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

                                                     FORM 10-Q

(Mark One)

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

       For the quarterly period ended                                September 30, 2002
                                      ----------------------------------------------------------------------------

                                                        OR

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



       For the transition period from                                        to
                                      --------------------------------------    ----------------------------------

                                           Commission File Number 1-9936

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

                       CALIFORNIA                                             95-4137452
            (State or other Jurisdiction of                                (I.R.S. Employer
             Incorporation or Organization)                              Identification No.)

                2244 Walnut Grove Avenue
                     (P.O. Box 800)
                  Rosemead, California
                 (Address of Principal                                          91770
                   Executive Offices)                                         (Zip Code)

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


       Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days.

Yes   X           No ___
    -----

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




                        Class                                           Outstanding at November 12, 2002
-------------------------------------------------------      --------------------------------------------------------
              Common Stock, no par value                                           325,811,206


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








EDISON INTERNATIONAL

INDEX
                                                                                              Page
                                                                                               No.
                                                                                              -----

Part I.Financial Information:

  Item 1.     Consolidated Financial Statements:

              Consolidated Statements of Income (Loss) - Three and Nine Months
                   Ended September 30, 2002, and 2001 (Unaudited)                              1

              Consolidated Statements of Comprehensive Income (Loss) -
                   Three and Nine Months Ended September 30, 2002,
                   and 2001 (Unaudited)                                                        1

              Consolidated Balance Sheets - September 30, 2002, (Unaudited)
                   and December 31, 2001                                                       2

              Consolidated Statements of Cash Flows - Nine Months
                   Ended September 30, 2002, and 2001 (Unaudited)                              4

              Notes to Consolidated Financial Statements                                       5

  Item 2.     Management's Discussion and Analysis of Results
                   of Operations and Financial Condition                                      17

  Item 3.     Quantitative and Qualitative Disclosures About Market Risk                      72

  Item 4.     Controls and Procedures                                                         72

Part II.  Other Information:

  Item 1.     Legal Proceedings                                                               73

  Item 6.     Exhibits and Reports on Form 8-K                                                77

Signatures

Certifications





EDISON INTERNATIONAL



PART I            FINANCIAL INFORMATION



Item 1.           Consolidated Financial Statements



CONSOLIDATED STATEMENTS OF INCOME (LOSS)

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

In millions, except per-share amounts                        2002            2001            2002          2001
-------------------------------------------------------------------------------------------------------------------

                                                                                (Unaudited)
Electric utility                                          $ 2,864          $ 2,725        $ 6,957       $ 5,826
Nonutility power generation                                 1,094            1,095          2,451         2,406
Financial services and other                                   39               62            102           292
-------------------------------------------------------------------------------------------------------------------

Total operating revenue                                     3,997            3,882          9,510         8,524
-------------------------------------------------------------------------------------------------------------------

Fuel                                                          362              315            912           815
Purchased power                                               780              759          1,615         3,290
Provisions for regulatory adjustment clauses - net            889               (5)         1,255          (124)
Other operation and maintenance                               849              768          2,395         2,251
Depreciation, decommissioning and amortization                258              242            766           695
Property and other taxes                                       35               28            110            88
Net gain on sale of utility plant                              (6)              --             (6)           (7)
-------------------------------------------------------------------------------------------------------------------

Total operating expenses                                    3,167            2,107          7,047         7,008
-------------------------------------------------------------------------------------------------------------------

Operating income                                              830            1,775          2,463         1,516
Interest and dividend income                                   48               39            227           130
Other nonoperating income                                       8               47             31            78
Interest expense - net of amounts capitalized                (307)            (449)          (984)       (1,179)
Other nonoperating deductions                                 (25)             (22)           (73)          (74)
Dividends on preferred securities                             (24)             (23)           (72)          (69)
Dividends on utility preferred stock                           (4)              (6)           (15)          (17)
-------------------------------------------------------------------------------------------------------------------

Income from continuing operations before taxes                526            1,361          1,577           385
Income tax                                                    175              560            480           155
-------------------------------------------------------------------------------------------------------------------

Income from continuing operations                             351              801          1,097           230
Income (loss) from discontinued operations - net of tax         1           (1,214)             4        (1,362)
-------------------------------------------------------------------------------------------------------------------

Net income (loss)                                          $  352          $  (413)       $ 1,101      $ (1,132)
-------------------------------------------------------------------------------------------------------------------

Weighted-average shares of common stock outstanding           326              326            326           326
Basic earnings (loss) per share:
Continuing operations                                      $ 1.08         $  2.46        $   3.37     $    0.71
Discontinued operations                                        --           (3.73)            .01         (4.18)
-------------------------------------------------------------------------------------------------------------------

Total                                                      $ 1.08         $ (1.27)       $   3.38      $  (3.47)
-------------------------------------------------------------------------------------------------------------------

Weighted-average shares, including effect
   of dilutive securities                                     329              326            329           326
Diluted earnings (loss) per share:
Continuing operations                                      $ 1.07         $  2.46        $   3.34     $    0.71
Discontinued operations                                        --           (3.73)            .01         (4.18)
-------------------------------------------------------------------------------------------------------------------
1.07
Total                                                      $ 1.07         $ (1.27)       $   3.35     $   (3.47)
-------------------------------------------------------------------------------------------------------------------

Dividends declared per common share                           --                --            --             --




CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

In millions                                                  2002            2001           2002           2001
-------------------------------------------------------------------------------------------------------------------

                                                                                (Unaudited)
Net income (loss)                                           $ 352           $ (413)      $ 1,101       $ (1,132)
Other comprehensive income, net of tax:
   Foreign currency translation adjustments                    (8)              97            71            (12)
   Unrealized loss on investments - net                        (1)              --            (8)            --
   Cumulative effect of change in accounting for derivatives   --              (16)            6            152
   Unrealized loss on cash flow hedges                        (69)             (17)          (42)          (300)
   Reclassification adjustment for gain (loss)
      included in net income (loss)                             2              (11)            5            (37)
-------------------------------------------------------------------------------------------------------------------

Comprehensive income (loss)                                 $ 276           $ (360)      $ 1,133       $ (1,329)
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                    The accompanying notes are an integral part of these financial statements.


Page 1




EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

                                                                            September 30,           December 31,
In millions                                                                     2002                    2001
-------------------------------------------------------------------------------------------------------------------

                                                                             (Unaudited)
ASSETS
Cash and equivalents                                                         $  2,548               $  3,991
Receivables, less allowances of $51 and $41 for uncollectible
  accounts at respective dates                                                  1,429                  1,259
Accrued unbilled revenue                                                          582                    451
Fuel inventory                                                                    114                    124
Materials and supplies, at average cost                                           216                    203
Accumulated deferred income taxes - net                                            85                  1,092
Trading and price risk management assets                                           68                     65
Regulatory assets - net                                                            61                     83
Prepayments and other current assets                                              292                    232
-------------------------------------------------------------------------------------------------------------------

Total current assets                                                            5,395                  7,500
-------------------------------------------------------------------------------------------------------------------

Nonutility property - less accumulated provision for
  depreciation of $937 and $706 at respective dates                             6,898                  6,414
Nuclear decommissioning trusts                                                  2,107                  2,275
Investments in partnerships and unconsolidated subsidiaries                     2,015                  2,253
Investments in leveraged leases                                                 2,446                  2,386
Other investments                                                                 208                    226
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Total investments and other assets                                             13,674                 13,554
-------------------------------------------------------------------------------------------------------------------

Utility plant, at original cost:
   Transmission and distribution                                               13,858                 13,568
   Generation                                                                   1,754                  1,729
Accumulated provision for depreciation and decommissioning                     (8,244)                (7,969)
Construction work in progress                                                     653                    556
Nuclear fuel, at amortized cost                                                   137                    129
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Total utility plant                                                             8,158                  8,013
-------------------------------------------------------------------------------------------------------------------

Goodwill                                                                          659                    633
Regulatory assets - net                                                         4,862                  5,528
Other deferred charges                                                          1,066                  1,341
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Total deferred charges                                                          6,587                  7,502
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Assets of discontinued operations                                                  59                    205
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Total assets                                                                 $ 33,873               $ 36,774
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-------------------------------------------------------------------------------------------------------------------


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

Page 2



EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

                                                                             September 30,         December 31,
In millions, except share amounts                                                2002                  2001
-------------------------------------------------------------------------------------------------------------------

                                                                              (Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt                                                             $      52              $  2,445
Long-term debt due within one year                                              1,184                 1,499
Preferred stock to be redeemed within one year                                      9                   105
Accounts payable                                                                1,020                 3,414
Accrued taxes                                                                     908                   183
Trading and price risk management liabilities                                      38                    24
Other current liabilities                                                       2,032                 2,187
-------------------------------------------------------------------------------------------------------------------

Total current liabilities                                                       5,243                 9,857
-------------------------------------------------------------------------------------------------------------------

Long-term debt                                                                 13,539                12,674
-------------------------------------------------------------------------------------------------------------------

Accumulated deferred income taxes - net                                         5,943                 6,367
Accumulated deferred investment tax credits                                       169                   172
Customer advances and other deferred credits                                    1,718                 1,675
Power-purchase contracts                                                          300                   356
Accumulated provision for pension and benefits                                    601                   505
Other long-term liabilities                                                       163                   147
-------------------------------------------------------------------------------------------------------------------

Total deferred credits and other liabilities                                    8,894                 9,222
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Liabilities of discontinued operations                                             39                    71
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Commitments and contingencies (Notes 2 and 4)
Minority interest                                                                 397                   345
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Preferred stock of utility:
   Not subject to mandatory redemption                                            129                   129
   Subject to mandatory redemption                                                147                   151
Company-obligated mandatorily redeemable securities of subsidiaries
      holding solely parent company debentures                                    951                   949
Other preferred securities                                                        117                   104
-------------------------------------------------------------------------------------------------------------------

Total preferred securities of subsidiaries                                      1,344                 1,333
-------------------------------------------------------------------------------------------------------------------

Common stock (325,811,206 shares outstanding at each date)                      1,978                 1,966
Accumulated other comprehensive income (loss)                                    (296)                 (328)
Retained earnings                                                               2,735                 1,634
-------------------------------------------------------------------------------------------------------------------

Total common shareholders' equity                                               4,417                 3,272
-------------------------------------------------------------------------------------------------------------------


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



Total liabilities and shareholders' equity                                   $ 33,873              $ 36,774
-------------------------------------------------------------------------------------------------------------------



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



Page 3




EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

In millions                                                                     2002                      2001
-------------------------------------------------------------------------------------------------------------------

                                                                                         (Unaudited)
Cash flows from operating activities:
Net income from continuing operations                                       $  1,097                   $   230
Adjustments to reconcile net income to net cash
   provided by operating activities:
    Depreciation, decommissioning and amortization                               766                       695
    Other amortization                                                            83                        67
    Deferred income taxes and investment tax credits                             189                       309
    Equity in income from partnerships and unconsolidated
       subsidiaries                                                             (228)                     (332)
    Income from leveraged leases                                                 (83)                      (88)
    Regulatory assets - long-term - net                                        1,003                      (388)
    Write-down of non-utility assets                                              --                       208
    Other assets                                                                  81                       (99)
    Other liabilities                                                            125                       (66)
    Changes in working capital:
       Receivables and accrued unbilled revenue                                 (286)                     (165)
       Regulatory liabilities - short-term - net                                  70                       (59)
       Fuel inventory, materials and supplies                                     (6)                       (9)
       Prepayments and other current assets                                     (112)                      157
       Accrued interest and taxes                                                769                      (105)
       Accounts payable and other current liabilities                         (2,468)                    1,694
Distributions and dividends from unconsolidated entities                         262                       217
Operating cash flows from discontinued operations                                 58                        (6)
-------------------------------------------------------------------------------------------------------------------

Net cash provided by operating activities                                      1,320                     2,260
-------------------------------------------------------------------------------------------------------------------

Cash flows from financing activities:
Long-term debt issued                                                          1,952                     3,396
Long-term debt repaid                                                         (1,536)                   (1,431)
Bonds remarketed (repurchased) and funds held in trust                           191                      (130)
Issuance of preferred securities                                                  --                        95
Redemption of preferred securities                                              (100)                     (164)
Rate reduction notes repaid                                                     (176)                     (174)
Nuclear fuel financing - net                                                     (59)                      (14)
Short-term debt financing - net                                               (2,321)                     (801)
Financing cash flows from discontinued operations                                 --                      (250)
-------------------------------------------------------------------------------------------------------------------

Net cash provided (used) by financing activities                              (2,049)                      527
-------------------------------------------------------------------------------------------------------------------

Cash flows from investing activities:
Additions to property and plant                                               (1,200)                     (698)
Purchase of power sales agreement                                                (80)                       --
Proceeds from sale of nonutility property                                         59                       237
Net funding of nuclear decommissioning trusts                                      1                         3
Distributions from (investments in) partnerships and
   unconsolidated subsidiaries                                                    82                       (99)
Net investments in leveraged leases                                               --                        68
Sales of investments in other assets                                             354                      (301)
Investing cash flows from discontinued operations                                 --                       165
-------------------------------------------------------------------------------------------------------------------

Net cash used by investing activities                                           (784)                     (625)
-------------------------------------------------------------------------------------------------------------------

Effect of exchange rate changes on cash                                           10                       (41)
-------------------------------------------------------------------------------------------------------------------

Net increase (decrease) in cash and equivalents                               (1,503)                    2,121
Cash and equivalents, beginning of period                                      4,054                     1,973
-------------------------------------------------------------------------------------------------------------------

Cash and equivalents, end of period                                            2,551                     4,094
Cash and equivalents - discontinued operations                                    (3)                      (64)
-------------------------------------------------------------------------------------------------------------------

Cash and equivalents, continuing operations                                 $  2,548                   $ 4,030
-------------------------------------------------------------------------------------------------------------------



                     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 of a normal recurring nature necessary for a fair presentation of
financial position, results of operations and cash flows in accordance with accounting principles generally
accepted in the United States for the periods covered by this report have been included.  The results of
operations for the period ended September 30, 2002, are not necessarily indicative of the operating results for
the full year.

Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated
Financial Statements" included in its 2001 Annual Report on Form 10-K filed with the Securities and Exchange
Commission.  Edison International follows the same accounting policies for interim reporting purposes.

Certain reclassifications have been made to prior-period amounts to conform to the September 30, 2002, financial
statement presentation.  These reclassifications had no impact on net income.

The quarterly report should be read in conjunction with Edison International's 2001 Annual Report on Form 10-K
filed with the Securities and Exchange Commission.

Note 1.  New Accounting Standards

On January 1, 2001, Edison International adopted a new accounting standard for derivative financial instruments
and hedging activities.  Effective April 1, 2002, Edison International also adopted two authoritative accounting
interpretations to this standard, which precludes fuel contracts with variable amounts from qualifying under the
normal purchases and sales exception and precludes Edison Mission Energy's (EME) forward electricity contracts
from qualifying for the normal sales exception as EME has net settlement provisions with its counterparties.
However, EME's contracts qualify as cash flow hedges.  Adoption of these interpretations did not have a
significant impact on Edison International's financial statements.

In October 2002, an accounting interpretation related to accounting for contracts involved in energy trading and
risk management activities was rescinded.  The rescission means that energy trading and risk management
activities will no longer be marked-to-market as trading activities, but will instead follow accounting standards
for derivatives, where each energy contract must be assessed to determine whether or not it meets the definition
of a derivative.  If an energy contract meets the definition of a derivative, then it would be recorded at fair
value (i.e., marked-to-market), subject to permitted exceptions.  If an energy contract does not meet the
definition of a derivative, then it would be recorded on an accrual basis.  EME is conducting a review of its
existing contracts to determine the impact of this change in accounting for contracts outstanding at October 25,
2002.

On January 1, 2002, Edison International adopted a new accounting standard for Goodwill and Other Intangibles.
The new accounting standard required a benchmark assessment for goodwill by June 30, 2002.  Edison International
completed its benchmark assessment and determined that the only goodwill impairment is related to EME's September
2000 acquisition of Citizens Power.  Total goodwill related to Citizens Power was $25 million as of December 31,
2001.  In accordance with the new accounting standard, during third quarter 2002 an additional test was performed
to determine the amount of the impairment.  The result of this test was a $23 million ($14 million after tax)
goodwill impairment associated with the Citizens Power acquisition.  Adoption of this standard was not material
to Edison International; therefore, the impact of adoption was recorded in the other nonoperating deductions line
item of the September 30, 2002, consolidated statements of income (loss), rather than as a cumulative effect of a
change in accounting principle, retroactive to January 1, 2002.

A new accounting standard, Accounting for Asset Retirement Obligations, requires entities to record the fair
value of a liability for a legal asset retirement obligation in the period in which it is incurred.  When the
liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related

Page 5


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Edison International on January 1, 2003.  Edison International is studying the effects of the new
standard and has not yet determined the potential impact on its financial statements.

Note 2.  Regulatory Matters

California Public Utilities Commission Litigation Settlement Agreement

Southern California Edison (SCE) and the California Public Utilities Commission (CPUC) entered into a settlement
of SCE's lawsuit against the CPUC, which sought a ruling that SCE is entitled to full recovery of its past
electricity procurement costs.  A key element of the settlement agreement was the establishment of a $3.6 billion
rate-recovery mechanism called the procurement-related obligations account (PROACT) as of August 31, 2001.  The
Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the federal court of
appeals seeking to overturn the stipulated judgment of the district court that approved the settlement
agreement.  On March 4, 2002, the court of appeals heard argument on the appeal, and on September 23, 2002, the
court issued its opinion.  In the opinion, the court affirmed the district court on all claims, with the
exception of the challenges founded upon California state law, which the appeals court referred to the California
Supreme Court.  Specifically, the appeals court affirmed the district court in the following respects:  (1) the
district court did not err in denying the motions to intervene brought by entities other than TURN; (2) the
district court did not err in denying standing for the entities other than TURN to appeal the stipulated
judgment; (3) the district court was not deprived of original jurisdiction over the lawsuit; (4) the district
court did not err in declining to abstain from the case; (5) the district court did not exceed its authority by
approving the stipulated judgment without TURN's consent; (6) the district court's approval of the settlement
agreement did not deny TURN due process; and (7) the district court did not violate the Tenth Amendment of the
United States Constitution in approving the stipulated judgment.  In sum, the appeals court concluded that none
of the substantive arguments based on federal statutory or constitutional law compelled reversal of the district
court's approval of the stipulated judgment.

However, the appeals court stated in its opinion that there is a serious question whether the settlement
agreement violated state law, both in substance and in the procedure by which the CPUC agreed to it.  The appeals
court added that if the settlement agreement violated state law, the CPUC lacked capacity to consent to the
stipulated judgment, and the stipulated judgment would need to be vacated.  The appeals court indicated that, on
a substantive level, the stipulated judgment appears to violate California's electric industry restructuring
statute providing for a rate freeze.  The appeals court also indicated that, on a procedural level, the
stipulated judgment appears to violate California laws requiring open meetings and public hearings.  Because
federal courts are bound by the pronouncements of the state's highest court on applicable state law, and because
the federal appeals court found no controlling precedents from California courts on the issues of state law in
this case, the appeals court issued a separate order certifying those issues to the California Supreme Court and
requested that the California Supreme Court accept certification.

The appeals court stayed further proceedings in the case pending a response from the California Supreme Court on
the request for certification.  The appeals court did not stay the continued operation of the settlement
agreement, thus collection of past procurement costs under PROACT is continuing.  On October 29, 2002, SCE filed a
brief requesting that the California Supreme Court answer the appeals' court certification and requesting that
hearing of the matter be placed on the California Supreme Court's March 2003 calendar, or heard at the court's
earliest convenience.  SCE continues to operate under the settlement agreement.  SCE continues to believe it is
probable that SCE ultimately will recover its past procurement costs through regulatory mechanisms, including the
PROACT.  However, SCE cannot predict with certainty the outcome of the pending legal proceedings.

Under the settlement agreement, SCE cannot pay dividends or other distributions on its common stock (all of which
is held by its parent, Edison International) prior to the earlier of the date on which SCE has

Page 6

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recovered all of its procurement-related obligations or January 1, 2005, except that if SCE has not recovered all
of its procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume
common stock dividends prior to January 1, 2005, and the CPUC will not unreasonably withhold its consent.

