE to
recover from ratepayers unpaid PX and ISO costs aggregating approximately $1 billion, or interest accruing on the
past procurement undercollections after January 31, 2001 (estimated to be approximately $400 million by year end
2001).  The bill would provide the State of California with a five-year option to purchase SCE's transmission
system at book value, and contains provisions for conservation easements similar to the MOU.  SCE opposed Senate
Bill 78XX on the grounds that SCE did not believe that the bill would provide the elements necessary to return
SCE to investment grade credit status and it believed that other provisions of the bill were also objectionable.
Senate Bill 78XX was approved by the Senate on July 20, 2001, and was referred to the State Assembly.  The
leadership of the Assembly has indicated its intent to amend the bill.  If amended by the Assembly, the amended
bill would return to the State Senate for a concurrence vote (the Senate must accept the bill as passed by the
Assembly or the bill is rejected).  The bill would reach the Governor's desk only if agreed to by the Senate.  In
the alternative, the Senate and Assembly could agree to refer the bill to a Conference Committee.

The Assembly introduced two bills, Assembly Bill 82XX and Assembly Bill 50XX.  Assembly Bill 50XX would have
allowed for recovery of all but $300 million of SCE's past procurement-related debt with no sale of SCE's
transmission assets or grant of conservation easements.  SCE supported this bill as most likely to return SCE to
investment grade credit status.  However, Assembly Bill 50XX was not passed by the Assembly Appropriations
Committee.  Assembly Bill 82XX was approved by both the Assembly Policy and Appropriations Committees, and is
currently on the floor of the Assembly.  That bill would allow SCE to securitize all of its net past procurement
undercollection except for $500 million, and would authorize the sale of SCE's transmission assets.  In
committee, SCE was supportive of Assembly Bill 82XX, but advocated amendments.

The Legislature is in recess until August 20, 2001.  During the summer interim recess, a working group of certain
Assembly members has been formed to identify additional amendments to Assembly Bill 82XX and/or to propose
amendments to Senate Bill 78XX.  SCE continues to work with the authors of all the bills.  However, SCE cannot
assure that legislation will be passed, nor whether any such legislation will ultimately be acceptable to SCE or
would be signed by the Governor.

Utility Retained Generation
---------------------------

In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
ratemaking for utility retained generation through the end of 2002.  The 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.  SCE proposed a
fifth balancing account to track generation-related undercollections incurred before January 31, 2001.  Hearings
were held in July 2001.  A final decision is expected later in 2001.

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




Page 48




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 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.  On December 15, 2000, the FERC released a final order
containing remedies and other actions in response to the problems in the California electricity market.  The
order, among other things, eliminated the requirement for California utilities to buy and sell power exclusively
through the ISO and PX; created a benchmark price for wholesale bilateral power contracts; created penalties for
under-scheduling power loads; provided for an independent governing board for the ISO; and established a
breakpoint of $150/MWh so that bids below $150 may clear at a single market-clearing price at or below $150/MWh
and bids above $150 will be paid as bid.  On December 18, 2000, SCE filed with the FERC an emergency request for
rehearing of the December 15 order.  On January 12, 2001, the FERC issued an order granting rehearing for the
purpose of further consideration.  The PX did not immediately implement the $150/MWh breakpoint and on February
26, 2001, made a compliance filing with the FERC, which requested the FERC's guidance on an acceptable
recalculation methodology.

In December 2000, 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.  On January 5, 2001, the court denied
SCE's petition.  SCE's petition for rehearing remains pending.  SCE is considering the possibility of judicial
appeals and other actions.

In December 2000, the ISO announced that generators of electricity were refusing to sell into the California
market due to concerns about the financial stability of SCE and PG&E.  In response to this announcement, the
United States Secretary of Energy issued an order requiring power companies to make arrangements to generate and
deliver electricity as requested by the ISO after the ISO certifies that it has been unable to acquire adequate
supplies of electricity in the market.  After being renewed multiple times, the order expired on February 6,
2001.  However, on February 7, 2001, a federal court judge issued a temporary restraining order requiring power
suppliers to sell to the California grid.  On March 21, 2001, a federal court judge ordered one of the power
suppliers to continue to sell power to the California grid.  Three other power suppliers have signed an agreement
with the judge voluntarily agreeing to continue to sell power to the grid while awaiting a review of the issue by
the FERC.  On April 6, 2001, the United States Court of Appeals issued a stay order, suspending the lower court's
March 21 order until a final appeals ruling can be issued.