In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition in the
California Supreme Court against the CPUC.  The FTCR's petition asserted that, among other things, the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE.  The petition sought a declaration that the CPUC cannot agree not to enforce any state law unless an
appellate court has determined that the state law is invalid, unconstitutional, or unenforceable.  The FTCR's
petition expressly stated that it did not seek any order from the California Supreme Court with respect to the
stipulated judgment implementing the settlement agreement between the CPUC and SCE; and the petition did not
request any judicial actions regarding the settlement agreement.  The FTCR is not a party to TURN's federal court
appeal concerning the stipulated judgment.  On August 14, 2002, the California Supreme Court issued a summary
denial of the FTCR's petition.

Electric Line Maintenance Practices Proceeding

In August 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices.  The OII is based on a report issued by the CPUC's Protection and Safety
Consumer Services Division (CPSD), which alleges SCE had a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000.  The OII also alleges that noncomplying
conditions were involved in 37 accidents resulting in death, serious injury, or property damage.  The CPSD
identified 4,721 alleged violations of the General Orders during the three-year period.  The OII placed SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation.

Prepared testimony was filed on this matter in April 2002, and hearings were concluded in September 2002.  In
opening briefs filed on October 21, 2002, the CPSD recommended SCE be assessed a penalty of $97 million, while
SCE requested that the CPUC dismiss the proceeding and impose no penalties.  SCE stated in its opening brief that
it has acted reasonably, allocating its financial and human resources in pursuit of the optimum combination of
employee and public safety, system reliability, cost-effectiveness, and technological advances.  SCE also
encouraged the CPUC to transfer consideration of issues related to development of standardized inspection
methodologies and inspector training to an order instituting rulemaking to revise these General Orders opened by
the CPUC in October 2001, or to a new rulemaking proceeding.  Reply briefs are due on November 18, 2002, and a
decision is expected by year-end 2002 or early 2003.  SCE is unable to predict with certainty whether this matter
ultimately will result in any material financial penalties or impacts on SCE.

Holding Company Proceeding

In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision authorizing
utilities to form holding companies and initiates an investigation into, among other things:  whether the holding
companies violated CPUC requirements to give first priority to the capital needs of their respective utility
subsidiaries; 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.  On January 9, 2002, the CPUC
issued an interim decision on the first priority condition.  The decision stated that, at least under certain
circumstances, the condition includes the requirement that holding companies infuse all types of capital into
their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve.  The decision
did not determine if any of the utility holding companies had violated this condition, reserving such a
determination for a later phase of the proceedings.  On February 11, 2002, SCE and Edison International filed an
application for rehearing of the decision.  On July 17, 2002, the CPUC affirmed its earlier decision on the first
priority condition and also denied Edison International's request for a rehearing of the CPUC's determination
that it had jurisdiction over Edison International in this proceeding.  On August 21, 2002, Edison International
and SCE jointly filed a petition

Page 7


requesting a review of the CPUC's decisions with regard to first priority considerations, and Edison
International filed a petition for a review of the CPUC decision asserting jurisdiction over holding companies.
Edison International cannot predict with certainty what effects this investigation or any subsequent actions by
the CPUC may have on Edison International or any of its subsidiaries.

Utility-Retained Generation (URG) Proceeding

On April 4, 2002, the CPUC issued a decision to return URG assets to cost-of-service ratemaking through the end
of 2002.  After that time, SCE's URG-related revenue requirement will be determined through the 2003 general rate
case proceeding.  Key elements of the URG decision are: retention of the San Onofre incentive pricing mechanism
through 2003; recovery of incurred costs for all URG components other than San Onofre; establishment of an
amortization schedule for SCE's nuclear plants based on their remaining useful lives; and establishment of
balancing accounts for utility generation, purchased power, and Independent System Operator (ISO) ancillary
services.

Based on this decision, during second quarter 2002, SCE reestablished for financial reporting purposes regulatory
assets related to its unamortized nuclear plant, purchased-power settlements and flow-through taxes, reduced the
PROACT balance, and recorded a corresponding credit to earnings of $480 million after tax.  The impact of the URG
decision is reflected in the financial statements as a credit (decrease) to the provisions for regulatory clauses
of $644 million, partially offset by an increase in deferred income tax expense of $164 million.  The reduction
in the PROACT balance reflects a change in the amortization schedule of SCE's unamortized nuclear facilities from
the schedule required to be used to calculate the PROACT during the last four months of 2001.  Implementation of
the URG decision, together with the PROACT mechanism, allowed SCE to reestablish substantially all of the
regulatory assets previously written off to earnings.

Wholesale Electricity Markets

On April 25, 2001, after months of high power prices, the Federal Energy Regulatory Commission (FERC) issued an
order providing for energy price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve
power).  The order establishes an hourly clearing price based on the costs of the least efficient generating unit
during the period.  Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency
periods and price mitigation in the 11-state western region through September 30, 2002.  On July 17, 2002, the
FERC issued an order reviewing the ISO's proposals to redesign the market and implementing a market power
mitigation program for the 11-state western region.  The FERC declined to extend beyond September 30, 2002, all
of the market mitigation measures it had previously adopted.  However, effective October 1, 2002, the FERC
extended a requirement, first ordered in its June 19, 2001, decision, that all western energy sellers offer for
sale all operationally and contractually available energy.  It also ordered a cap on bids for real-time energy
and ancillary services of $250/MWh to be effective beginning October 1, 2002, and ordered various other market
power mitigation measures.  Implementation of the $250/MWh bid cap and other market power mitigation measures
were delayed until October 31, 2002, by a FERC order issued September 26, 2002.  The FERC did not set a specific
expiration date for its new market mitigation plan.  SCE cannot yet determine whether the new market mitigation
plan adopted by the FERC will be sufficient to mitigate market price volatility in the wholesale electricity
markets in which SCE will purchase its residual net short electricity requirements (i.e., the amount of energy
needed to serve SCE's customers from sources other than its own generating plants, power purchase contracts and
California Department of Water Resources (CDWR) contracts).

On July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges by energy
suppliers to the ISO and California Power Exchange (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 conducted evidentiary hearings on this matter in March, August and October 2002.  An initial decision
from the judge is expected by the end of 2002 and a decision by the FERC is expected in 2003.  On August 13,
2002, in an investigation proceeding, the FERC's staff issued an initial report on manipulation of electric and
natural gas prices, which identified fundamental flaws in the use of the gas price presently included in the
methodology for calculating refunds.  Parties have filed

Page 8


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

comments on the FERC staff's initial report.  SCE cannot yet determine either the likelihood that the initial
report will affect the FERC's determination of refunds or the amount of any potential refunds.  Under the
settlement agreement with the CPUC, any refunds will be applied to reduce the PROACT balance until the PROACT is
fully recovered.  After PROACT recovery is complete, 90% of any refunds will be refunded to ratepayers.  SCE has
not incorporated any potential refunds into its current projection of the timing of PROACT recovery.



Note 3.  Purchased Power

SCE purchased power through the PX and ISO from April 1998 through mid-January 2001.  SCE has bilateral forward
contracts with other entities and power-purchase contracts with other utilities and independent power producers
classified as qualifying facilities (QFs).  Purchased power detail is provided below:

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

     In millions                                            2002            2001         2002           2001
--------------------------------------------------------------------------------------------------------------

                                                                               (Unaudited)
     PX/ISO:
     Purchases                                            $   15         $    26      $    79       $    660
     Generation sales                                         --               2           --            324
--------------------------------------------------------------------------------------------------------------

     Purchased power - PX/ISO - net                           15              24           79            336
     Purchased power - bilateral contracts                    16              53           46            142
     Purchased power - interutility/QF contracts             749             682        1,490          2,812
--------------------------------------------------------------------------------------------------------------

     Total                                                $  780         $   759      $ 1,615       $  3,290
--------------------------------------------------------------------------------------------------------------



PX/ISO billing adjustments are included in all periods reported above.  Net PX/ISO amounts for the three months
ended September 30, 2002, and 2001, and for the nine months ended September 30, 2002, reflect only billing
adjustments.  These billing adjustments are recovered through the PROACT and have no impact on earnings.  Since
January 17, 2001, all power, other than the QF and bilateral contracts, is purchased by a state agency for
delivery to SCE's customers and is not considered a cost to SCE.

Note 4.  Contingencies

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

Aircraft Leases

Edison Capital has leased two aircraft to United Airlines with a current potential earnings exposure of
$37 million and three aircraft to American Airlines with a current potential earnings exposure of $46 million, in
the event of repossession of the aircrafts.  Each aircraft also secures the repayment of loans borrowed to
purchase the aircraft.  United Airlines has publicly indicated that it is considering filing for reorganization
in bankruptcy.  In the event of bankruptcy, the leases may be affirmed, rejected or renegotiated.  Each lender
with a security interest in the aircraft may also seek to re-possess the aircraft in the event of bankruptcy or
default in loan repayments.  United Airlines has also contacted Edison Capital regarding its remaining lease
obligations and its desire to avoid bankruptcy.  There are no existing defaults, each required lease payment has
been timely made, and each airline had informed Edison Capital that each aircraft continues to be in service.
The next payment from United Airlines is due in December 2002.  At this time, Edison Capital is unable to
determine the likelihood or estimate the amount of potential losses related to its aircraft leases.


Page 9


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EME's Chicago In-City Obligation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, an EME
subsidiary committed to install one or more gas-fired electric generating units having an additional gross
dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago (referred to as the
In-City Obligation).  The acquisition documents require that commercial operation of this project commence by
December 15, 2003.  Due to additional capacity for new gas-fired generation in the Mid-America Interconnected
Network, generally referred to as the MAIN Region, and the improved reliability of power generation in the
Chicago area, EME is in discussions with Commonwealth Edison and the City of Chicago regarding alternatives to
construction of 500 MW of capacity, which EME does not believe is needed at this time.  There can be no assurance
that these discussions will result in an agreement to terminate the In-City Obligation.  If EME were to install
this additional capacity, EME estimates that the cost could be as much as $320 million.

Energy Crisis Issue

In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.  The
lawsuit, as amended, involved securities fraud claims arising from alleged improper accounting for the
energy-cost undercollections.  The complaint was 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 was consolidated with
another similar lawsuit filed on March 15, 2001.  SCE and Edison International filed a motion to dismiss the
lawsuits for failure to state a claim and on March 8, 2002, the district court dismissed the complaint with
prejudice.  The plaintiffs have dismissed their appeal and on April 26, 2002, the federal court of appeals
dismissed the appeal with prejudice.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which require it to incur
substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove
the effect of past operations on the environment.

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

Edison International records its environmental remediation liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be estimated.  Edison International
reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of involvement and financial condition of
other potentially responsible parties.  These estimates include costs for site investigations, remediation,
operations and maintenance, monitoring and site closure.  Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.

Edison International's recorded estimated minimum liability to remediate its 41 identified sites at SCE is
$100 million.  Edison International's other subsidiaries have no identified remediation sites.  The ultimate costs
to clean up Edison International's identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of
reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over

Page 10


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $285 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 remediation costs at certain sites, representing $39 million of its
recorded liability, through an incentive mechanism (SCE may request to include additional sites).  Under this
mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and other third parties.  SCE has
successfully settled insurance claims with all responsible carriers.  Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates.  SCE has recorded a regulatory asset of $65 million for its
estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

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

Edison International expects to clean up its identified sites over a period of up to 30 years.  Remediation costs
in each of the next several years are expected to range from $10 million to $25 million.  Recorded costs for the
twelve months ended September 30, 2002, were $22 million.

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

Federal Income Taxes

On August 7, 2002, Edison International received a notice from the Internal Revenue Service (IRS) asserting
deficiencies in federal corporate income taxes for its 1994 to 1996 tax years.  The vast majority of the tax
deficiencies are timing differences and, therefore, amounts ultimately paid, if any, would benefit Edison
International as future tax deductions.  Edison International is challenging the deficiencies asserted by the
IRS, which are currently under appeal.  Edison International believes that it has meritorious legal defenses to
those deficiencies and believes that the ultimate outcome of this matter will not result in a material impact on
Edison International's consolidated results of operations or financial position.

Lakeland Project

EME owns the Lakeland project, a 220-MW combined-cycle natural gas-fired power plant located in the U.K., and
sells the project's electricity under a power sales agreement.  Norweb Energi Ltd. is the counterparty under the
Lakeland power sales agreement and an indirect subsidiary of TXU Europe.  On October 14, 2002, TXU Corp., the
U.S. parent company of TXU Europe, announced that it would not provide additional funding for its European
business and was considering selling all or a portion of this business.  On October 21, 2002, TXU Corp. announced
the sale by its indirect subsidiary, TXU (U.K.) Ltd, of all its retail customer contracts in the U.K.
Concurrently, TXU announced its intention to renegotiate certain power sales agreements, including the Lakeland
power sales agreement, as part of an effort to restructure its operations and preserve creditor value.  TXU
further indicated that failure to renegotiate these agreements or otherwise to restructure its operations could
result in the equivalent of bankruptcy in the U.K. for one or more of TXU's subsidiaries, including possibly
Norweb Energi Ltd.


Page 11


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Currently, EME continues to deliver power under the Lakeland power sales agreement and Norweb Energi Ltd. has
made all payments.  However, EME cannot determine the outcome of TXU's restructuring activities in Europe, nor
the effect of such activities upon the Lakeland power sales agreement.  If the power sales agreement is
terminated, EME could operate the Lakeland project as a merchant plant, but because of current depressed power
prices in the U.K. market, EME may not be able to operate the plant profitably in the near term.  Although cash
is held by the project ($32 million at September 30, 2002), EME does not anticipate any distributions unless and
until the uncertainties surrounding the power sales agreement are resolved.  Further, during the fourth quarter,
EME will complete an asset impairment evaluation taking into consideration continuing developments with respect
to the power sales agreement.  At September 30, 2002, EME had $138 million invested in property, plant and
equipment and $72 million in debt associated with the Lakeland project.

Navajo Nation Litigation

Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to the Mohave Generating
Station.  In June 1999, the Navajo Nation filed a complaint in federal district court against Peabody and certain
of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE.  The complaint
asserts claims against the defendants for, among other things, violations of the federal RICO statute,
interference with fiduciary duties and contractual relations, fraudulent misrepresentation by nondisclosure, and
various contract-related claims.  The complaint claims that the defendants' actions prevented the Navajo Nation
from obtaining the full value in royalty rates for the coal.  The complaint seeks damages of not less than $600
million, trebling of that amount, and punitive damages of not less than $1 billion, as well as a declaration that
Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated.

In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation
had breached a settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.

The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of
Interior, alleging that the Government had breached its fiduciary duty concerning contract negotiations including
the Navajo Nation and the defendants.  In February 2000, the Court of Claims issued a decision in the
Government's favor, finding that while there had been a breach, there was no available redress from the
Government.  Following appeal of that decision by the Navajo Nation, an appellate court ruled that the Court of
Claims did have jurisdiction to award damages and remanded the case to the Court of Claims for that purpose.  On
June 3, 2002, the Government's request for review of the case by the United States Supreme Court was granted.
Briefing on this matter has been completed and argument is scheduled for December 2002.

SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint of the Navajo Nation's suit against the government, or the impact of the complaint on the
operation of Mohave beyond 2005.

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 generating stations 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

Page 12



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pay a maximum of $175 million per nuclear incident.  However, it would have to pay no more than $20 million per
incident in any one year.  Such amounts include a 5% surcharge if additional funds are needed to satisfy public
liability claims and are subject to adjustment for inflation.  If the public liability limit above is
insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.  The United States Congress is considering amendments to
the applicable federal law that could increase the liability of SCE in case of a nuclear incident.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and
Palo Verde.  Decontamination liability and property damage coverage exceeding the primary $500 million also has
been purchased in amounts greater than federal requirements.  Additional insurance covers part of replacement
power expenses during an accident-related nuclear unit outage.  A mutual insurance company owned by utilities
with nuclear facilities issues these policies.  If losses at any nuclear facility covered by the arrangement were
to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium
adjustments of up to $38 million per year.  Insurance premiums are charged to operating expense.

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest in Paiton Energy, which owns the Paiton project, a 1,230-MW
coal-fired power plant in Indonesia.  Under the terms of a long-term power purchase agreement between Paiton
Energy and the state-owned electric utility company, the state-owned electric utility company is required to pay
for capacity and fixed operating costs once each unit and the plant achieve commercial operation.

The state-owned electric utility company and Paiton Energy signed a binding term sheet on December 14, 2001, that
set the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a
monthly restructure settlement payment covering amounts owed by the state-owned electric utility company and the
settlement of other claims.  In addition, the binding term sheet extends the term of the power purchase agreement
from 2029 to 2040.  On June 28, 2002, Paiton Energy and the state-owned electric utility company concluded
negotiations on an amendment to the power purchase agreement that includes the agreed commercial terms in the
binding term sheet.  The binding term sheet serves as the basis under which the state-owned electric utility
company is paying Paiton Energy during 2002, while the parties complete certain actions, including approval by
Paiton Energy's lenders of the amendment to the power purchase agreement.  Such actions are required to be
completed by December 31, 2002.  Previously, the state-owned electric utility company and Paiton Energy entered
into agreements covering 2001.  The state-owned electric utility company has made all payments to Paiton Energy
as required under these agreements for 2001, which are superseded by the binding term sheet.  Paiton Energy
continues to generate electricity to meet the power demand in the region.  The state-owned electric utility
company has paid invoices for the months of January through August 2002, as well as the restructure settlement
payments due for the months of January through September 2002, as required under the binding term sheet and the
power purchase agreement.  Paiton Energy believes that the state-owned electric utility company will continue to
make payments for electricity under the binding term sheet while the parties work to complete the conditions
precedent to the effectiveness of the amendment to the power purchase agreement.  Under the binding term sheet,
past due accounts receivable under the original power purchase agreement are to be compensated through a monthly
restructuring settlement payment of $4 million for 30 years.  If the power purchase agreement amendment does not
become effective within 180 days of its signing, the parties would be entitled to revert to the terms and
conditions of the original power purchase agreement in order to pursue arbitration in an international forum.

EME's investment in the Paiton project increased to $516 million at September 30, 2002, from $492 million at
December 31, 2001.  The increase in the investment resulted from EME's subsidiary recording its proportionate share
of net income from Paiton Energy, as well as its proportionate share of other comprehensive income.  EME's
investment in the Paiton project will increase or decrease from earnings or

Page 13



EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

losses from Paiton Energy and decrease by cash distributions.  Assuming the Paiton project remains profitable, EME
expects the investment account to increase substantially during the next several years as earnings are expected to
exceed cash distributions.

As mentioned above, Paiton Energy and the state-owned electric utility company have completed negotiations on an
amendment to the power purchase agreement.  While the binding term sheet has been approved by the project
lenders, Paiton Energy has not yet obtained the approval of the amendment to the power purchase agreement by the
project lenders.  Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior
debt, which takes into account the revised payment terms contained in the amendment to the power purchase
agreement.  Paiton Energy, its government agency lenders and the commercial bank lenders have agreed to terms and
conditions for debt restructuring.  In addition, Paiton Energy must seek approval of the debt restructuring from
its bondholders.  Paiton Energy believes that the debt restructuring will receive the necessary approvals from
the bondholders.  Therefore, EME believes that it will ultimately recover its investment in the project.

PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, has reinstated the pending
arbitration to resolve disputes under the fuel supply agreement between BHP and Paiton Energy.  The arbitration
had been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal
supply chain for the Paiton project.  These discussions did not result in a settlement of all potential claims
with respect to the restructuring of the coal supply chain, and BHP recently requested that the arbitration
tribunal permit BHP to amend or supplement its statement of claims to assert additional claims against Paiton
Energy for breach and termination of the fuel supply agreement.  BHP's total claim, to date, is $250 million.

Paiton Energy has entered into settlement negotiations with BHP.  A settlement offer has been made, and BHP has
indicated that it may be willing to accept that offer, subject to the execution of acceptable documentation and
the timing of payment.  Such settlement is subject to Paiton Energy obtaining approval of its lenders.  EME
believes that the outcome of this arbitration will not have a material adverse effect on its consolidated
financial position or results of operations.

Spent Nuclear Fuel

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

SCE, as operating agent, has primary responsibility for the interim storage of its spent nuclear fuel at
San Onofre.  The San Onofre Units 2 and 3 spent fuel pools currently contain San Onofre Unit 1 spent fuel in
addition to spent fuel from Units 2 and 3.  Current capability to store spent fuel in the Units 2 and 3 spent
fuel pools is adequate through 2005.  SCE plans to move the Unit 1 spent fuel to an interim spent fuel storage
facility by the first quarter of 2005.  The spent fuel pool storage capacity for Units 2 and 3 will then
accommodate needs until 2007 for Unit 2 and 2008 for Unit 3.  SCE expects to begin using an interim spent fuel
storage facility for Units 2 and 3 spent fuel by early 2006.  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, expects to begin using an interim spent fuel storage facility by the end of 2002.


Page 14


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Storm Lake

As of September 30, 2002, Edison Capital had an investment of approximately $84 million in Storm Lake Power, a
project developed by Enron Wind, a subsidiary of Enron Corporation.  As of September 30, 2002, Storm Lake had
outstanding loans of approximately $69 million.  Enron and its subsidiary provided certain guarantees related to
the amount of power that would be generated from Storm Lake.  The lenders have sent a notice to Storm Lake
claiming that Enron's bankruptcy, among other things, is an event of default under the loan agreement.  In the
event of default, the lenders may exercise certain remedies, including acceleration of the loan balance,
repossession and foreclosure of the project, which could result in the loss of some or all of Edison Capital's
investment in Storm Lake.  While expressly reserving their rights, the lenders have not taken any steps to
exercise their remedies beyond issuing the notices of default.  On behalf of Storm Lake, Edison Capital is also
engaged in regular, ongoing discussions with the lenders in which Edison Capital expects to demonstrate to the
lenders that Storm Lake's ability to meet its loan obligations is not impaired, and that the noticed events of
default can be worked out with the lenders.  Edison Capital believes that Storm Lake will vigorously oppose any
attempt by the lenders to exercise remedies that could result in a loss of Edison Capital's investment.



Note 5.  Business Segments

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

Segment information for the three and nine months ended September 30, 2002, and 2001, was:

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

     In millions                                              2002           2001          2002         2001
--------------------------------------------------------------------------------------------------------------

                                                                                (Unaudited)
     Operating Revenue:
     Electric utility                                      $ 2,864       $  2,725      $  6,957     $  5,826
     Nonutility power generation                             1,094          1,095         2,451        2,406
     Financial services                                         35             40            81          155
     Corporate and other                                         4             22            21          137
--------------------------------------------------------------------------------------------------------------

     Consolidated Edison International                     $ 3,997       $  3,882      $  9,510     $  8,524
--------------------------------------------------------------------------------------------------------------

     Net Income (Loss):
     Electric utility(1)                                   $   234       $    651      $  1,075     $     81
     Nonutility power generation(2)                            149         (1,026)          116       (1,018)
     Financial services                                         27             14            58           50
     Corporate and other(3)                                    (58)           (52)         (148)        (245)
--------------------------------------------------------------------------------------------------------------

     Consolidated Edison International                     $   352       $   (413)     $  1,101     $ (1,132)
--------------------------------------------------------------------------------------------------------------


(1)   Net income available for common stock.


(2)   Includes loss from discontinued operations of $91,000 for the three months ended September 30, 2002,
      earnings from discontinued operations of $3 million for the nine months ended September 30, 2002, and
      losses from discontinued operations of $1.2 billion for both the three and nine months ended
      September 30, 2001.

(3)   Includes earnings from discontinued operations of $1 million for both the three and nine months ended
      September 30, 2002, and losses from discontinued operations of $7 million and $134 million,
      respectively, for the three and nine months ended September 30, 2001.

Corporate and other primarily includes interest expense at the Edison International parent company and Mission
Energy Holding Company, parent company operating expenses and results from nonutility subsidiaries not
significant as a reportable segment.  Mission Energy Holding Company's net losses for the

Page 15


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

three and nine months ended September 30, 2002, were $24 million and $70 million, respectively, compared with $24
million for each of the same periods in 2001.

Total segment assets as of September 30, 2002, were:  electric utility, $19 billion; nonutility power generation,
$11 billion; and financial services, $4 billion.

Note 6.  Discontinued Operations

The results of EME's Fiddler's Ferry and Ferrybridge coal stations in the U.K. and Edison Enterprises'
subsidiaries sold during 2001 have been reflected as discontinued operations in the consolidated financial
statements, in accordance with the early adoption of an accounting standard related to the impairment and
disposal of long-lived assets.  The consolidated financial statements have been reclassified to conform to the
discontinued operations presentation for all periods presented.  For the nine months ended September 30, 2002,
revenue from discontinued operations was $3 million and for the three and nine months ended September 30, 2002,
pre-tax income was $1 million and $4 million, respectively.  For the three and nine months ended September 30,
2001, revenue from discontinued operations was $161 million and $600 million, respectively, and pre-tax loss was
$2.0 billion and $2.2 billion, respectively.

The carrying value of assets and liabilities of discontinued operations were:



                                                                   September 30,         December 31,
         In millions                                                   2002                  2001
----------------------------------------------------------------------------------------------------------

                                                                    (Unaudited)
         Assets
         Cash and equivalents                                        $    3               $    63
         Receivables - net                                                5                    89
         Other                                                            1                     2
----------------------------------------------------------------------------------------------------------

         Total current assets                                             9                   154
----------------------------------------------------------------------------------------------------------

         Other noncurrent assets                                         50                    51
----------------------------------------------------------------------------------------------------------

         Total assets                                                $   59               $   205
----------------------------------------------------------------------------------------------------------

         Liabilities
         Accounts payable and accrued liabilities                    $   32               $    59
         Short-term debt and other                                       --                     5
----------------------------------------------------------------------------------------------------------

         Total current liabilities                                       32                    64
         Noncurrent liabilities                                           7                     7
----------------------------------------------------------------------------------------------------------

         Total liabilities                                           $   39               $    71
----------------------------------------------------------------------------------------------------------





Note 7.  Subsequent Event

Employees at EME's Illinois plants in union-represented positions are covered by collective bargaining agreements
that are due to expire December 31, 2005.  These employees also had a retirement health care and other benefits
plan agreement that expired on June 15, 2002.  In October 2002, EME reached an agreement with its
union-represented employees on a new retirement health care and other benefits plan, which extends from
January 1, 2003, through June 30, 2005.  EME will continue to provide benefits at the same level as those in the
expired agreement until December 31, 2002.

EME has been accounting for postretirement benefits obligations on the basis of a substantive plan under an
accounting standard for postretirement benefits other than pensions.  A substantive plan means that EME is
assuming, for accounting purposes, that it would provide for postretirement benefits to union-represented
employees following conclusion of negotiations to replace the current benefits agreement, even though EME has no
legal obligation to do so.  Under the new agreement, postretirement benefits will not be provided.  Accordingly,
EME will treat this as a plan termination in accordance with this accounting standard and will record a pre-tax
gain of approximately $71 million during the fourth quarter of 2002.



Page 16









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

The Management's Discussion and Analysis of Results of Operations and Financial Condition (MD&A) for the three-
and nine-month periods ended September 30, 2002, discusses material changes in the results of operations,
financial condition and other developments of Edison International since December 31, 2001, and as compared to
the three- and nine-month periods ended September 30, 2001.  This discussion presumes that the reader has read or
has access to Edison International's MD&A for the calendar year 2001 (the year-end 2001 MD&A), which was included
in Edison International's 2001 annual report to shareholders and incorporated by reference into Edison
International's Annual Report on Form 10-K for the year ended December 31, 2001.

This MD&A contains forward-looking statements.  These statements are based on Edison International's knowledge of
present facts, current expectations about future events and assumptions about future developments.
Forward-looking statements are not guarantees of performance; they are subject to risks, uncertainties and
assumptions that could cause actual future activities and results of operations to be materially different from
those set forth in this discussion.  Important factors that could cause actual results to differ include, but are
not limited to, risks discussed below in the Financial Condition, Market Risk Exposures and Forward-Looking
Information and Risk Factors sections.  The following discussion provides information about material developments
since the issuance of the year-end 2001 MD&A and should be read in conjunction with the financial statements
contained in this quarterly report and Edison International's Annual Report on Form 10-K for the year ended
December 31, 2001.

This MD&A includes information about Edison International and its principal subsidiaries, Southern California
Edison Company (SCE), Edison Mission Energy (EME), Edison Capital and Mission Energy Holding Company (MEHC).
Edison International is a holding company.  SCE is a regulated public utility company providing electricity to
retail customers in central, coastal, and southern California.  EME is an independent power producer engaged in
owning or leasing and operating electric power generation facilities worldwide, and energy trading and price risk
management activities.  Edison Capital is a global provider of capital and financial services in energy,
affordable housing, and infrastructure projects focusing primarily on investments related to the production and
delivery of electricity.  MEHC was formed in June 2001, as a holding company for EME.  In this MD&A, except when
stated to the contrary, references to each of Edison International, SCE, MEHC, EME, or Edison Capital mean each
such company with its subsidiaries on a consolidated basis.  References to Edison International (parent) or
parent company mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.
References to SCE, MEHC, EME, or Edison Capital followed by stand alone mean each such company alone, not
consolidated with its subsidiaries.

CURRENT DEVELOPMENTS RELATED TO EME

Edison International's nonutility power generation subsidiary (EME) is now experiencing numerous changes in its
industry and business.  This section provides an introductory overview of those changes and their effects on EME.

A number of significant developments have adversely affected independent power producers and subsidiaries of
major integrated energy companies who sell a sizable portion of their generation into the wholesale energy market
(sometimes referred to as merchant generators).  These developments include depressed market prices in wholesale
energy markets, both in the United States and United Kingdom (U.K.), significant declines in the credit ratings
of most major market participants, and the decline of liquidity in the energy markets as a result of tightening
credit and increasing concern about the ability of counterparties to perform their obligations. In addition, many
merchant generators and power trading firms have announced plans to improve their financial position through
asset sales, the cancellation or deferral of substantial new development, significant reductions in or
elimination of trading activities, decreases in capital expenditures, including cancellations of orders for new
turbines, and reductions in operating costs.


Page 17



EME's Situation

Because of the 2000-2001 California power crisis, and its indirect effect on EME, EME began in early 2001 to
shift its emphasis from the development and acquisition of projects to focus instead on enhancing the performance
of its existing projects and on maintaining credit quality.  As a result, during 2001 and early 2002, EME
completed the sale of several non-strategic project investments, and, during the first quarter of 2002, further
reduced business development activities and undertook a related effort to reduce both corporate overhead and
other expenditures across the organization and reduce debt.

Notwithstanding these efforts in 2002, EME has been affected by lower wholesale prices of energy and capacity,
particularly at its Homer City facilities in Pennsylvania, and by the diminished ability to enter into forward
contracts for the sale of power primarily from these facilities because of the credit constraints affecting EME
and many of its counterparties.

EME's Illinois plants have been largely unaffected by these developments because Exelon Generation Company
(ExGen) is under contract to buy substantially all of the capacity of these units for the balance of 2002.
However, as permitted by the power purchase agreements, ExGen has advised EME that it will not purchase 2,684 MW
of the capacity from EME's coal-fired units and 1,864 MW of capacity from EME's Collins Station and small peaking
units for 2003 and 2004 and ExGen has the further right to release an additional 3,043 MW for 2004.  As a result,
beginning in 2003, the portion of EME's generation to be sold into the wholesale markets will significantly
increase, thereby increasing EME's merchant risk.  See the Illinois Plants discussion in Market Risk Exposures.

As a result of these and other factors, Moody's downgraded MEHC's credit rating, EME's credit rating and the
credit ratings of EME's largest subsidiary, Edison Mission Midwest Holdings, on October 1, 2002, as shown in the
following table:



                                                             Moody's Rating        Moody's Rating
                                                                prior to               after
Rated Entities                                                  Downgrade            Downgrade
--------------------------------------------------------- ---------------------- -------------------
--------------------------------------------------------- ---------------------- -------------------
Mission Energy Holding Company senior secured debt
                                                                   Ba2                   B3

Edison Mission Energy senior unsecured debt                       Baa3                  Ba3
Edison Mission Midwest Holdings Co. bank facility                 Baa2                  Ba2
--------------------------------------------------------- ---------------------- -------------------



In addition, Standard & Poor's has placed both MEHC's and EME's credit ratings on CreditWatch with negative
implications.  See discussion in EME's Liquidity Issues.

Against this background, EME has undertaken a number of actions to reduce its commitments and expenditures,
thereby improving EME's cash flow.  These actions include:

o        a reduction in EME's capital expenditure program by $363 million for the next five years as the result
         of the cancellation of an outstanding order for nine turbines and suspension of work on two selective
         catalytic reduction systems (commonly referred to as SCRs) for EME's Powerton Station;

o        suspension, beginning in January 2003, of operations at Units 1 and 2 of EME's Will County plant and
         Units 4 and 5 of EME's Collins Station in Illinois in order to reduce operating costs;

o        suspension of new business development activities; and

o        implementation of plans to reduce annual general and administrative expenses by $25 million.



Page 18



EME has also reduced its already modest non asset-backed trading activities in Boston, and focused almost
exclusively on the sale of power from its facilities and related risk management activities.

In addition, EME continues to review the possibility of sales of assets, but believes that current market
conditions may inhibit its ability to obtain prices commensurate with its valuation of those investments that EME
might offer for sale.  For a discussion of EME's current financial condition, see EME's Liquidity Issues.



RESULTS OF OPERATIONS

Edison International's earnings per share were $1.08 and $3.38, respectively, for the three and nine months ended
September 30, 2002, compared with losses of $1.27 and $3.47, respectively, for the three and nine months ended
September 30, 2001.  The table below presents Edison International's net income and earnings per share for the
three and nine months ended September 30, 2002, and September 30, 2001, and the relative contributions by its
subsidiaries.

     In millions, except per share amounts                       EPS                    Net Income
--------------------------------------------------------------------------------------------------------

       Three Months Ended September 30,                   2002         2001         2002         2001
--------------------------------------------------------------------------------------------------------

     Earnings (Loss) from Continuing Operations:
     Core Earnings:
         SCE                                            $  0.72      $  0.41       $ 234      $   133
         EME                                               0.46         0.55         149          180
         Edison Capital                                    0.08         0.05          27           14
         Mission Energy Holding Company (stand alone)     (0.07)       (0.08)        (24)         (24)
         Edison International (parent) and other          (0.11)       (0.06)        (35)         (20)
--------------------------------------------------------------------------------------------------------

     Edison International Core Earnings                    1.08         0.87         351          283
     SCE procurement-related adjustment                     --          1.59          --          518
--------------------------------------------------------------------------------------------------------

     Edison International Consolidated Earnings
         from Continuing Operations                        1.08         2.46         351          801
--------------------------------------------------------------------------------------------------------

     Earnings (Loss) from Discontinued Operations          --          (3.73)          1       (1,214)
--------------------------------------------------------------------------------------------------------

     Edison International Consolidated                  $  1.08      $ (1.27)      $ 352      $  (413)
--------------------------------------------------------------------------------------------------------


       Nine Months Ended September 30,                    2002         2001         2002         2001
--------------------------------------------------------------------------------------------------------

     Earnings (Loss) from Continuing Operations:
     Core Earnings:
         SCE                                            $  1.83      $  0.88      $  595      $   287
         EME                                               0.35         0.65         113          211
         Edison Capital                                    0.18         0.15          58           50
         Mission Energy Holding Company (stand alone)     (0.22)       (0.08)        (70)         (24)
         Edison International (parent) and other          (0.24)       (0.26)        (79)         (89)
--------------------------------------------------------------------------------------------------------

     Edison International Core Earnings                    1.90         1.34         617          435
     SCE procurement-related adjustment                     --         (0.63)         --         (205)
     SCE implementation of URG decision                    1.47          --          480           --
--------------------------------------------------------------------------------------------------------

     Edison International Consolidated Earnings
         from Continuing Operations                        3.37         0.71       1,097          230
--------------------------------------------------------------------------------------------------------

     Earnings (Loss) from Discontinued Operations          0.01        (4.18)          4       (1,362)
--------------------------------------------------------------------------------------------------------

     Edison International Consolidated                  $  3.38      $ (3.47)    $ 1,101     $ (1,132)
--------------------------------------------------------------------------------------------------------



Earnings (Loss) from Continuing Operations

Edison International's third quarter 2002 earnings from continuing operations were $351 million, compared with
earnings of $801 million for third quarter 2001; year-to-date 2002 earnings from continuing operations were $1.1
billion, compared with earnings of $230 million in 2001.

In 2002, SCE's third quarter and year-to-date earnings were $234 million and $1.1 billion, respectively, compared
to earnings of $651 million and $81 million, respectively, for the three and nine months ended September 30,
2001.  The 2002 year-to-date earnings include a $480 million one-time gain in the second

Page 19


quarter to reflect the implementation of a California Public Utilities Commission (CPUC) decision in SCE's
utility-retained generation (URG) proceeding.  In 2001, SCE's third quarter and year-to-date earnings included
$518 million and $(205) million, respectively, in procurement-related adjustments for undercollected power
procurement costs.  Excluding these adjustments, SCE's third quarter and year-to-date earnings for the periods
ended September 30, 2002, were $234 million and $595 million, respectively, compared to earnings of $133 million
and $287 million, respectively, for the three and nine months ended September 30, 2001.  Excluding these
adjustments, the $101 million increase in SCE's third quarter 2002 earnings and the $308 million increase in
year-to-date 2002 earnings primarily reflects higher revenue from the implementation of the CPUC's April 2002
decisions in SCE's performance-based ratemaking (PBR) proceeding and URG proceeding and lower interest expense.
The increases were partially offset by higher operating and maintenance expense.  The quarterly increase also
reflects rewards from SCE's prior year's performance under its PBR mechanism.  The year-to-date increase also
reflects increased income from San Onofre Nuclear Generating Station Units 2 and 3, partially offset by higher
depreciation expense.  Relevant regulatory proceedings are discussed below in the PROACT Regulatory Asset, URG
Decision and PBR Decision sections.

Accounting principles generally accepted in the United States require SCE, at each financial statement date, to
assess the probability of recovering its regulatory assets through the rate-making process.  As of December 31,
2000, SCE was unable to conclude that, under applicable accounting principles, its $4.2 billion generation and
procurement-related regulatory assets were probable of recovery through the rate-making process, and wrote them
off as a charge to earnings in 2000.  In the first nine months of 2001, SCE had $205 million (after tax) of power
procurement costs in excess of revenue, which were expensed as incurred.

Based on the CPUC's January 23, 2002, resolution regarding the regulatory accounting for PROACT, as of December
31, 2001, SCE was able to conclude that $3.6 billion in regulatory assets previously written off were probable of
recovery through the rate-making process.  As a result, SCE's year-ended December 31, 2001, consolidated income
statement included a $2.1 billion credit to earnings.  In 2002, any difference between energy procurement costs
and related revenue is accumulated in the PROACT balance.  See additional discussion below in the CPUC Litigation
Settlement Agreement section.

EME had earnings from continuing operations of $149 million and $113 million, respectively, for the quarter and
year-to-date period ended September 30, 2002, compared to earnings of $180 million and $211 million,
respectively, for the same periods in 2001.  The decreases were primarily due to write-offs of capitalized costs
and lower U.S. energy prices in 2002 compared to 2001, partially offset by lower state income taxes, improved
operating results at EME's Illinois plants and income from the Paiton project in Indonesia.  The decreases in
2002 were also due to gains in 2001 related to accounting for derivatives.  The year-to-date decrease in 2002 was
also due to unplanned outages at the Homer City plant and gains related to gas swaps from EME's oil and gas
activities in 2001, partially offset by improved operating results at the ISAB project in Italy.  EME's earnings
are seasonal with higher earnings generally expected during the summer months and operating losses expected
during the fall and winter months.

Edison Capital's third quarter and year-to-date 2002 earnings were $27 million and $58 million, respectively,
compared to $14 million and $50 million, respectively, for the three and nine months ended September 30, 2001.
The increases are primarily the result of lower state income taxes and interest expense, partially offset by the
lack of asset sales in 2002.

Mission Energy Holding (stand alone), which was formed in mid-2001 as a wholly owned indirect subsidiary of
Edison International to hold the stock of EME, reported losses of $24 million and $70 million, respectively, for
the three- and nine-month periods ending September 30, 2002, compared to a loss of $24 million for both the
three- and nine-month periods ending September 30, 2001.  The losses are the result of interest expense on debt
issued in mid-2001, the proceeds of which were used to repay Edison International's debt.