In December 2000, the FERC established a penalty applicable to scheduling coordinators that do not schedule
sufficient resources to supply 95% of their respective loads.  SCE has sought a suspension of the so-called
"underscheduling penalty."  SCE has also sought a rehearing of a FERC order, issued in May 2001, which rejected
the ISO's proposal for suspension of the underscheduling penalty.  In the May 2001 order, the FERC also indicated
that it will make a determination regarding the suspension of the underscheduling penalty in a future order on a
complaint filed by SCE and PG&E that asked the FERC to eliminate the penalty.  As of July 2001, the statewide
accumulated penalties were estimated by the ISO to be approximately $1 billion.  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, 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




Page 49



costs of the least efficient generating unit during the period.  The new approach replaces the $150/MWh
breakpoint discussed above.

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 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.  A prehearing conference
is scheduled for August 13, 2001.

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 44 identified sites is $116 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
$272 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 $46 million of its
recorded liability, through an incentive mechanism, which is discussed in Note 4.  SCE has recorded a regulatory
asset of $75 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.  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 $20 million.  Recorded costs for the
twelve months ended June 30, 2001, were $19 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




Page 50



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.

Edison International's projected environmental capital expenditures are $1.7 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.  On June 1, 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 resulting outage.

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 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 or 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 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.

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




Page 51



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 June 30, 2001, SCE did not have any derivatives as
defined by the new accounting 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).

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 implementation (or
non-implementation) of the MOU as described above; 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, including the possible filing of an involuntary bankruptcy petition against SCE; 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;
changes in prices of electricity and fuel costs; the actions of securities rating agencies; 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 52



PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

Edison International

                                         Geothermal Generators' Litigation

As previously reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K for the fiscal year
ended December 31, 2000 (2000 Form 10-K), Edison International and two of its non-utility subsidiaries have been
involved in litigation with an independent power producer and six of its affiliated entities.  On June 13, 2001,
all claims in this matter were dismissed with prejudice, based upon a settlement and CPUC approval of the
settlement.  This matter is described more fully under Southern California Edison Company - Geothermal
Generators' Litigation.

                                              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-Q for the quarterly period ending June 30, 2001 (First 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 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, 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

                                         Geothermal Generators' Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, SCE has been involved in
litigation with an independent power producer and six of its affiliated entities.

Effective February 8, 2000, the parties entered into confidential agreements resolving all claims in the
consolidated action and calling for dismissals with prejudice and releases subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings during the period required to
obtain CPUC approval.  On April 26, 2000, SCE filed an application to obtain such approval.  The Commission
approved the settlement at its November 21, 2000 meeting, and issued its decision on November 22, 2000.  That
decision became final (no longer subject to appeal) on December 22, 2000.  On June 13, 2001, the Court dismissed
all claims in the case, with prejudice, based upon the settlement and the CPUC approval of the settlement.

                                       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, SCE is actively involved in four lawsuits claiming personal injuries
allegedly resulting from exposure to radiation at San Onofre.

On May 9, 2001, SCE was served with a complaint filed on March 1, 2001, by a former contract worker at San Onofre
and his wife in the U.S. District Court for the Southern District of California.  In addition to SCE, plaintiffs
also named as defendants Combustion Engineering and Bechtel Construction Company, the employer of the former San




Page 53



Onofre worker.  The Court approved a stipulation of the parties giving defendants until August 28, 2001, to
respond to the complaint.  The parties currently are negotiating an agreement to further stay prosecution of this
case pending the results of the November 17, 1995, case currently before the Ninth Circuit Court of Appeal.

                                              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, 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 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.  The Court has ordered
defendants to respond to the consolidated complaint by September 17, 2001.