Edison International (parent) and other incurred losses of $35 million and $79 million, respectively, in the
three and nine months ended September 30, 2002, compared to losses of $20 and $89 million for the

Page 20


same periods in 2001.  The increased third quarter loss in 2002 was mostly due to a loss at Edison
International's insurance subsidiary due to a premium refund to EME and an asset impairment charge and lower
billable hours at a nonutility subsidiary providing operation and maintenance services.  The improvement in the
year-to-date period in 2002 was primarily due to lower interest expense, partially offset by the insurance
subsidiary loss and asset impairment charge mentioned above.

Operating Revenue

Approximately 96% 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).

Electric utility revenue increased for the three and nine months ended September 30, 2002, compared to the same
periods in 2001.  The increase for the three months ended September 30, 2002, was primarily due to an increase in
overall sales volume, as well as an increase in revenue resulting from SCE providing its customers with energy
from its own generating plants and power purchase contracts, rather than the California Department of Water
Resources (CDWR) purchasing power on behalf of SCE's customers.  Amounts SCE bills to and collects from its
customers for electric power purchased and sold by the CDWR to SCE's customers (beginning January 17, 2001) are
being remitted to the CDWR and are not recognized as revenue by SCE.  These amounts were $326 million and $922
million for the three- and nine-month periods ended September 30, 2002, compared to $642 million and $1.4 billion
for the three- and nine-month periods ended September 30, 2001.  The increase in electric utility revenue was
partially offset by a decrease in revenue arising from an increase in credits given to direct access customers in
2002, compared to 2001, due to a significant increase in the number of direct access customers.  The increase for
the nine months ended September 30, 2002, compared to the same period in 2001, was also due to a 3(cent)-per-kWh
surcharge authorized by the CPUC as of March 27, 2001.  Although the surcharge was authorized as of March 27,
2001, it was not collected in rates until the CPUC determined how the rate increase would be allocated among
SCE's customer classes, which occurred in May 2001.  To compensate for the two-month delay in collecting the 3(cent)
surcharge, the CPUC authorized an additional $0.006 surcharge for a 12-month period beginning in June 2001, which
contributed to the increase in revenue.  Subsequently, the CPUC allowed the continuation of the $0.006 surcharge
that was scheduled to terminate in June 2002 and required SCE to track the associated future revenue in a
balancing account, until the CPUC determines the use of such surcharge.  The continuation of the surcharge will
result in an increase to revenue and cash by as much as $200 million in 2002, but will have no impact on earnings
(see Temporary Surcharge).  In addition, SCE's revenue was higher due to SCE providing its customers with a
greater volume of energy generated from its own generating plants and power purchase contracts, rather than the
CDWR purchasing on SCE's customers behalf, partially offset by increase in credits given to direct access
customers in 2002.

With respect to increase in credits given to direct access customers in the three and nine months ended
September 30, 2002, from 1998 through mid-September 2001, SCE's customers were able to choose to purchase power
directly from an energy service provider other than SCE (thus becoming direct access customers) or continue to
have SCE purchase power on their behalf.  On March 21, 2002, the CPUC issued a decision affirming that new direct
access arrangements entered into by SCE's customers after September 20, 2001, are invalid.  Direct access
arrangements entered into prior to September 20, 2001, remain valid.  Most direct access customers continue to be
billed by SCE, but are given a credit for the generation costs SCE saved by not serving them.  Electric utility
revenue is reported net of this credit.  See additional discussion on the Direct Access - Historical Procurement
Charge in the Direct Access Proceedings section below.

Nonutility power generation revenue increased for the nine months ended September 30, 2002, compared to the same
period in 2001, primarily due to increases at EME related to the consolidation of Contact Energy effective June
1, 2001, as a result of increasing ownership to majority control (51%) and higher electric revenue from the First
Hydro and Midwest Illinois plants.  These increases were partially offset by decreases at EME due to lower U.S.
energy prices in 2002 compared to 2001, unplanned outages at the

Page 21


Homer City plant, lower income from its investment in cogeneration projects and lower income from its oil and gas
activities.

Electric power generated at EME's Illinois plants is sold under agreements with ExGen.  ExGen is obligated to
make capacity payments for the Illinois plants under contract and an energy payment for electricity produced by
these plants.  EME's revenue under these agreements was $521 million and $957 million, for the three and nine
months ended September 30, 2002, representing 48% and 39% of nonutility power generation revenue for the
respective periods, and $487 million and $912 million for the three and nine months ended September 30, 2001,
representing 45% and 38% of nonutility power generation revenue for the respective periods.  See Illinois Plants
discussion in the Market Risk Exposures section.

Due to warmer weather during the summer months, EME's nonutility power generation revenue from the Homer City
facilities and the Illinois plants is usually higher during the third quarter of each year.  In addition, EME's
third quarter income from its investment in cogeneration projects is materially higher than other quarters of the
year due to higher summer pricing under contracts held by EME's West Coast partnership investments.  EME's First
Hydro plants are expected to provide higher revenue during the winter months.

Financial services and other revenue decreased for both the quarter and year-to-date periods ended September 30,
2002, primarily from Edison Capital's decrease in earning assets, no significant asset sales in 2002, and the
impact of adopting the equity method of accounting in conformance with the infrastructure funds accounting
policies.  The decreases were also the result of the termination of a major contract at a nonutility subsidiary
providing operation and maintenance services and another subsidiary's sale of nonutility real estate in 2001.

Operating Expenses

Fuel expense increased for the three and nine months ended September 30, 2002, as compared to 2001.  The increase
for the quarter was primarily due to higher fuel costs at EME's Illinois plants due to increased generation.  The
nine-month increase was primarily related to EME's consolidation of Contact Energy, partially offset by lower
fuel costs at its Homer City facilities due to decreased generation from the outages in 2002.

Purchased-power expense decreased significantly for the nine-month period ended September 30, 2002, as compared
to 2001.  The decrease resulted primarily from lower expenses at SCE related to qualifying facilities (QFs),
bilateral contracts and interutility contracts, as discussed below.  In addition, the decrease reflects the
absence of California Power Exchange (PX)/Independent System Operator (ISO) purchased-power expense after
mid-January 2001.  See Purchased Power table in Note 3 to the Consolidated Financial Statements in this quarterly
report.

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated
prices.  These contracts expire on various dates through 2025.  In 2002, purchased-power expense declined
significantly, primarily due to lower payments to QFs.  Generally, energy payments for gas-fired QFs are tied to
spot natural gas prices.  Effective May 2002, energy payments for renewable QFs are based on a fixed price.
During the first nine months ended September 30, 2002, spot natural gas prices were significantly lower than the
same periods in 2001.  The decrease in 2002 purchased-power expense related to bilateral contracts and
interutility contracts was also due to the decrease in natural gas prices.

PX/ISO purchased-power expense increased significantly between May 2000 and mid-January 2001, due to a number of
factors, including increased demand for electricity in California, dramatic price increases for natural gas (a
key input of electricity production), and problems in the structure and conduct of the PX and ISO markets.  In
December 2000, the FERC eliminated the requirement that SCE buy and sell all power through the PX and ISO.  Due
to SCE's noncompliance with the PX's tariff requirement for posting collateral for all transactions, as a result
of the downgrades in its credit rating, the PX suspended SCE's

Page 22


market trading privileges effective mid-January 2001.  Although SCE has not purchased power from the PX since
mid-January 2001, SCE continues to receive adjusting invoices for power purchased through the PX/ISO prior to
mid-January 2001.

Provisions for regulatory adjustment clauses - net increased for both the quarter and year-to-date ended
September 30, 2002, compared to the same periods in 2001.  The third quarter increase was primarily due to
overcollections related to the difference between SCE's revenue from retail electric rates (including surcharges)
and the costs that SCE is authorized by the CPUC to recover in retail electric rates used to reduce the PROACT
balance, as well as revenue collected to recover the rate reduction bond regulatory asset.  The year-to-date
increase was primarily due to overcollections used to recover the PROACT balance and revenue collected to recover
the rate reduction bond regulatory asset, partially offset by the impact of SCE's implementation of CPUC
decisions related to URG and the PBR mechanism, as well as the impact of other regulatory actions.

As a result of the URG decision, SCE reestablished regulatory assets previously written off (approximately $1.1
billion) related to its nuclear plant investment, purchased-power settlements and flow through taxes, and
decreased the PROACT balance by $256 million, all retroactive to January 1, 2002.  The impact of the URG decision
is reflected in the financial statements as a credit (decrease) to the provisions for regulatory adjustment
clauses of $644 million, partially offset by an increase in deferred income tax expense of $164 million, for a
net credit to earnings of $480 million  (see URG Decision discussion).  As a result of the CPUC decision that
modified the PBR mechanism, SCE recorded a $136 million credit (increase) to the provisions for regulatory
adjustment clauses in the second quarter of 2002, to reflect undercollections in CPUC-authorized revenue
resulting from changes in retail rates (see PBR Decision discussion).

Other operating and maintenance expense increased for the three months ended September 30, 2002, compared to
2001.  The increase was primarily due to increases at both SCE and EME.

SCE's increase for the three-month period ended September 30, 2002, compared to the same period in 2001, was
primarily due to the San Onofre Unit 2 refueling outage in 2002, and increases in transmission and distribution
maintenance costs, partially offset by lower expenses related to balancing accounts.

EME's operating and maintenance expense increased for the quarter, primarily due to an increase in lease costs
related to the December 7, 2001, sale-leaseback for its Homer City plant, and write-offs of capitalized costs in
the third quarter of 2002, including $61 million associated with terminating agreements to purchase turbines from
Siemens Westinghouse, and $25 million related to suspension of a capital environmental improvements project at
EME's Illinois plants.  These increases were partially offset by lower plant costs resulting from higher
maintenance costs in 2001 from planned outages and costs of additional security related to a strike at the
Illinois plants during the third quarter of 2001.

Employees at EME's Illinois plants in union-represented positions are covered by collective bargaining agreements
that are due to expire December 31, 2005.  These employees also had a retirement health care and other benefits
plan agreement that expired on July 15, 2002.  In October 2002, EME reached an agreement with the
union-represented employees on a new retirement health care and other benefits plan, which extends from January
1, 2003, through June 30, 2005.  EME will continue to provide benefits at the same level as those in the expired
agreement until December 31, 2002.  EME has accounted for postretirement benefits obligations on the basis of a
substantive plan under an accounting standard for postretirement benefits other than pensions.  A substantive
plan means that EME is assuming for accounting purposes that it would provide for postretirement benefits to
union-represented employees following conclusion of negotiations to replace the current benefits agreement, even
though EME has no legal obligation to do so.  Under the new agreement, postretirement benefits will not be
provided.  Accordingly, EME will treat this as a plan termination in accordance with this accounting standard and
will record a pre-tax gain of approximately $71 million during the fourth quarter of 2002.

Depreciation, decommissioning and amortization expense increased for the nine months ended September 30, 2002, as
compared to 2001, mainly due to an increase in depreciation expense associated with SCE's additions to
transmission and distribution assets and an increase in SCE's nuclear

Page 23


decommissioning expense.  A 1994 CPUC decision allowed SCE to accelerate the recovery of its nuclear-related
assets while deferring the recovery of its distribution-related assets for the same amount.  Beginning in January
2002, the CPUC approved the commencement of recovery of SCE's deferred distribution asset.  In addition, the
increases reflect amortization expense on the nuclear regulatory asset reestablished during second quarter 2002
based on the URG decision (discussed below).  These increases were partially offset by lower depreciation expense
at EME's Homer City plant due to the sale-leaseback transaction that took place in December 2001, as well as
ceasing the amortization of goodwill in January 1, 2002.  Edison Capital had a decrease in amortization as a
result of a change from the cost method to the equity method of accounting for its fund investments.

Property and other taxes increased for the nine-month period ended September 30, 2002, compared to the same
period in 2001, due to a reclassification at EME of foreign and domestic property taxes from plant operation
expense.

Other Income and Deductions

Interest and dividend income increased for the nine-month period ended September 30, 2002, compared to the same
period in 2001.  The increases were mainly due to the interest income earned on the PROACT balance at SCE.  The
increases were partially offset by lower interest income due to lower average cash balances and lower interest
rates at SCE, EME and Edison Capital during 2002, as compared to 2001, as well as a change at Edison Capital from
the cost to equity method of accounting for its fund investments.

Other nonoperating income decreased for both the three and nine months ended September 30, 2002, compared to the
year-earlier periods.  The decreases were primarily related to foreign exchange losses on intercompany loans
during 2002 at EME, as well as a gain on sale of EME's interest in energy projects in 2001 and no sales in 2002.

Interest expense - net of amounts capitalized decreased for the three and nine months ended September 30, 2002,
mainly due to lower short-term debt balances at SCE, EME and Edison Capital and lower long-term debt balances at
EME during 2002, as well as lower interest expense related to the suspension of purchased power at SCE in 2001.
The decrease was partially offset by an increase in interest expense on long-term debt due to higher long-term
debt balances at SCE, the MEHC debt financing in July 2001, and the consolidation of Contact Energy at EME.

Income Taxes

Income tax expense decreased for the three-month period ended September 30, 2002, and increased for the
nine-month period ended September 30, 2002.  The quarterly tax expense was lower in 2002, compared to 2001, as
2001 pre-tax income included recovery of previously undercollected costs.  In addition, EME and Edison Capital
recorded additional state income tax benefits during the quarter.  The year-to-date increase was primarily due to
an increase in pre-tax income, partially offset by the reestablishment of tax-related regulatory assets upon
implementation of the URG decision at SCE.  The effective tax rate for both periods is lower than the statutory
tax rate.  The quarterly effective tax rate is lower due to the benefit of lower foreign tax rates at EME and the
benefit of low-income housing credits at Edison Capital.  In addition, the year-to-date effective tax rate is
lower due to the reestablishment of tax-related regulatory assets upon the implementation of the URG decision at
SCE.

Earnings (Loss) from Discontinued Operations

Edison International's discontinued operations represent operating losses and the impact of the sale of EME's
Ferrybridge and Fiddler's Ferry coal stations and the majority of the Edison Enterprises (a nonutility subsidiary
of Edison International that formerly provided retail services) businesses.  Edison International recorded losses
from discontinued operations of $1.2 billion and $1.4 billion, respectively, for the three- and nine-month
periods ended September 30, 2001.  EME recorded losses from discontinued operations of $1.2 billion during both
periods at the Ferrybridge and Fiddler's Ferry coal stations located in the U.K.  Edison Enterprises recorded
losses from discontinued operations of $7 million and $134 million,

Page 24


respectively, for the three- and nine-month periods ended September 30, 2001, reflecting operating losses and an
impairment charge from the sale of the majority of its assets.

FINANCIAL CONDITION

The liquidity of Edison International is affected primarily by debt maturities, access to capital markets,
dividend payments, capital expenditures, lease obligations, asset purchases and sales, investments in
partnerships and unconsolidated subsidiaries, credit ratings, utility regulation and energy market conditions.
Capital resources primarily consist of cash from operations, asset sales and external financings.  California law
prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.

As a result of recent developments at EME (as discussed below), the fair market value of Edison International's
consolidated long-term debt was approximately 81% of its carrying value at September 30, 2002, compared to
approximately 89% at December 31, 2001.

At September 30, 2002, Edison International's principal subsidiaries had $417 million of borrowing capacity
available under lines of credit totaling $787 million.  SCE has drawn on its entire $300 million line of credit,
which expires March 2004.  In September 2002, EME entered into a new $275 million credit facility as a
replacement of its existing facility.  EME had borrowing capacity of $417 million available to finance general
cash requirements, under its total lines of credit of $487 million, which includes a one-year $275 million
component that expires September 2003, and a three-year $212 million component that expires September 2004.  The
lines of credit, when available, could be drawn down at bank index rates.  In April 2002, Edison Capital
terminated its bank facility after paying it off in full.

The parent company's short-term and long-term debt has been used for general corporate purposes, including
investments in its subsidiaries' business activities.  The parent company currently has no short-term debt
outstanding.  EME's short-term and long-term debt was used to finance acquisitions and development, and is
currently used for general corporate purposes.  MEHC's long-term debt was used to retire some of Edison
International's debt.  Edison Capital's short-term and long-term debt has been used for general corporate
purposes, as well as investments.  SCE's short-term debt is currently used to finance procurement-related
obligations.  Long-term debt is used mainly to finance capital expenditures.  External financings are influenced
by market conditions and other factors.

SCE's Liquidity Issues

Sustained high wholesale energy prices from May 2000 through June 2001 and a freeze on retail rates resulted in
significant undercollections of wholesale power costs.  These undercollections, 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, materially and adversely
affected SCE's liquidity throughout 2001.  As a result of its liquidity concerns, beginning in January 2001, SCE
suspended payments for purchased power, deferred payments on outstanding debt, and did not declare or pay
dividends on any of its cumulative preferred stock or common stock.

In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE.  Based on the rights
to power procurement cost recovery and revenue established by the agreement and the PROACT resolution, SCE repaid
its undisputed past-due obligations and near-term debt maturities in March 2002, using cash on hand resulting
from rate increases approved by the CPUC in 2001, and the proceeds of $1.6 billion in senior secured credit
facilities and the remarketing of $196 million in pollution-control bonds.  The $1.6 billion financing included a
$600 million, one-year term loan, due on March 3, 2003.  SCE prepaid $300 million of this loan on August 14, 2002.

At September 30, 2002, SCE had cash of $1.3 billion.  SCE expects to meet its continuing obligations in 2002 from
cash on hand and operating cash flows.  Material factors affecting the timing of recovery of the PROACT balance
are discussed below in PROACT Regulatory Asset.  In 2003, SCE's significant debt maturities are approximately
$1.7 billion, comprising of $1 billion in variable rate notes due November 2003, the remaining $300 million ($300
million was prepaid in August 2002) of a one-year term loan due

Page 25


March 2003, $125 million in first and refunding mortgage bonds due June 2003 and approximately $250 million of
rate reduction notes due throughout 2003.  After 2002, SCE's liquidity may be affected by, among other things,
matters described in the CPUC Litigation Settlement Agreement, the CDWR Revenue Requirement Proceeding and the
Generation Procurement Proceeding sections.  The CPUC has ordered SCE to resume procurement of its residual net
short on January 1, 2003.  SCE expects to post collateral to secure its obligations under power purchase
contracts and to transact through the ISO for imbalance power.  See the discussion of SCE under Market Risk
Exposures below.

EME's Liquidity Issues

EME's Credit Ratings

On October 1, 2002, Moody's downgraded EME's senior unsecured rating to Ba3 (below investment grade) from Baa3
(investment grade), and the ratings of its wholly owned indirect subsidiaries, Edison Mission Midwest Holdings
Co. (bank facility to Ba2 from Baa2) and Midwest Generation, LLC (lessor bonds to Ba3 from Baa3).  The ratings
remain under review for possible further downgrade.  On October 10, 2002, Standard & Poor's placed the BBB-
corporate ratings of EME, Edison Mission Midwest Holdings Co., and Edison Mission Marketing & Trading Inc. on
CreditWatch with negative implications.

These ratings actions did not trigger any defaults under EME's credit facilities or those of the other affected
entities; however, the changed ratings will increase the borrowing costs under certain of those facilities.  For
interest payments on EME's corporate credit facility, the applicable margin as determined by EME's long-term
credit ratings increased for Tranche A (to LIBOR + 3.625% from LIBOR + 2.375%) and Tranche B (to LIBOR + 3.50%
from LIBOR + 2.25%).  In addition to the interest payments, the facility fee as determined by EME's long-term
credit ratings increased for Tranche A (to 0.875% from 0.625%) and Tranche B (to 1.00% from 0.75%).  EME
estimates its annual interest and lease costs will increase by $37 million as a result of the downgrade of EME's
credit rating based on existing debt and lease agreements.

As a result of these rating actions, EME has:
o        provided additional collateral in the form of letters of credit ($5 million as of November 7, 2002, and
         EME could be required to provide additional such collateral in the future) for the benefit of
         counterparties in its price risk management and domestic trading activities related to accounts
         receivable and unrealized losses; and
o        posted a $42 million letter of credit to support the remaining portion of EME's obligation in connection
         with EME's acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd. project in the
         Philippines.

Moreover, as a result of these ratings actions, EME could be required by market practice and contract to provide
collateral for its U.K. trading activities.  To this end, EME's subsidiary, Edison Mission Operation and
Maintenance Limited, has obtained a credit facility in the amount of(pound)17 million, under which letters of credit
totaling(pound)11 million have been issued as of October 17, 2002.  EME also anticipates that sales of power from its
Illinois plants, Homer City facilities and First Hydro plants in the U.K. may require additional credit support
over the next twelve months, depending upon market conditions and the strategies adopted for the sale of this
power.  Changes in forward market prices and margining requirements could further increase the need for credit
support for EME's risk management and trading activities.  EME currently projects the potential working capital
to support its price risk management and trading activity to be between $100 million and $200 million from time
to time over the next twelve months.

Downgrade of Edison Mission Midwest Holdings
--------------------------------------------

As a result of the downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the
agreements binding on Edison Mission Midwest Holdings and Midwest Generation will limit the ability of Edison
Mission Midwest Holdings to use excess cash flow to make distributions to EME.  The following

Page 26


table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the
related changes in the cost of borrowing by Edison Mission Midwest Holdings under the applicable financing
agreements.  The currently applicable provisions are those set forth in the same row as the Moody's rating Ba2.



           S&P Rating         Moody's Rating         Cost of                        Cash Trap
                                                    Borrowing
                                                     Margin
       -------------------- -------------------- ---------------- ----------------------------------------------
       -------------------- -------------------- ---------------- ----------------------------------------------
                                                    (based on
                                                     LIBOR)

         BBB- or higher       Baa3 or higher           150        No cash trap
               BB+                  Ba1                225        50% free cash trapped until six month
                                                                  debt service reserve is funded
               BB                   Ba2                275        100% of free cash trapped
               BB-                  Ba3                325        100% of free cash trapped
               B+                   B1                 325        100% cash sweep by lenders to repay debt
                                                                  (i.e., 100% of free cash trapped and used to
                                                                  repay debt)
       -------------------- -------------------- ---------------- ----------------------------------------------



As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds
($1.4 billion) to EME in exchange for promissory notes in the same aggregate amount.  Debt service payments by
EME on the promissory notes are used by Midwest Generation to meet its payment obligations under these leases.
Furthermore, EME has guaranteed the lease obligations of Midwest Generation under these leases.  EME's
obligations under the promissory notes payable to Midwest Generation are general obligations of EME and are not
contingent upon receiving distributions from Edison Mission Midwest Holdings.  See Edison Mission Midwest
Holdings (Illinois plants) in EME's Liquidity section for a discussion of implications for the Powerton and
Joliet leases.

As a result of the downgrade of EME's subsidiary, Edison Mission Midwest Holdings, to Ba2, provisions in the
agreements binding on Edison Mission Midwest Holdings require it to deposit each quarter 100% of its defined
excess cash flow into a cash flow recapture account held and maintained by the collateral agent.  On October 31,
2002, Edison Mission Midwest Holdings deposited $50 million into the cash flow recapture account in accordance
with these provisions. Edison Mission Midwest Holdings will be required to make deposits into the cash flow
recapture account at the end of each such quarter in an amount equal to that quarter's excess cash flow.  The
funds in the cash flow recapture account may be used only to meet debt service obligations of Edison Mission
Midwest Holdings if funds are not otherwise available from working capital.

Possible Downgrade of Edison Mission Marketing & Trading
--------------------------------------------------------

Pursuant to the Homer City sale-leaseback documents, a downgrade of Edison Mission Marketing & Trading to below
investment grade would restrict the ability of EME Homer City Generation to sell forward the output of the Homer
City facilities.  Under the sale-leaseback documents, EME Homer City Generation may only engage in permitted
trading activities as defined in the documents.  These documents include a requirement that the counterparty to
such transactions, and EME Homer City Generation, if acting as seller to an unaffiliated third party, be
investment grade.  EME currently sells all of the output from the Homer City facilities through Edison Mission
Marketing & Trading, and EME Homer City Generation is not rated.  Therefore, in order for EME to continue to sell
forward the output of the Homer City facilities in the event of a downgrade in Edison Mission Marketing &
Trading's credit, either:  (1) EME must obtain a waiver from the sale-leaseback owner participant to permit EME
Homer City Generation to sell directly into the market or through Edison Mission Marketing & Trading; or (2)
Edison Mission Marketing & Trading must provide assurances of performance consistent with the investment grade
requirements of the sale-leaseback documents.  EME has obtained a consent from the sale-leaseback owner
participant that will allow EME Homer City Generation to enter into limited amounts of such sales, under
specified conditions, through September 25, 2003.  EME is permitted to sell the output of the Homer City
facilities into the

Page 27


Pennsylvania-New Jersey-Maryland Power Pool (PJM) at any time.  See Homer City Facilities discussion in Market
Risk Exposures.

EME Corporate Liquidity

EME has a $487 million corporate credit facility which includes a one-year $275 million component, Tranche A,
that expires on September 16, 2003, and a three-year $212 million component, Tranche B, that expires on September
17, 2004.  At September 30, 2002, EME had borrowing capacity under this facility of $417 million and corporate
cash and cash equivalents of $67 million.  EME plans to utilize the corporate credit facilities to fund corporate
expenses, including interest, during 2002, as necessary depending on the timing and amount of distributions from
its subsidiaries.  During the first quarter of 2002, cash flow included distributions from EME's investments in
partnerships made subsequent to their receipt of payments of past due accounts receivable from SCE on March 1,
2002.  Total amounts paid to these partnerships by SCE were $415 million, of which EME's share was $206 million.
In addition, EME received $368 million in tax-allocation payments from its ultimate parent company.  These and
cash distributions from its subsidiaries represent the major source of cash of EME to meet its cash
requirements.  The timing and amount of distributions from its subsidiaries may be affected by many factors
beyond EME's control.  See the year-end 2001 MD&A and Risk Factors under Financial Condition included in Item 7
of Edison International's Annual Report on Form 10-K for the year ended December 31, 2001.  See also the
discussion under the Historical Distributions Received by EME under the Restricted Assets of EME's Subsidiaries
section.  In addition, the timing and amount of tax-allocation payments are dependent on the consolidated taxable
income of Edison International and its subsidiaries.  See discussion under Intercompany Tax-Allocation Payments
section.

In September 2002, EME amended Tranche A of its corporate credit facility to extend the expiration period to
September 16, 2003, and to reduce the amount available from $538 million to $275 million.  Tranche B of the
corporate credit facility in the amount of $212 million expires on September 17, 2004.  The credit facility
provides credit available in the form of cash advances or letters of credit.  At September 30, 2002, there were
no cash advances outstanding under either Tranche and $70 million of letters of credit outstanding under
Tranche B. In addition to the interest payments, EME pays a facility fee as determined by its long-term credit
ratings (0.625% and 0.75% at September 30, 2002 for Tranche A and Tranche B, respectively) on the entire credit
facility independent of the level of borrowings.

As part of the amendment to EME's credit agreement, EME agreed to utilize, in lieu of the interest coverage ratio
that is included in EME's articles of incorporation and bylaws, an interest coverage ratio that is based on cash
received by EME, including tax-allocation payments, cash disbursements and interest paid.  At September 30, 2002,
EME met this new interest coverage ratio.  The interest coverage ratio in EME's articles of incorporation and
bylaws remains relevant for determining its ability to make distributions. See discussion under Interest Coverage
Ratio section.

Historical Distributions Received by EME

The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary
holding companies, which depend on distributions from subsidiaries and affiliates to fund general and
administrative costs and interest costs of recourse debt.  Distributions for the first nine months of each year
are not necessarily indicative of annual distributions due to the seasonal fluctuations in EME's business.


Page 28





                                                                                               Nine Months Ended
                                                                                                 September 30,
                    -------------------------------------------------------------------- ------------------------------
                    -------------------------------------------------------------------- --------------- --------------
                    In millions                                                               2002           2001
                    -------------------------------------------------------------------- --------------- --------------
                    -------------------------------------------------------------------- --------------- --------------
                    Distributions from Consolidated Operating Projects:
                       Edison Mission Midwest Holdings (Illinois plants)                    $   --          $   --
                       EME Homer City Generation L.P. (Homer City facilities)                   --            43.7
                       First Hydro Holdings                                                     --            51.6
                       Holding companies of other consolidated operating
                          projects                                                             21.2            0.3

                    Distributions from Non-Consolidated Operating Projects:
                       Distributions from Big 4 projects(1)                                   111.8          128.8
                       Distributions from Four Star Oil and Gas Company                        21.0           56.6
                       Distributions from other non-consolidated operating
                          projects                                                             66.3           18.7
                    -------------------------------------------------------------------- --------------- --------------
                    -------------------------------------------------------------------- --------------- --------------

                    Total Distributions                                                     $ 220.3        $ 299.7
                    -------------------------------------------------------------------- --------------- --------------


         (1) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset
             project, Sycamore project and Watson project.  Distributions do not include either capital
             contributions made during the California energy crisis or the subsequent return of such
             capital.  Distributions reflect the amount received by EME after debt service payments by EME
             Funding Corp.

Changes in distributions between the nine-month periods were due to:

o        Lower market prices for energy and capacity and major unplanned outages at the Homer City facilities
         during the first nine months of 2002.

o        Lower profitability of the First Hydro project.

o        Current  payment during 2002 of accounts  receivable by the Big 4  Projects from SCE,  compared to delayed
         payment during 2001 as a result of the California energy crisis.

o        Lower profitability in 2002 of Four Star Oil and Gas Company due to lower natural gas prices.

o        Higher distributions from EME's partnership interests in other California partnerships.

o        Distributions from EME's Italian Wind project for the first time in 2002.  The project has transitioned
         from the construction phase to commercial operations for a majority of its units.

Restricted Assets of EME's Subsidiaries
---------------------------------------

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its
other subsidiaries.  Assets of EME's subsidiaries are not available to satisfy its obligations or the obligations
of any of its other subsidiaries.  However, unrestricted cash or other assets that are available for distribution
may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid
as dividends or otherwise distributed or contributed to EME or to an affiliate of EME.  Set forth below is a
description of covenants binding EME's principal subsidiaries that may restrict the ability of those entities to
make distributions to EME directly or indirectly through the other holding companies owned by EME:


Page 29



Edison Mission Midwest Holdings (Illinois Plants)

Edison Mission Midwest Holdings is the borrower under a $1.9 billion credit facility with a group of commercial
banks.  The funds borrowed under this facility were used to fund the acquisition of the Illinois plants and
provide working capital to such operations.  Midwest Generation LLC, a wholly owned subsidiary of Edison Mission
Midwest Holdings, owns, leases or operates the Illinois plants.  Midwest Generation entered into sale-leaseback
transactions for the Collins Station as part of the original acquisition and for the Powerton Station and the
Joliet Station in August 2000.  In order to make a distribution from Edison Mission Midwest Holdings to EME,
Edison Mission Midwest Holdings and Midwest Generation must be in compliance with the covenants specified in
these agreements, including maintaining a minimum credit rating.  Due to the downgrade of the credit rating of
Edison Mission Midwest Holdings, no distributions can currently be made by Edison Mission Midwest Holdings to EME
at this time.  See EME's Credit Ratings discussion.

Edison Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month
period of at least 1.50 to 1 as long as the power purchase agreements with ExGen represent 50% or more of Edison
Mission Midwest Holdings' and its subsidiaries' revenue.  If the power purchase agreements with ExGen represent
less than 50% of Edison Mission Midwest Holdings' and its subsidiaries' revenue, it must maintain a debt service
coverage ratio of at least 1.75 to 1.  EME expects that revenue for 2003 from ExGen will represent 50% or more of
Edison Mission Midwest Holdings' and its subsidiaries' revenue.  Failure to meet such historical debt service
coverage ratio is an event of default under the credit agreement and Collins lease agreements, which, upon a vote
by a majority of the lenders to accelerate the due date of the obligations of Edison Mission Midwest Holdings or
associated with the Collins lease, may result in an event of default under the Powerton and Joliet leases.  At
September 30, 2002, Edison Mission Midwest Holdings met the historical debt service coverage ratio.

There are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany
loans from its affiliate Edison Mission Overseas (which is also a subsidiary of Edison Mission Midwest Holdings)
or to make distributions directly to Edison Mission Midwest Holdings.

EME Homer City Generation L.P.

EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001.  In
order to make a distribution, EME Homer City must be in compliance with the covenants specified in the lease
agreements, including the following financial performance requirements measured on the date of distribution:

o        At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period
         (taken as a whole) must be greater than 1.7 to 1.  The senior rent service coverage ratio is
         defined as all income and receipts of EME Homer City less amounts paid for operating expenses,
         required capital expenditures, taxes and financing fees divided by the aggregate amount of the debt
         portion of the rent, plus fees, expenses and indemnities due and payable with respect to the
         lessor's debt service reserve letter of credit.

o        At the end of each quarter, the equity and debt portions of rent then due and payable must have been
         paid.

o        The senior rent service coverage ratio (discussed in item 1 above) projected for each of the prospective
         two twelve-month periods must be greater than 1.7 to 1.

o        No more than two rent default events may have occurred, whether or not cured.  A rent default event is
         defined as the failure to pay the equity portion of the rent within five business days of when it
         is due.

At September 30, 2002, EME Homer City met the above financial performance measures.  However, as a result of
lower wholesale prices of electricity and capacity and the adverse impact of the plant outages,

Page 30


EME does not expect EME Homer City Generation to have funds available for distributions to EME for the remainder
of 2002.

First Hydro Holdings

A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of(pound)400 million of Guaranteed
Secured Bonds due in 2021.  In order to make a distribution, First Hydro Finance must be in compliance with the
covenants specified in its bond indenture, including the following interest coverage ratio:

o        As determined on June 30 and December 31 of each year, the ratio of net revenue (which is generally the
         consolidated profit of First Hydro Holdings and its subsidiaries before tax) to interest payable on the
         Guaranteed Secured Bonds for the prior twelve-month period (taken as a whole) must be greater than 1.2
         to 1.

First Hydro's interest coverage ratio must also exceed a minimum default threshold included in the Guaranteed
Secured Bonds.  When measured for the twelve-month period ended June 30, 2002, First Hydro's interest coverage
ratio was above the default threshold, but below the minimum required to permit distributions.  EME believes that
if market and trading conditions experienced thus far in 2002 are sustained for the balance of the year, First
Hydro's interest coverage ratio will also be above the distribution threshold when measured for the twelve-month
period ended December 31, 2002.  Compliance by First Hydro with these and other requirements of its bond
financing documents is subject, however, to market conditions for the sale of energy and ancillary services.

Edison Mission Energy Funding Corp. (Big 4 Projects)

EME's subsidiaries, which EME refers to as the Guarantors, that hold its interests in the Big 4 Projects
completed a $450 million secured financing in December 1996.  Edison Mission Energy Funding Corp., a special
purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which
were lent to the Guarantors in exchange for a note.  The Guarantors have pledged their ownership interests in the
Big 4 Projects to Edison Mission Energy Funding as collateral for the note.  All distributions receivable by the
Guarantors from the Big 4 Projects are deposited into a trust account from which debt service payments are made
on the obligations of Edison Mission Energy Funding and from which distributions may be made to EME if Edison
Mission Energy Funding is in compliance with the terms of the covenants in its financing documents, including the
following requirements measured on the date of distribution:

o        The debt service coverage ratio for the preceding four fiscal quarters is
         at least 1.25 to 1.

o        The debt service coverage ratio projected for the succeeding four fiscal quarters is
         at least 1.25 to 1.

The debt service coverage ratio is determined by the amount of distributions received by the Guarantors from the
Big 4 Projects during the relevant quarter divided by the debt service (principal and interest) on Edison Mission
Energy Funding's notes and bonds paid or due in the relevant quarter.  At September 30, 2002, there were no
restrictions under these covenants on EME's ability to receive distributions.  Although the credit ratings of
Edison Mission Energy Funding's notes and bonds were recently subject to a downgrade to below investment grade,
this will have no effect on the ability of the Guarantors to make distributions to EME.

Other Matters Related to Distributions from EME's Subsidiaries or Affiliates
----------------------------------------------------------------------------

Paiton Project - Paiton Energy and the state-owned electric utility company have completed negotiations on an
amendment to the power purchase agreement, which incorporates the terms and conditions of the binding term sheet
into the power purchase agreement.  While the project lenders have approved the binding term sheet, Paiton Energy
has yet to obtain approval of the amendment to the power purchase

Page 31


agreement by the project lenders. Paiton Energy and its government agency lenders have agreed to summary terms
and conditions for debt restructuring of Paiton Energy, which terms and conditions have been approved by the
commercial bank lenders to the project.  In addition, Paiton Energy must seek approval of the debt restructuring
from its bondholders. Distributions from the project will not occur until restructuring of the senior debt has
been completed, and in any case, are not likely to commence until at least 2006.

Lakeland Project - EME owns the Lakeland project, a 220-MW combined-cycle natural gas-fired power plant located
in the U.K., and sells the project's electricity under a power sales agreement.  The combination of the
introduction of the New Electricity Trading Arrangements (replacing the pool system of electricity sales in the
U.K.) and the separation of the supply and distribution businesses in the U.K. required material amendment to
Lakeland's power sales agreement and related documents.  By October 2002, agreement had been reached with Norweb
Energi Ltd (the counterparty under the Lakeland power sales agreement and an indirect subsidiary of TXU Europe)
and all other relevant parties as to the form of the necessary amendments, but the documentation to implement
this agreement was awaiting actual signature and has not yet been signed.

On October 14, 2002, TXU Corp., the U.S. parent company of TXU Europe, announced that it would not provide
additional funding for its European business and was considering selling all or a portion of this business.  On
October 21, 2002, TXU Corp. announced the sale by its indirect subsidiary, TXU (U.K.) Ltd, of all its retail
customer contracts in the U.K.  Concurrently, TXU announced its intention to renegotiate certain power sales
agreements, including the Lakeland power sales agreement, as part of an effort to restructure its operations and
preserve creditor value.  TXU further indicated that failure to renegotiate these agreements or otherwise to
restructure its operations could result in the equivalent of bankruptcy in the U.K. for one or more of TXU's
subsidiaries, including possibly Norweb Energi Ltd.

Currently, EME continues to deliver power under the Lakeland power sales agreement and Norweb Energi Ltd. has
made all payments.  However, EME cannot determine the outcome of TXU's restructuring activities in Europe, nor
the effect of such activities upon the Lakeland power sales agreement.  If the power sales agreement is
terminated, EME could operate the Lakeland project as a merchant plant, but because of current depressed power
prices in the U.K. market, EME may not be able to operate the plant profitably in the near term.  Although cash
is held by the project ($32 million at September 30, 2002), EME does not anticipate any distributions unless and
until the uncertainties surrounding the power sales agreement are resolved.  Further, during the fourth quarter,
EME will complete an asset impairment evaluation taking into consideration continuing developments with respect
to the power sales agreement.  At September 30, 2002, EME had $138 million invested in property, plant and
equipment and $72 million in debt associated with the Lakeland project.

ISAB Project - EME owns a 49% interest in the ISAB project in Italy.  The project has recently renewed its
insurance coverage, which, because of the events of September 11, 2001, and the resulting constraints in the
insurance industry, is not compliant with the insurance requirements set out in the facility loan documentation.
While EME believes the coverage obtained is the maximum available at the current time at reasonable commercial
rates, deviations from the specified coverages nevertheless require approval of the lending group.  Additionally,
EME's partner in the project wishes to transfer its ownership of certain of the project-related assets to an
affiliate company and is seeking lender approval for this.  Finally, periodically the project is required to
provide the lending group with a long-term forecast which is used to determine the loan life coverage ratio based
on, among other things, a set of technical assumptions for the project which must be approved by the technical
adviser to the lenders.  In part because of the overall group-wide cost analysis being undertaken by EME,
preparation of the technical assumptions has been delayed beyond its due date, thereby delaying preparation of
the forecast and the calculation of the loan life coverage ratio.  EME does not expect to receive distributions
from the project until these issues have been resolved with the project's lending group.  It is anticipated that
these matters will be resolved in 2003.


Page 32



Ability of EME to Pay Dividends

EME's articles of incorporation and bylaws contain restrictions on its ability to declare or pay dividends or
distributions.  These restrictions require the unanimous approval of its board of directors, including at least
one independent director, before it can declare or pay dividends or distributions, unless either of the following
is true:

o        EME then has investment grade ratings with respect to its senior unsecured long-term debt and receives
         rating agency confirmation that the dividend or distribution will not result in a downgrade; or

o        such dividends and distributions do not exceed $32.5 million in any fiscal quarter and EME then meets an
         interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal
         quarters.