                                         Qualifying Facilities 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, 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 largely been coordinated before a single trial judge.  On July 19, 2001, the judge set briefing and oral
argument for August 2001 on the issue of whether the trial court or the CPUC has jurisdiction over the claims and
defenses asserted in the various actions, and continued the current stay of the actions before him.  The judge
further ordered that for any matters over which the trial court has jurisdiction, motions for summary judgment or
adjudication shall be briefed and heard in October 2001.

During June, July and August 2001, SCE reached agreements with generators representing about 95% of the QF
renewable energy and approximately 95% of the QF cogeneration energy 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.  Long Beach has posted
a bond and attached one of SCE's bank accounts.  SCE filed a petition for review of the right to attach order
issued in the Long Beach case, and the California Court of Appeal has issued a temporary stay order in that case
and set oral argument on SCE's petition for September 25, 2001.  Long Beach has sought reconsideration of the
stay order, but the Court of Appeal has not yet responded to this request.

In addition to the cases previously referenced in Edison International's 2000 Form 10-K, and in Part II, Item 1
of Edison International's First Quarter 10-Q, the following legal proceedings, identified by principal party,
filing date, and court jurisdiction, have been filed against SCE:




Page 54



Principal Party                             Date Filed                       Court Jurisdiction
---------------                             ----------                       ------------------

Rio Bravo Jasmin                            May 16, 2001             Los Angeles County Superior Court,
                                                                     Central District

Calwind Resources, Inc.                     May 18, 2001             Los Angeles County Superior Court,
                                                                     Central District

Wheelabrator Norwalk                        May 18, 2001             Los Angeles County Superior Court,
Energy Co., Inc.                                                     South East District

Smurfit Stone Container                     May 25, 2001             United States District Court,
                                                                     Central District, Los Angeles Division

Ripon Cogeneration, Inc.                    June 6, 2001             Los Angeles County Superior Court,
                                                                     Central District

Midway-Sunset Cogeneration                  June 7, 2001             Kern County Superior Court
Company

San Gorgonio Westwinds II, LLC              June 8, 2001             Riverside County Superior Court

Colmac Energy, Inc.                         June 12, 2001            Los Angeles County Superior Court,
                                                                     Central District

Dutch Energy Corporation                    July 23, 2001            Los Angeles County Superior Court,
                                                                     Central District (On August 6, 2001,
                                                                     plaintiff voluntarily dismissed this
                                                                     complaint without prejudice.)


                                          PX Performance Bond Litigation

As previously reported in Part I, Item 3 of Edison International's 2000 Form 10-K, 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.




Page 55



Item 4.  Submission of Matters to a Vote of Security Holders

At Edison International's Annual Meeting of Shareholders on May 14, 2001, shareholders elected thirteen nominees
to the Board of Directors.  The number of broker non-votes for each nominee was zero.  The number of votes cast
for and withheld from each Director-nominee were as follows:

                                                                                Number of Votes
                                                                                ---------------

Name                                                                       For                  Withheld
----                                                                       ---                  --------
John E. Bryson                                                         262,035,541               9,719,171
Warren Christopher                                                     260,334,472              11,420,240
Stephen E. Frank                                                       262,882,194               8,872,518
Joan C. Hanley                                                         263,106,598               8,648,114
Carl F. Huntsinger                                                     263,139,245               8,615,467
Charles D. Miller                                                      263,061,370               8,693,342
Luis G. Nogales                                                        263,100,541               8,654,171
Ronald L. Olson                                                        258,975,850              12,778,862
James M. Rosser                                                        263,182,018               8,572,694
Robert H. Smith                                                        263,202,476               8,552,236
Thomas C. Sutton                                                       263,245,175               8,509,537
Daniel M. Tellep                                                       263,199,164               8,555,548
Edward Zapanta                                                         263,150,572               8,604,140


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 February 15,
                  2001 (File No. 1-9936, filed as Exhibit 3.3 to Form 10-K for the year ended December 31, 2000)*

         10       Stock Purchase Agreement By and Between Edison Enterprises and ADT Security Services, Inc.,
                  dated as of June 27, 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
         --------------                           ----------                    ----------------

         March 27, 2001                        April 10, 2001                         5
         June 11, 2001                         June 11, 2001                          5

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



Page 56


                                                    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


August 14, 2001