EME's interest coverage ratio for the four quarters ended September 30, 2002, was 2.04 to 1.  See further details
of EME's interest coverage ratio below.  Accordingly, under the ring-fencing provisions of EME's articles of
incorporation and bylaws, until its interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four
quarters, EME cannot pay a dividend without unanimous board approval.  EME has not paid or declared a dividend to
MEHC during the first nine months of 2002 and, based on the current expectations, MEHC does not expect to receive
any distributions during the remainder of 2002 and 2003.



EME's Interest Coverage Ratio

The following table sets forth the major components of one of EME's interest coverage ratios for the twelve
months ended September 30, 2002, and the year ended December 31, 2001:

In millions                                                                 September 30,        December 31,
                                                                                 2002                2001
------------------------------------------------------------------------- ------------------- -------------------
------------------------------------------------------------------------- ------------------- -------------------
Funds Flow from Operations:
     Operating Cash Flow(1) from Consolidated Operating
         Projects(2):
         Illinois Plants                                                    $   333.0            $    201.3
         Homer City                                                              66.6                 175.2
         Ferrybridge and Fiddler's Ferry                                         10.0                (104.5)
         First Hydro                                                             36.0                  45.9
     Other consolidated operating projects                                       75.5                  64.1
     Trading and price risk management                                            4.0                  28.2
     Distributions from non-consolidated Big 4 projects(3)                      111.8                 128.8
     Distributions from other non-consolidated operating projects               105.5                  93.5
     Interest income                                                              6.5                   9.0
     Operating expenses                                                        (135.8)               (143.1)
------------------------------------------------------------------------- ------------------- -------------------
------------------------------------------------------------------------- ------------------- -------------------
         Total funds flow from operations                                   $   613.1            $    498.4
------------------------------------------------------------------------- ------------------- -------------------
------------------------------------------------------------------------- ------------------- -------------------
Interest Expense:
     From obligations to unrelated third parties                            $   185.5            $    188.7
     From notes payable to Midwest Generation                                   114.9                 116.1
------------------------------------------------------------------------- ------------------- -------------------
------------------------------------------------------------------------- ------------------- -------------------
         Total interest expense                                             $   300.4            $    304.8
------------------------------------------------------------------------- ------------------- -------------------
------------------------------------------------------------------------- ------------------- -------------------
Interest Coverage Ratio                                                          2.04                1.64
------------------------------------------------------------------------- ------------------- -------------------



     (1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid and project debt
         service.  Operating cash flow does not include capital expenditures or the difference between cash
         payments under EME's long-term leases and lease expenses recorded in its income

Page 33



         statement.  EME expects its cash payments under its long-term power plant leases to be higher than its lease
         expense through 2014.

     (2) Consolidated operating projects are entities of which EME owns more than a 50% interest and, thus,
         include the operating results and cash flows in EME's consolidated financial statements.
         Non-consolidated operating projects are entities of which EME owns 50% or less and which EME accounts
         for under the equity method.

     (3) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project,
         Sycamore project and Watson project.

The major factors affecting funds flow from operations during the twelve months ended September 30, 2002,
compared to the year ended December 31, 2001, were:

o        Higher capacity revenue and lower operating expenses and interest costs for the Illinois Plants.

o        Lower market prices for energy and capacity and major unplanned outages at the Homer City facilities.

o        The Ferrybridge and Fiddler's Ferry projects had positive operating cash flow in the fourth quarter of
         2001 and an insurance recovery in the second quarter of 2002.

o        Lower trading and price risk management activity.

Interest expense decreased $4 million during the twelve months ended September 30, 2002, from the year ended
December 31, 2001, as a result of a lower average debt balance.

The actual interest coverage ratio during 2001 and the twelve months ended September 30, 2002, was affected by
the operating results of the Ferrybridge and Fiddler's Ferry projects in the U.K.  The interest coverage ratio,
excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 1.92 to 1 for the twelve months
ended September 30, 2002.

The above interest coverage ratio is not determined in accordance with generally accepted accounting principles
as reflected in the Consolidated Statements of Cash Flows.  Accordingly, this ratio should not be considered in
isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in
the Consolidated Statements of Cash Flows.  This ratio does not measure the liquidity or ability of EME's
subsidiaries to meet their debt service obligations.  Furthermore, this ratio is not necessarily comparable to
other similarly titled captions of other companies due to differences in methods of calculations.



EME's Leverage Ratio

EME and its principal bank lenders measure the leverage of EME using a recourse debt to recourse capital ratio as
described below:

                                                Actual at
  Financial Ratio           Covenant       September 30, 2002                     Description
  -------------------------------------------------------------------------------------------------------------
  -------------------------------------------------------------------------------------------------------------

  Recourse Debt to        Less than or            60.5%           Ratio of (a) senior recourse debt to (b)
  Recourse Capital Ratio equal to 67.5%                           sum of (i) shareholder's equity per EME's
                                                                  balance sheet adjusted by comprehensive
                                                                  income after December 31, 1999, plus (ii)
                                                                  senior recourse debt
  -------------------------------------------------------------------------------------------------------------




Page 34






Discussion of Recourse Debt to Recourse Capital Ratio
-----------------------------------------------------

The recourse debt to recourse capital ratio of EME at September 30, 2002, and December 31, 2001, was calculated
as follows:

                                                          September 30,         December 31,
In millions                                                   2002                 2001
----------------------------------------------------- --------------------- ----------------------
----------------------------------------------------- --------------------- ----------------------

Recourse Debt(1)
    Corporate Credit Facilities                           $      78.1           $     203.6
    Senior Notes                                              1,600.0               1,700.0
    Guarantee of termination value of
       Powerton/Joliet operating leases                       1,423.1               1,431.9
    Coal and Capex Facility                                     176.9                 251.6
    Other                                                        27.7                  46.3
----------------------------------------------------- --------------------- ----------------------
----------------------------------------------------- --------------------- ----------------------
    Total Recourse Debt to EME                                3,305.8               3,633.4
Adjusted Shareholder's Equity(2)                              2,157.6               2,039.0
Recourse Capital(3)                                       $   5,463.4           $   5,672.4
----------------------------------------------------- --------------------- ----------------------
----------------------------------------------------- --------------------- ----------------------
Recourse Debt to Recourse Capital Ratio                         60.5%                 64.1%
----------------------------------------------------- --------------------- ----------------------



         (1)  Recourse debt means senior direct obligations of EME or obligations related to indebtedness
              or rental expenses of one of its subsidiaries for which EME has provided a guarantee.

         (2)  Adjusted shareholder's equity is defined as the sum of total shareholder's equity and
              equity preferred securities, less changes in accumulated other comprehensive gain or loss
              after December 31, 1999.

         (3)  Recourse capital is defined as the sum of adjusted shareholder's equity and recourse debt.

During the nine months ended September 30, 2002, the recourse debt to recourse capital ratio improved due to:

o        reduction in the utilization of EME's corporate credit facility.  EME paid off the $80 million that was
         outstanding at December 31, 2001, and reduced the letters of credit issued under the credit facility by
         $46 million;

o        final repayment of the $100 million senior notes in June 2002;

o        termination of the Illinois peaker lease by paying off the $45 million B notes and C certificates that
         EME guaranteed;

o        payments on the Coal and Capex facility with proceeds from Ferrybridge and Fiddler's Ferry working
         capital settlements that occurred after the divestiture; and

o        increase in shareholder's equity from positive net income for the quarter ended September 30, 2002.

During 2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in EME's
shareholder's equity from $1.1 billion of after-tax losses attributable to the loss on sale of EME's Ferrybridge
and Fiddler's Ferry coal-fired power plants located in the U.K.  EME sold the Ferrybridge and Fiddler's Ferry
power plants in December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these
plants.


Page 35



EME Subsidiary Financing Plans

The estimated capital and construction expenditures of EME's subsidiaries for the fourth quarter of 2002 are
$39 million.  These expenditures are planned to be financed by existing subsidiary credit agreements and cash
generated from their operations, except with respect to the Homer City project.  Under the Homer City
sale-leaseback agreements, EME has committed to provide funds for capital expenditures needed by the power
plant.  EME expects to contribute $28 million in 2002 and 2003 to fund the estimated capital expenditures of this
project, of which $17 million was contributed during the nine-month period ended September 30, 2002.

On August 9, 2002, EME's subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois
peaker power units that were subject to a lease with a third-party lessor.  This operating lease was structured
to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in
accordance with existing guidance for leases involving special purpose entities (sometimes referred to as
synthetic leases).  In order to fund the purchase, EME received $255 million as repayment of the note receivable
held by EME and paid $300 million plus outstanding lease obligations to the owner-lessor.  Accordingly, EME's net
cash outlay was $46 million.  These peaker units were recorded as assets and are being depreciated over their
estimated useful lives of 15 years.

EME's Chicago In-City Obligation
--------------------------------

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, an EME
subsidiary committed to install one or more gas-fired electric generating units having an additional gross
dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago (referred to as the
In-City Obligation).  The acquisition documents require that commercial operation of this project commence by
December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected
Network, generally referred to as the MAIN Region, and the improved reliability of power generation in the
Chicago area, EME is in discussions with Commonwealth Edison and the City of Chicago regarding alternatives to
construction of 500 MW of capacity, which EME does not believe is needed at this time.  There can be no assurance
that these discussions will result in an agreement to terminate the In-City Obligation.  If EME were to install
this additional capacity, EME estimates that the cost could be as much as $320 million.



Edison Mission Midwest Holdings
-------------------------------

EME's wholly owned subsidiary, Edison Mission Midwest Holdings, has the following maturities of long-term debt at
September 30, 2002:

                      Amount               Due Date
                   (In millions)
               ---------------------- ------------------------
               ---------------------- ------------------------

                    $   911.0         December 2003
                        808.3         December 2004
               ---------------------- ------------------------
               ---------------------- ------------------------

                    $ 1,719.3
               ---------------------- ------------------------


Edison Mission Midwest Holdings plans to refinance the $911 million debt obligation prior to its expiration in
December 2003.  Completion of this refinancing is subject to a number of uncertainties, including the
availability of credit from financial institutions in light of industry conditions.  Accordingly, there is no
assurance that EME will be able to refinance this debt when it becomes due or that, if EME is able to complete a
refinancing, that the amount and the terms will not be substantially different from those under Edison Mission
Midwest Holdings' current credit facility.

Valley Power Peaker Project
---------------------------

During 2001, a subsidiary of EME began construction of a 300-MW gas-fired peaker plant located adjacent to the
Loy Yang B coal-fired power plant site in Australia.  EME owns a 60% interest in the Valley Power Peaker project
through a subsidiary, with the remaining interest held by EME's 51.2% affiliate,

Page 36


Contact Energy.  The peaker units will service peaking demand within the National Energy Market of Eastern
Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the
pool and by entering into financial contracts related to pool prices with a variety of generation and retail
businesses.  Construction of the peaker plant was completed during the first half of 2002.  Construction
financing of this project was provided through an interim financing, which was replaced on November 4, 2002, with
108 million Australian dollars in long-term financing.

Sunrise Project Financing
-------------------------

EME owns a 50% interest in Sunrise Power Company (Sunrise), which owns the Sunrise project, a natural gas-fired
facility currently under construction in Kern County, California.  The Sunrise project consists of two phases.
Phase I, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001.  Phase II, conversion to a
combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003.  Sunrise Power
entered into a long-term power purchase agreement with the CDWR on June 25, 2001.

On February 25, 2002, the CPUC and the California Electricity Oversight Board (CEOB) filed complaints with the
FERC against all sellers of long-term contracts to the CDWR, including Sunrise.  The CPUC compliant alleges that
the contracts are unjust and unreasonable on price and other terms, and requests that the contracts be
abrogated.  The CEOB complaint makes a similar allegation and requests that the contracts be deemed voidable at
the request of the CDWR.  The FERC dismissed both complaints against Sunrise.  The CPUC and the CEOB have a 60
day right to appeal to the federal courts.

On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint against the CDWR,
all sellers of power under long-term energy contracts entered into in 2001, including Sunrise, and one of the
consultants involved in the negotiation of energy contracts on behalf of the CDWR.  The lawsuit requests to void
all the contracts entered into in 2001, as well as all the contracts renegotiated in 2002, as a result of a
purported conflict of interest by the consultant. Sunrise has not yet been served with a copy of the complaint.

On May 15, 2002, Sunrise was served with a complaint against sellers of long-term power to the CDWR, including
Sunrise.  The lawsuit alleges that the defendants, including Sunrise, engaged in unfair and fraudulent business
practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms.  The
lawsuit seeks to enjoin enforcement of the unfair and oppressive terms and conditions in the contracts, as well
as restitution by the defendants of excessive monies obtained by the defendants.  Plaintiffs in several other
similar pending class action lawsuits have filed petitions seeking to have this lawsuit consolidated with those
lawsuits.  The defendants in this lawsuit and other class action suits filed a motion to stay all proceedings
pending final resolution of the jurisdictional issue.  Various plaintiffs have filed pleadings opposing the
removal and requesting that the matters be remanded to state court.  The motions are still pending.

The construction of the Sunrise project has been funded with equity contributions by its partners, including
EME.  Sunrise Power has engaged a financial advisor to assist with obtaining project financing.  In order to
obtain project financing, a number of uncertainties need to be resolved related to the power purchase agreement,
the credit of the CDWR and certain environmental permits.  If these uncertainties are resolved, EME believes that
project financing can be obtained in 2003, which would result in a distribution of approximately $126 million.

Loan Agreement in Connection with Power Sales Agreement
-------------------------------------------------------

In connection with the restructuring of the power sales agreement with an unaffiliated electric utility, a wholly
owned subsidiary borrowed $84 million under a note purchase agreement to finance the purchase of the power sales
agreement held by a third party, make a deposit under a note purchase agreement, and pay for transaction costs.
The note is non-recourse to EME.  Debt service is funded and secured by payments from the power sales agreement.
The interest rate under the note purchase agreement is fixed

Page 37


at 7.31% and is due in June 2015. Principal payments under the note purchase agreement are $400,000 in 2002,
$800,000 in 2003, $2 million in 2004, $2 million in 2005, $3 million in 2006 and $76 million due after 2006.

Intercompany Tax-Allocation Payments

EME is included in the consolidated federal and state income tax returns of Edison International and participates
in a tax-allocation arrangement with other subsidiaries of Edison International.  EME has historically received
tax-allocation payments related to domestic net operating losses incurred by EME and its subsidiaries.  The
amount and timing of tax-allocation payments are dependent, in part, on the consolidated taxable income of Edison
International and its subsidiaries and other factors, including specific procedures regarding allocation of state
taxes.  EME is not eligible to receive tax-allocation payments for tax losses until such time as Edison
International and its subsidiaries generate sufficient taxable income in order to be able to utilize EME's tax
losses in the consolidated income tax returns for Edison International and its subsidiaries.  This occurred in
2002, and, accordingly, EME received $368 million in tax-allocation payments from Edison International, which
included $213 million related to the amount due December 31, 2001, and $155 million as an estimated
tax-allocation payment for 2002.

MEHC's Liquidity Issues

MEHC's ability to honor its obligations under its senior secured notes and term loan after the two-year interest
reserve period (which expires July 15, 2003) and to pay overhead is substantially dependent upon the receipt of
dividends from EME and receipt of tax-allocation payments from Edison International.  The common stock of EME has
been pledged to secure all obligations with respect to the senior secured notes and the term loan.  Part of the
proceeds from MEHC's senior secured notes and the term loan were used to fund escrow accounts to secure the first
four interest payments due under the senior secured notes and the interest payments for the first two years under
the term loan.  Other than the dividends received from EME, funds received pursuant to MEHC's tax-allocation
arrangements and the interest reserve account, MEHC will not have any other source of funds to meet its
obligations under the senior secured notes and the term loan.  Dividends from EME may be limited based on its
earnings and cash flow, terms of restrictions contained in EME's contractual obligations (including its corporate
credit facility), charter documents, business and tax considerations, and restrictions imposed by applicable
law.  See Ability of EME to Pay Dividends discussion.  As of September 30, 2002, MEHC has not received any
distributions from EME during 2002 and, based on the current expectations, no distributions are expected during
the remainder of 2002 and 2003.

At September 30, 2002, MEHC had $45 million of cash and cash equivalents and $158 million in restricted cash.
MEHC plans to use its cash resources to meet its interest obligations under the secured notes and the term loan.
Based on current interest rates, MEHC expects to have sufficient cash resources, including tax-allocation
payments to pay interest on its debt obligations until July 2005 if the $100 million put option (described below)
under the term loan is not exercised.  If the $100 million put option is exercised, MEHC expects to have
sufficient cash resources, including tax-allocation payments, to pay interest on its debt obligations until July
2004.

If MEHC is unable to make any payment on the senior secured notes or under the term loan as that payment becomes
due, it would result in a default under the senior secured notes and the term loan and could lead to foreclosure
on MEHC's ownership interest in the capital stock of EME.

Description of Term Loan Put-Option
-----------------------------------

The term loan bears interest at a floating rate equal to the three-month London interbank offered rate (LIBOR)
plus 7.50% and matures on July 2, 2006.  On the third anniversary of the term loan, the lenders under the term
loan may require that MEHC repay up to $100 million of the principal amount at par.


Page 38



MEHC's Interest Coverage Ratio
------------------------------

Currently, MEHC is permitted to pay dividends under the terms of its outstanding debt (a) in amounts sufficient
to permit Edison International to make required interest payments on its outstanding $750 million 6-7/8% notes
due 2004, (b) to pay Edison International corporate overhead in amounts consistent with historically expended
amounts, and (c) for other Edison International working capital and general corporate purposes in an amount not
to exceed $50 million.  The interest coverage ratio limits MEHC's ability, and the ability of EME and its
subsidiaries, to incur indebtedness, except as specified in the indenture and the credit agreement, unless MEHC's
interest coverage ratio exceeds 1.75x for the period prior to June 30, 2003, and 2.0x for the periods
thereafter.  MEHC's interest coverage ratio is comprised of interest income and expense related to its holding
company activities and the consolidated financial information of EME.  For a complete discussion of EME's
interest coverage ratio and the components included therein, see EME's Interest Coverage Ratio above.  The
following table sets forth an actual and pro forma calculation of MEHC's interest coverage ratio for the twelve
months ended September 30, 2002, and the year ended December 31, 2001:



                                                                                         December 31, 2001
                                                                                            Pro Forma
                                                                                             Adjust-
In millions                                         September 30, 2002          Actual       ments(1)      Pro Forma
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
Funds Flow From Operations:
   EME                                                   $   613.1             $  498.4                    $   498.4
   Less: Operating cash flow from
     unrestricted subsidiaries                               (16.1)                --                           --
   Add: Outflows of funds from
     operations of projects sold                             (10.0)               103.3                        103.3
   MEHC (stand alone)                                          9.5                  4.9       $   4.9            9.8
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
                                                         $   596.5             $  606.6       $   4.9      $   611.5
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
Interest Expense:
   EME                                                   $   300.4             $  304.7                    $   304.7
   EME - affiliate debt                                        1.8                  3.4                          3.4
   MEHC interest expense                                     159.5                 82.2       $  79.7          161.9
   Less: Interest savings on projects sold                    (0.3)                (4.5)                        (4.5)
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
                                                         $   461.4             $  385.8       $  79.7      $   465.5
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------
                                                              1.29                 1.57                         1.31
Interest Coverage Ratio
--------------------------------------------------- -------------------- ---- ----------- --------------- ------------


      (1)The pro forma adjustments assume the issuance of the 13.5% senior secured bonds and the term loan
         occurred on January 1, 2001, with the proceeds invested during the six-month period at
         approximately 3%.

The above interest coverage ratio was determined in accordance with the definitions set forth in the bond
indenture governing the senior secured notes and the credit agreement governing the term loan.  Since the
issuance of the senior secured notes and term loan occurred mid-year, the pro forma calculation is provided as an
indication of the interest coverage ratio on a full-year basis.

Edison Capital's Liquidity Issues

As of September 30, 2002, Edison Capital had cash on hand of $270 million and current liabilities of
approximately $183 million.  Edison Capital has no short-term borrowing capacity.  Edison Capital expects to meet
its operating cash needs through cash on hand, tax-allocation payments from the parent company and expected cash
flow from operating activities.


Page 39


Edison Capital has unfunded commitments of $143 million for both current and long-term liabilities for both
affordable housing projects and infrastructure funds to be funded through 2004, to the extent that investments
are identified and the funding conditions are satisfied.

Edison Capital receives cash payments from Edison International for federal and state tax benefits and incentives
available from Edison Capital's investments that are utilized on the Edison International consolidated tax
return.  Historically, a significant portion of Edison Capital's cash flow comes from cash generated from these
tax benefits.  In 2002, Edison Capital received net tax-allocation payments of $348 million through September 30,
2002.

On April 16, 2002, Edison Capital paid off $90 million on its bank facility and terminated the agreement.
At this time, Edison Capital has not determined when a short-term credit facility will be established.

Edison International's Liquidity Issues

The parent company's liquidity and its ability to pay interest, debt payments, operating expenses and dividends
are dependent upon dividends from subsidiaries and tax-allocation payments under its tax allocation agreement
with its subsidiaries.  SCE's ability to pay dividends on its common stock is restricted as a result of CPUC
regulation.  The CPUC regulates SCE's capital structure, which limits the dividends it may pay Edison
International by precluding any dividends that would reduce SCE's equity component of its capital structure below
authorized levels.  However, under the settlement agreement with the CPUC, SCE cannot pay dividends or other
distributions on its common stock (all of which is held by its parent, Edison International) prior to the earlier
of the date on which SCE has recovered all of its procurement-related obligations or January 1, 2005, except that
if SCE has not recovered all of its procurement-related obligations by December 31, 2003, SCE may apply to the
CPUC for consent to resume common stock dividends prior to January 1, 2005, and the CPUC will not unreasonably
withhold its consent.  Edison Capital's ability to make dividend payments is restricted by debt covenants, which
require Edison Capital to maintain a specified minimum net worth.  Edison Capital currently exceeds the threshold
amount.  Currently, MEHC is permitted to pay dividends under the terms of its outstanding debt (a) in amounts
sufficient to permit Edison International to make required interest payments on its outstanding $750 million
6-7/8% notes due 2004, (b) to pay Edison International corporate overhead in amounts consistent with historically
expended amounts and (c) for other Edison International working capital and general corporate purposes in an
amount not to exceed $50 million.  After July 15, 2003, MEHC may not pay dividends unless it has an interest
coverage ratio of 2.0x.  MEHC did not declare or pay a dividend in the first nine months of 2002.  MEHC's ability
to pay dividends is dependent on EME's ability to pay dividends to MEHC.  EME and its subsidiaries have certain
dividend restrictions as discussed in EME's Liquidity Issues section above.  EME did not pay or declare a
dividend during the first nine months of 2002.  The ability of Edison International to pay its $750 million notes
due September 2004 may be substantially dependent, among other things, on subsidiary dividends.  Also, as
discussed in MEHC Liquidity Issues section, the downgrade in EME's credit rating to below investment grade
adversely impacts EME's ability to pay MEHC dividends, and to the extent this situation continued beyond July
2004, it would adversely affect MEHC's ability to meet its debt service obligations.  Edison International's
investment in MEHC, through a wholly owned subsidiary, as of September 30, 2002, was $1 billion.

In May 2001, Edison International deferred the interest payments in accordance with the terms of its outstanding
$825 million quarterly income debt securities, due 2029, 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, at a time.  Edison International cannot pay cash dividends on
or purchase its common stock while interest is being deferred.

In March 2002, Edison International received income tax related cash inflows, primarily due to an Internal
Revenue Service (IRS) refund resulting from a March 2002 change in federal tax law and, as a result, paid in full
a $250 million note due to SCE related to tax-allocation payments owed to SCE for the year 2000.  At September
30, 2002, the parent company had $206 million of cash on hand.  Edison International received $146 million in
tax-allocation payments through September 30, 2002.


Page 40



Edison International does not expect to pay dividends to common shareholders at least until SCE recovers the
PROACT balance.  Material factors affecting the timing of recovery of the PROACT balance are discussed below in
PROACT Regulatory Asset.  Also see CPUC Litigation Settlement Agreement.



Cash Flows from Operating Activities

Net cash provided by operating activities:

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

         In millions                                                 2002                    2001
----------------------------------------------------------------------------------------------------------

         Continuing operations                                  $   1,262               $   2,266
         Discontinued operations                                       58                      (6)
----------------------------------------------------------------------------------------------------------

                                                                $   1,320               $   2,260
----------------------------------------------------------------------------------------------------------



Cash provided by operating activities from continuing operations for the nine months ended September 30, 2002,
was primarily due to SCE overcollections mainly resulting from the CPUC-approved surcharges (1(cent)per kWh in
January 2001, 3(cent)per kWh in June 2001 and a $0.006 per kWh in June 2001).  Also, EME received distributions from
its energy projects and investments in partnerships during 2002.  The cash provided was partially offset by SCE's
March 2002 repayment of past-due obligations.

Cash provided by operating activities from continuing operations for the nine months ended September 30, 2001,
was primarily due to SCE temporarily suspending payments for purchased power and other obligations beginning in
January 2001.



Cash Flows from Financing Activities

Net cash provided by financing activities:

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

         In millions                                                 2002                    2001
----------------------------------------------------------------------------------------------------------

         Continuing operations                                  $   2,049                $    777
         Discontinued operations                                       --                    (250)
----------------------------------------------------------------------------------------------------------

                                                                $   2,049                $    527
----------------------------------------------------------------------------------------------------------



Cash used by financing activities in the nine months ended September 30, 2002, was primarily due to SCE's March
2002 payments of $1.65 billion of credit facilities and $531 million of matured commercial paper, as well as $1.5
billion repayments on long-term debt.  These payments were partially offset by the closing of a $1.6 billion
financing and the remarketing of $196 million in pollution-control bonds that took place in the first quarter of
2002.  Also contributing to the usage of cash were EME's net payments on its senior notes that matured, its
corporate credit facility and short-term borrowings in connection with the restructuring of a power sales
agreement.  The $1.6 billion financing that took place in the first quarter of 2002 included a $600 million,
one-year term loan, due on March 3, 2003.  SCE prepaid $300 million of this loan on August 14, 2002.

Net cash provided by financing activities in the nine months ended September 30, 2001, was primarily due to SCE's
draw on its credit line, partially offset by the repurchase of pollution control bonds in early 2001 that could
not be remarketed in accordance with their terms, and MEHC's July 2001 issuances of $800 million of senior
secured notes and $385 million under a new term loan.


Page 41



Cash used by financing activities from discontinued operations in 2001 was primarily related to the early
repayment of the term facility in connection with the sale of the Ferrybridge and Fiddler's Ferry power plants.



Cash Flows from Investing Activities

Net cash used by investing activities:

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

         In millions                                                 2002                    2001
----------------------------------------------------------------------------------------------------------

         Continuing operations                                   $   (784)               $   (790)
         Discontinued operations                                       --                     165
----------------------------------------------------------------------------------------------------------

                                                                 $   (784)               $   (625)
----------------------------------------------------------------------------------------------------------



Cash flows from investing activities are affected by additions to property and plant, EME's sales of assets and
SCE's funding of nuclear decommissioning trusts.  SCE's additions to property and plant were $695 million,
primarily for transmission and distribution assets; EME's capital additions of $505 million in 2002 were
primarily for the Valley Power Peaker project in Australia, the Illinois plants, the Homer City facilities and
payments related to three turbines.  Included in EME's capital expenditures was a $300 million payment for the
Illinois peaker power units that were subject to a lease (see Off Balance Sheet Financing).  These increases were
partially offset by proceeds from the sale of various EME projects.

Cash flows from investing activities in 2001 was primarily related to transmission and distribution additions at
SCE.

COMMITMENTS

Edison International's long-term debt maturities and sinking fund requirements for the five twelve-month periods
following September 30, 2002, are:  2003 - $1.2 billion; 2004 - $3.0 billion; 2005 - $2.2 billion; 2006 - $873
million; and 2007 - $690 million.  These amounts have been updated to reflect the $1.6 billion in debt SCE issued
on March 1, 2002.

Preferred securities redemption requirements for the five twelve-month periods following September 30, 2002,
are:  2003 - $9 million; 2004 - $9 million; 2005 - $9 million; 2006 - $9 million; and 2007 - $113 million.

MARKET RISK EXPOSURES

Edison International's primary market risk exposures include commodity price risk, interest rate risk and foreign
currency exchange risk that could adversely affect results of operations or financial position.  Commodity-price
risk arises from fluctuations in the market price of electricity, natural gas, oil, coal, emission and
transmission rights.  Interest rate risk arises from fluctuations in interest rates and foreign currency exchange
risk arises from fluctuations in 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

Under the CPUC settlement agreement, SCE is permitted full recovery of its power procurement costs during the
PROACT recovery period.  After the PROACT recovery period, SCE expects to recover its power procurement costs in
customer rates through regulatory mechanisms established in rate-making proceedings.  Assembly Bill (AB) 57,
which the Governor of California signed in September 2002, provides that the CPUC shall adjust rates, or order
refunds, to amortize undercollections or overcollections of



Page 42


power procurement costs.  Until January 1, 2006, the CPUC must adjust rates if the undercollection or
overcollection exceeds 5% of SCE's prior year's procurement costs, excluding revenue collected for the CDWR.  As
a result of these regulatory mechanisms,  the effects of market risks, if any, will impact SCE's cash flows but
are not expected to have an impact on earnings.

On October 24, 2002, a CPUC decision was issued that ordered SCE to resume procurement of its residual net short
(the amount of energy needed to serve SCE's customers from sources other than its own generating plants, power
purchase contracts and CDWR contracts) beginning January 1, 2003, and approved SCE's procurement plan filed with
the CPUC, subject to certain modifications.  SCE plans to enter into capacity contracts of up to 5 years in order
to reduce its exposure to spot market prices for power.  In addition, SCE expects that it will transact through
the ISO for imbalance power.  SCE will be required to post collateral to support its obligations under either of
these types of transactions.

The reduction in the credit quality of many trading parties increases SCE's credit risk.  In the event a
counterparty were to default on its obligations, SCE also would be exposed to potentially higher costs for
replacement power.  SCE has developed standards that limit extension of unsecured credit based upon a number of
objective factors.  In negotiating capacity contracts, SCE also has included collateral requirements and credit
enforcements to mitigate the risk of possible defaults.  However, these actions may not protect SCE in the event
of bankruptcy of a counterparty.

SCE forecasts that its average 2003 residual net short, on an energy basis, will be approximately 5% of the total
energy needed to serve SCE's customers, with most of the short position occurring during off-peak hours.  SCE's
residual net short exposure is larger during the first quarter of 2003, because of a planned refueling outage at
San Onofre Unit 3.  In the second half of 2003, this exposure declines significantly as more power deliveries are
scheduled to commence under existing CDWR contracts that are allocated to SCE's customers.  Factors that could
cause SCE's residual net short to be larger than expected include:  direct access customers returning to utility
service from their energy service provider; lower utility generation; lower deliveries under QF, CDWR or
interutility contracts; or higher load requirements.

On July 17, 2002, the FERC issued an order implementing a market power mitigation program for the 11-state
western region.  SCE cannot yet determine whether the new market mitigation plan adopted by the FERC will be
sufficient to mitigate market price volatility in the wholesale electricity markets in which SCE will be
purchasing its residual net short electricity requirements.

During 2000 and 2001, SCE experienced severe cost volatility associated with its QF contracts.  To mitigate this
volatility, SCE purchased $209 million in hedging instruments (gas call options) in October and November 2001 to
hedge a majority of its natural gas price exposure associated with QF contracts for 2002 and 2003.  Although the
gas call options are reflected in the income statement, any fair value changes of the gas call options are offset
through a regulatory balancing account; therefore, fair value changes do not affect earnings.  On March 13, 2002,
SCE filed an application with the CPUC for approval and recovery of $209 million in hedging costs.  No party is
challenging the reasonableness of SCE's expenditure.  In addition, most renewable QFs are paid a fixed price of
5.37(cent)per kWh for energy.

See additional discussion on these matters in CPUC Litigation Settlement Agreement, Generation Procurement
Proceeding and Wholesale Electricity Markets below.

EME

EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel
for EME's uncontracted generating plants.  These risks arise from fluctuations in electricity and fuel prices,
emission and transmission rights, interest rates and foreign currency exchange rates.  EME manages these risks in
part by using derivative financial instruments in accordance with established policies and procedures.  See
Current Developments Related to EME and EME's Credit Ratings for a discussion of the market developments and
their impact on EME's credit and the credit of its counterparties.


Page 43



Commodity Price Risk

EME's energy trading activities and merchant power plants expose it to commodity price risks.  Commodity price
risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place,
which limit the amount of total net exposure EME may enter into at any point in time.  Procedures exist which
allow for monitoring of all commitments and positions with regular reviews by a risk management committee.  EME
performs a value at risk analysis in its daily business to measure, monitor and control its overall market risk
exposure.  The use of value-at-risk allows management to aggregate overall risk, compare risk on a consistent
basis and identify the drivers of the risk.  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 the use of stress
testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits.

Electric power generated at EME's merchant plants is generally sold under bilateral arrangements with utilities
and power marketers under short-term contracts with terms of two years or less, or, in the case of the Homer City
facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator
(NYISO).  As discussed further below, beginning in 2003, EME will also be selling a significant portion of the
power generated from its Illinois plants into wholesale energy markets.  In order to provide more predictable
earnings and cash flow, EME may hedge a portion of the electric output of its merchant plants, the output of
which is not committed to be sold under long-term contracts.  When appropriate, EME manages the spread between
electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve
those objectives.

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

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

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

o        transmission congestion in and to each market area;

o        the market structure rules to be established for each market area;

o        the cost of emission credits or allowances;

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

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

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

A discussion of each market area is set forth below by region.

Illinois Plants
---------------

Electric power generated at the Illinois plants is currently sold under three power purchase agreements with
ExGen, under which ExGen purchases capacity and has the right to purchase energy generated by


Page 44


the Illinois plants.  The agreements, which began on December 15, 1999, and have a term of up to five years,
provide for capacity and energy payments.  ExGen is obligated to make a capacity payment for the plants under
contract and an energy payment for the electricity produced by these plants and taken by ExGen.  The capacity
payments provide the revenue for fixed charges, and the energy payments compensate the Illinois plants for
variable costs of production.

Virtually all of EME's energy and capacity sales from the Illinois plants in the first nine months of 2002 were
to ExGen under the power purchase agreements, and EME expects this to continue during the remainder of 2002.
Under each of the power purchase agreements, ExGen, upon notice by a given date, has the option in effect to
terminate each agreement with respect to all or a portion of the units subject to it.

In July 2002, under the power purchase agreement related to EME's coal-fired generation units, ExGen notified EME
of its exercise of its option to purchase 1,265 MW of capacity and energy during 2003 (of a possible total of
3,949 MW subject to option) from the option coal units. As a result, 2,684 MW of capacity of the Will County 1
and 2, Joliet 6 and 7, and Powerton 5 and 6 units will no longer be subject to the power purchase agreement after
January 1, 2003.  The notification received from ExGen has no effect on its commitments to purchase capacity from
these units for the balance of 2002.  ExGen continues to have a similar option, exercisable not later than 180
days prior to January 1, 2004, to retain or release for 2004 all or a portion of the option coal units retained
for 2003.  ExGen remains committed to purchase the capacity of certain committed units having 1,696 MW of
capacity for both 2003 and 2004.

The following table lists the committed coal units, the units for which ExGen has exercised its call option for
2003, and the units that, as of January 1, 2003, will be released from the terms of the power purchase agreement,
along with related pricing information set forth in the power purchase agreement.



                                                 Coal-Fired Units

                                    Unit              Summer(1)               Non-Summer(1)           Energy Prices
                                    Size           Capacity Charge           Capacity Charge
                                    (MW)          ($ per MW Month)          ($ per MW Month)            ($/MWh)
Unit Name                                        2003         2002         2003         2002        2003       2002
-------------------------------- ------------ ------------ ------------ ------------ ------------ ---------- ----------
-------------------------------- ------------ ------------ ------------ ------------ ------------ ---------- ----------

Committed Units
         Waukegan Unit 7              328        11,000       12,000       1,375        1,500       17.0       16.0
         Crawford Unit 8              326        11,000       12,000       1,375        1,500       17.0       16.0
         Will County Unit 4           520        11,000       12,000       1,375        1,500       17.0       16.0
         Joliet Unit 8                522        11,000       12,000       1,375        1,500       17.0       16.0
                                 ------------
                                 ------------
                                    1,696
Option Units(2)
         Waukegan Unit 6              100        21,300       15,520       2,663        1,940       20.0       19.0
         Waukegan Unit 8              361        21,300       15,520       2,663        1,940       20.0       16.0
         Fisk Unit 19                 326        21,300       15,520       2,663        1,940       20.0       19.0
         Crawford Unit 7              216        21,300       15,520       2,663        1,940       20.0       19.0
         Will County Unit 3           262        21,300       15,520       2,663        1,940       20.0       16.0
                                 ------------
                                 ------------
                                    1,265
Released Units(3)
         Will County Unit 1           156           (3)       15,520          (3)       1,940         (3)      16.0
         Will County Unit 2           154           (3)       15,520          (3)       1,940         (3)      19.0
         Joliet Unit 6                314           (3)       15,520          (3)       1,940         (3)      19.0
         Joliet Unit 7                522           (3)       15,520          (3)       1,940         (3)      19.0
         Powerton Unit 5              769           (3)       15,520          (3)       1,940         (3)      16.0
         Powerton Unit 6              769           (3)       15,520          (3)       1,940         (3)      16.0
                                 ------------
                                 ------------
                                    2,684
                                 ------------
                                 ------------
                                    5,645
-------------------------------- ------------ ------------ ------------ ------------ ------------ ---------- ----------


     (1) Summer months are June, July, August and September, and Non-Summer months are the remaining months in
         the year.


Page 45




     (2) Option units refer to those option units for which ExGen has exercised its right to purchase capacity
         and energy during 2003 under the terms of the power purchase agreement.

     (3) Released units refer to those option units for which ExGen hasnot exercised its right to purchase
         capacity and energy during 2003, and which are thus released from the terms of the power purchase
         agreement.  After January 1, 2003, the price for energy and capacity from these units will be based upon
         either the terms of new bilateral contracts or prices received from forward and spot market sales.

In October 2002, under the power purchase agreements related to EME's Collins Station and peaking units, ExGen
notified EME of its exercise of its option to terminate the existing power purchase agreements during 2003 with
respect to (a) 1,614 MW of capacity and energy (of a possible total of 2,698 MW subject to the option to
terminate) from the Collins Station, a natural gas and oil-fired electric generating station, and (b) 113 MW of
capacity and energy (of a possible total of 807 MW subject to the option to terminate) from the natural gas and
oil-fired peaking units, in accordance with the terms of each applicable power purchase agreement.  As a result,
1,614 MW of capacity from the Collins Units 2, 4 and 5, and 113 MW of capacity from the Lombard 33 and Calumet 33
and 34 peaking units, will no longer be subject to a power purchase agreement after January 1, 2003.  The
notification received from ExGen has no effect on its commitments to purchase capacity from these generating
units for the balance of 2002.  ExGen continues to have a similar option to terminate, exercisable not later than
90 days prior to January 1, 2004, the power purchase agreements for 2004 with respect to all or a portion of the
generating units not previously terminated for 2003 (1,084 MW from the Collins Station and 694 MW from the
peaking units).

The following table lists the generating units at the Collins Station and the peaking units as to which ExGen has
not exercised its option to terminate for 2003, the generating units and peaking units which, as of January 1,
2003, will, as a result of the exercise by ExGen of its option to terminate, be released from the terms of the
power purchase agreement, and the peaking units as to which ExGen exercised its option to terminate effective as
of January 1, 2002, along with related pricing information set forth in the respective power purchase agreements.



                                         Collins Station and Peaking Units

                                   Unit              Summer(1)               Non-Summer(1)              Energy
                                   Size          Capacity Charge           Capacity Charge              Prices
                                   (MW)         ($ per MW Month)           ($ per MW Month)             ($/MWh)

Generating Unit                                2003         2002         2003         2002       2003       2002
------------------------------- ----------- ----------- ------------- ------------ ----------- ---------- ----------
------------------------------- ----------- ----------- ------------- ------------ ----------- ---------- ----------
Option Units
     Collins Unit 1                554        8,333        6,666         2,083        1,667         33         32
     Collins Unit 3                530        8,333        6,666         2,083        1,667         33         32
                                -----------
                                -----------
                                 1,084
     Peaking Units                 694        9,500        7,600         1,500        1,200        55-90      50-85

Released Units
     Collins Unit 2                554          (2)        6,666           (2)        1,667        (2)         32
     Collins Unit 4                530          (2)        6,666           (2)        1,667        (2)         32
     Collins Unit 5                530          (2)        6,666           (2)        1,667        (2)         32
                                -----------
                                -----------
                                 1,614
     Peaking Units                 113          (2)        7,600           (2)        1,200        (2)         50
     Peaking Units (3)             137          (3)          (3)           (3)          (3)        (3)        (3)
------------------------------- ----------- ----------- ------------- ------------ ----------- ---------- ----------

(1)      Summer months are June, July, August and September, and Non-Summer months are the remaining months in
         the year.

(2)      Generating and peaking units for which ExGen has exercised its right to terminate the power purchase
         agreement with respect thereto, and which are thus released from the terms of the power purchase
         agreement. After January 1, 2003, the price for energy and capacity from these units will be based upon
         either the terms of new bilateral contracts or prices received from forward and spot market sales.


Page 46


(3)      Peaking units for which ExGen exercised its right to terminate the power purchase agreement effective as of
         January 1, 2002. The price for energy and capacity from these units has since that date been based on
         the terms of bilateral contracts or prices received from forward and spot market sales.

The energy and capacity from any units which do not remain subject to one of the power purchase agreements with
ExGen will be sold under terms, including price and quantity, to be negotiated with customers through a
combination of bilateral agreements, forward energy sales and spot market sales.  Thus, EME will be subject to
the market risks related to the price of energy and capacity described above. EME expects capacity prices for
merchant energy sales will, in the near term, be substantially lower than those EME currently receives under
EME's existing agreements (with the possibility of minimal revenue due to the current oversupply conditions in
this marketplace).  EME further expects that the lower revenue resulting from this difference will be offset in
part by energy prices, which EME believes will, in the near term, be higher for merchant energy sales than those
EME currently receives under its existing agreements, as indicated below in the table of forward-looking prices.
EME intends to manage this price risk, in part, by accessing both the direct customer and over-the-counter
markets described below as well as using derivative financial instruments in accordance with established policies
and procedures.

During 2003, the primary markets available to EME for wholesale sales of electricity from the Illinois plants are
expected to be direct customer and over-the-counter.  Direct customer transactions are bilateral sales to
regional buyers that principally include investor-owned utilities, municipal utilities, rural electric
cooperatives and retail energy suppliers.  Transactions in the direct customer market include real-time, daily
and longer-term structured sales that meet the specific requirements of wholesale electricity consumers.
Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include
forward sales of electricity.  The most liquid over-the-counter markets in the Midwest region are Into Cinergy,
and, to a lesser extent, Into ComEd.

Into Cinergy and Into ComEd are bilateral markets for the sale or purchase of electrical energy for future
delivery.  The emergence of Into Cinergy and Into ComEd as commercial hubs for the trading of physical power has
not only facilitated transparency of wholesale power prices in the Midwest, but also aided in the development of
risk management strategies that are utilized to mitigate commodity price volatility. Energy is traded in the form
of physical delivery of megawatt-hours. Delivery is either made (1) into the receiving control area's
transmission system (i.e., Cinergy's or ComEd's transmission system) by the seller's daily election of control
area interface, or (2) by procuring energy generated from a source within the receiving control area. Almost all
of the Illinois plants have busbar delivery that meets the Into ComEd delivery criteria.  Performance of
transactions in these markets is secured by liquidated damages and, in the case of less creditworthy
counterparties, credit support provisions such as letters of credit and cash margining arrangements.

The following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar
2003 and calendar 2004 strips (defined as energy purchases for the entire calendar year) as publicly quoted for
sales Into ComEd and Into Cinergy during the first nine months of 2002.  As indicated above, these forward prices
will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is
also affected by economic growth, and the amount of existing and planned power plant capacity.  The actual spot
prices for electricity delivered into these markets may vary materially from the forward market prices.


Page 47





                                                     Into ComEd*
                                       2003                                2004
-----------------------------------------------------------------------------------------------

Date                      On-Peak     Off-Peak    24-Hr       On-Peak     Off-Peak    24-Hr
-----------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------
January 31, 2002          $ 27.26      $ 18.34     $ 22.56     $ 28.72     $ 19.09     $ 23.65
February 28, 2002           28.96        18.50       23.48       31.30       19.25       24.99
March 31, 2002              32.50        19.85       25.56       34.31       21.35       27.20
April 30, 2002              32.55        19.05       25.65       33.55       20.05       26.65
May 31, 2002                30.85        17.31       23.71       32.30       19.18       25.38
June 30, 2002               29.54        16.88       22.50       30.98       19.38       24.53
July 31, 2002               28.64        16.90       22.37       30.09       18.90       24.11
August 31, 2002             28.75        17.00       22.47       30.20       19.25       24.34
September 30, 2002          29.16        15.92       22.09       30.61       18.17       23.96
-----------------------------------------------------------------------------------------------


                                                     Into Cinergy**
                                        2003                                2004
------------------------------------------------------------------------------------------------

Date                       On-Peak     Off-Peak    24-Hr       On-Peak     Off-Peak    24-Hr
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
January 31, 2002            $ 28.38     $ 18.77     $ 23.32     $ 29.85     $ 19.52     $ 24.41
February 28, 2002             30.30       18.75       24.25       32.64       19.50       25.75
March 31, 2002                33.82       20.15       26.33       35.63       21.65       27.97
April 30, 2002                34.03       19.75       26.73       35.03       20.75       27.73
May 31, 2002                  31.74       18.88       24.96       33.97       20.75       27.00
June 30, 2002                 31.08       18.25       23.95       32.50       20.75       25.97
July 31, 2002                 29.34       18.25       23.41       32.00       20.25       25.72
August 31, 2002               29.63       18.00       23.41       31.60       20.25       25.54
September 30, 2002            30.56       17.50       23.59       32.18       19.75       25.54
------------------------------------------------------------------------------------------------



                 (1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday
                     through Friday.  All other hours of the week are referred to as off-peak.

                 *   Source:  Prices were obtained by gathering publicly available broker quotes adjusted
                     for historical basis differences between ComEd and Cinergy.

                 **  Source:  Prices were obtained by gathering publicly available broker quotes.


The average price that EME derives from electricity sales is normally higher than a 24-hour price as EME manages
its generation to optimize on-peak periods when power prices are higher.

Midwest Generation intends to hedge a portion of its merchant portfolio risk.  To the extent it does not do so,
the unhedged portion will be subject to the risks and benefits of spot-market price movements.  The extent to
which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on
several factors.  First, Midwest Generation will evaluate over-the-counter market prices to determine whether
sales at forward market prices are sufficiently attractive compared to assuming the risk associated with spot
market sales.  Second, Midwest Generation's ability to enter into hedging transactions will depend upon Midwest
Generation's liquidity and upon the over-the-counter forward sales markets' having sufficient liquidity to enable
Midwest Generation to identify counterparties who are able and willing to enter into hedging transactions with
Midwest Generation.  Due to factors beyond Midwest Generation's control, market liquidity has decreased
significantly since the beginning of 2002, and a number of formerly significant trading parties have completely
withdrawn from the market or substantially

Page 48


reduced their trading activities.  This decrease in market liquidity may require Midwest Generation to rely more
heavily on sales to end user counterparties in the direct customer markets.  See discussion under Credit Risks
under EME's Market Risk Exposures section.

In addition to the prevailing market prices, the ability of Midwest Generation to derive profits from the sale of
electricity from the released units will be affected by the cost of production, including costs incurred to
comply with environmental regulations.  The costs of production of the released units vary and, accordingly,
depending on market conditions, the amount of generation that will be sold from the released units is expected to
vary from unit to unit.  In this regard, EME will suspend operations of Units 1 and 2 at its Will County plant
and Units 4 and 5 of EME's Collins Station at the end of 2002 until market conditions improve.  If market
conditions were to be depressed for an extended period of time, EME would need to consider decommissioning these
units, which would result in a charge against income.

Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and
hedging transactions may be affected by transmission constraints.  Although the FERC and the relevant industry
participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how
effectively such issues will be resolved.

A group of transmission-owning utilities has asked the FERC to permit them to join PJM, and the FERC granted
those requests, with conditions, in an order issued on July 31, 2002.  These companies include Commonwealth
Edison and American Electric Power (AEP).  As recently filed by Commonwealth Edison with the FERC, Commonwealth
Edison will join PJM either as an individual transmission owner, or as a member of an Independent Transmission
Company.  Furthermore, the Commonwealth Edison transmission system, to which the Illinois plants are directly
interconnected, is expected to be fully integrated into the PJM market structure by the December of 2003.
National Grid is currently in discussions with AEP, Commonwealth Edison and Dayton Power & Light to form an
independent transmission company that would operate under the PJM umbrella and oversight.  EME believes that
Commonwealth Edison's integration into the PJM market will improve EME's ability to sell electricity into a well
developed, stable, transparent, and liquid cash market without additional transmission charges.  The expanded PJM
market will be interconnected by numerous extra-high voltage transmission ties and will include (in addition to
the existing market encompassed by PJM) the service territories of Commonwealth Edison, American Electric Power,
Illinois Power, Virginia Power, and Dayton Power and Light.  Furthermore, as a condition of approval of the
requests to join PJM, the FERC is requiring PJM and its counterpart transmission entity in the Midwest to form a
common, seamless energy market by October 2004, which would further expand the areas into which EME may sell
power without incurring multiple transmission charges.  The companies are planning to begin the first phase of
the integration process during first quarter 2003 by turning over their respective transmission service
operations to PJM under the terms and conditions of the PJM Open Access Transmission Tariff.  The first phase of
this integration process is intended to eliminate rate-pancaking across the current PJM region and the new PJM
West region, of which both Commonwealth Edison and AEP will be a part.

Homer City Facilities
---------------------

Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic
utilities and power marketers under short-term contracts with terms of two years or less, or to the PJM or the
NYISO.  These pools have short-term markets, which establish an hourly clearing price.  The Homer City facilities
are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both
the PJM and NYISO markets.  The Homer City facilities can also transmit power to the Midwestern United States.


Page 49


The following table depicts the average historical market prices per megawatt hour in PJM during the first nine
months of 2002 and 2001:



                                                                    24-Hour PJM
                                                                 Historical Prices*
                                                               2002            2001
                           ----------------------------------------------------------------
                           ----------------------------------------------------------------
                                January                      $  20.52       $    36.66
                                February                        20.62            29.53
                                March                           24.27            35.05
                                April                           25.68            34.58
                                May                             21.98            28.64
                                June                            24.98            26.61
                                July                            30.01            30.21
                                August                          30.41            43.99
                                September                       29.00            22.44
                           ----------------------------------------------------------------
                           ----------------------------------------------------------------
                                Nine-month Average           $  25.27       $    31.97
                           ----------------------------------------------------------------


                           * Prices were calculated at the Homer City busbar (delivery point)
                             using historical hourly prices provided on the PJM-ISO web-site.

As shown on the above table, the average historical market prices at the Homer City busbar (delivery point)
during the first nine months of 2002 are below the average market prices during the first nine months of 2001.
These forward prices will continue to fluctuate as a result of a number of factors, including natural gas prices,
electricity demand which is affected by weather and is also affected by economic growth, and the amount of
existing and planned power plant capacity.  The actual spot prices for electricity delivered into these markets
may vary materially from the forward market prices.  At the end of October 2002, EME's forecasted yearly average
24-hour PJM price for 2002 was $25.64, compared to the actual yearly average 24-hour PJM price of $29.07 in
2001.  EME's forecasted yearly average 24-hour PJM prices are based on year-to-date actual data and a forecast
for the remainder of the year based on current market information.

The following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar
2003 and calendar 2004 strips (defined as energy purchases for the entire calendar year) for sales in PJM during
the first nine months of 2002.



                                                                     24-Hour PJM
                                                                   Forward Prices*
                                                                 2003            2004
                           -----------------------------------------------------------------
                           -----------------------------------------------------------------
                                January 31, 2002              $  25.48        $    26.31
                                February 28, 2002                27.11             27.59
                                March 31, 2002                   29.69             29.66
                                April 30, 2002                   29.19             28.81
                                May 31, 2002                     28.40             28.24
                                June 30, 2002                    27.96             28.09
                                July 31, 2002                    27.94             28.43
                                August 31, 2002                  28.10             28.17
                                September 30, 2002               29.00             28.99
                           -----------------------------------------------------------------


                           * Prices were obtained by gathering publicly available broker quotes
                             at PJM West (delivery point).

The forward prices at PJM West (delivery point) are generally higher than the prices of the Homer City busbar
(delivery point) due to transmission congestion charges.  The average PJM West price has been

Page 50


3% higher than the average Homer City busbar price during the past 24 months.  The average price that Homer City
facilities derive from electricity sales is normally higher than a 24-hour price as EME manages its generation to
optimize the on-peak periods when power prices are higher.

The ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part
of the sale-leaseback transaction discussed in Off-Balance Sheet Transactions included in the year-end 2001 MD&A,
depends on revenue generated by the Homer City facilities, which depend in part on the market conditions for the
sale of capacity and energy.  These market conditions are beyond EME's control.

United Kingdom
--------------

Since 1989, EME's plants in the U.K. have sold their electrical energy and capacity through a centralized
electricity pool, which established a half-hourly clearing price, also referred to as the pool price, for
electrical energy.  On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical
trading system referred to as the new electricity trading arrangements.  The First Hydro plant has entered into
forward contracts of varying terms that expire on various dates through August 2005.

The new electricity trading arrangements provide for, among other things, the establishment of a range of
voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 3.5 hours
(effective July 2, 2002, this time period became 1 hour) before a trading period of one-half 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.  The grid operator retains the right under the new market mechanisms to purchase system
reserve and response services to maintain the quality of the electrical supply directly from generators
(generally referred to as ancillary services).  Ancillary services contracts typically run for a year and can
consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when
actually called upon by the grid operator.  Physical bilateral contracts have replaced the prior financial
contracts for differences, but have a similar commercial function.  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 of,
its net contracted positions or pay for any energy imbalance at highly volatile imbalance prices calculated by
the market operator.  A consequence of this new system has been to increase greatly the motivation of parties to
contract in advance and to further develop forwards and futures markets of greater liquidity than at present.
Furthermore, another consequence of the market change is that counterparties may require additional credit
support, including parent company guarantees or letters of credit.

The legislation introducing the new trading arrangements set a principal objective for the Gas and Electric
Market Authority to "protect the interests of consumers...where appropriate by promoting competition...." This
represents a shift in emphasis toward the consumer interest.  However, this is qualified by recognition that
license holders should be able to finance their activities.  The Utilities Act of 2000 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 is monitoring the
operation of these new provisions.

During 2001, EME's operating income from the First Hydro plant decreased $106 million from the prior year
primarily due to the removal of a formal capacity mechanism in the new trading arrangements and the oversupply of
generation in the market resulting in a sharp fall in the market value for capacity.  In addition, First Hydro's
operating results were adversely affected in the second half of 2001 by a fall in the differential of the peak
daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top
reservoir.  This was a reflection both of excess generating capacity on the U.K. system as a whole and also of
the practice of generators holding plants on the system at part load to protect themselves against the adverse
affects of being out of balance in the new market.  During 2002 there has been further downward pressure on
wholesale prices and on peak/off peak differentials.


Page 51


Despite the foregoing, First Hydro's interest coverage ratio, when measured for the twelve-month period ended
June 30, 2002, was above the default threshold in its bond financing documents, and it was able to make the
July 31, 2002, interest payment without recourse to the project's debt service reserve.  EME believes that should
market and trading conditions experienced thus far in 2002 be sustained for the balance of the year, First
Hydro's interest coverage ratio will also be above the default and distribution thresholds when measured for the
twelve-month period ended December 31, 2002.  Compliance by First Hydro with these and other requirements of its
bond financing documents are subject, however, to market conditions for the sale of energy and ancillary
services.  These market conditions are beyond EME's control.

New Zealand
-----------

A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers
and forward contracts with other wholesale electricity counterparties.  Contact Energy has entered into forward
contracts of varying terms that expire on various dates through March 31, 2007, and option contracts of varying
terms that expire on various dates through December 31, 2003.  The New Zealand Government commissioned an inquiry
into the electricity industry in February 2000.  Following the inquiry report the New Zealand Government released
a Government Policy Statement, at the center of which was a call for the industry to rationalize the three
existing industry codes, form a single governance structure and address transmission pricing methodology.  The
Government Policy Statement also requested a model use of system agreement be developed, that is, a framework by
which the retailers contract for services from each of the distribution networks, and a consumer complaints
ombudsman be established.  An essential theme throughout the Government Policy Statement was the desire that the
industry retain a private multilateral self-governing structure.  During 2001, an amendment to the Electricity
Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the
Government's call.  A draft single governance code was put forward to the New Zealand Commerce Commission for
approval early in 2002.  In October 2002, the Commerce Commission approved the new arrangements in the form of a
rulebook for the self-governance of the electricity sector.  The Commission conditioned this authorization upon:

o        changes to the governance arrangements to ensure that pro-competitive and public benefit enhancing rule
         changes are not delayed unduly in working groups;

o        changes to the governance arrangements to allow the Electricity Governance Board discretion to override
         an industry vote opposing a pro-competitive and public benefit enhancing rule change;

o        completion of the drafting of rules dealing with consumer issues; and

o        a review of the efficacy of the part of the rulebook dealing with transmission services after two years.

The authorization will expire four years from the date of the implementation of the rulebook, or on March 31,
2007, whichever is earlier.

Credit Risks

In conducting its price risk management and trading activities, EME contracts with a number of utilities, energy
companies and financial institutions.  Due to factors beyond EME's control, market liquidity has decreased
significantly since the beginning of 2002, and a number of formerly significant trading parties have completely
withdrawn from the market or substantially reduced their trading activities.  The reduction in the credit quality
of traditional trading parties increases EME's credit risk.  In addition, the decrease in market liquidity may
require EME to rely more heavily on wholesale electricity sales to direct customer markets, which may increase
EME's credit risk.  In the event a counterparty were to default on its trade obligation, EME would be exposed to
the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing
counterparty were unable to pay the resulting liquidated

Page 52


damages owed to EME.  Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for
products delivered prior to the time such counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by its counterparties.  Credit risk is
measured by the loss EME would record if its counterparties failed to perform pursuant to the terms of their
contractual obligations.  EME has established controls to determine and monitor the creditworthiness of
counterparties and use master netting agreements whenever possible to mitigate its exposure to counterparty
risk.  EME may require counterparties to pledge collateral when deemed necessary.  EME tries to manage the credit
in the portfolio based on credit ratings.  EME uses published ratings of counterparties to guide it in the
process of setting credit levels, risk limits and contractual arrangements including master netting agreements.
Where external ratings are not available, EME conducts internal assessments of credit risks of counterparties
using publicly disclosed information, such as financial statements, regulatory filings, and press releases.  The
credit quality of EME's counterparties is reviewed regularly by its risk management committee.  EME also monitors
the concentration of credit risk from various positions, including contractual commitments.  Credit concentration
is determined on both an individual and group counterparty basis.  In addition to continuously monitoring its
credit exposure to its counterparties, EME also takes appropriate steps to limit exposures, initiate actions to
lower credit exposure and take credit reserves if appropriate.

ExGen accounted for 36% and 42% of EME's consolidated operating revenue in 2001 and 2000, respectively.  ExGen
represents 39% of EME's consolidated revenue in the first nine months of 2002.  EME expects the percentage to be
less in 2003 because a smaller number of plants will be subject to contracts with ExGen.  See Illinois Plants
discussion in Market Risk Exposures section.  Any failure of ExGen to make payments under the power purchase
agreements could adversely affect EME's results of operations and financial condition.

Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of
EME's equity contributions to, and distributions from, EME's international projects.  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 U.S.
dollars or other indices reasonably expected to correlate with foreign exchange movements.  In addition, EME has
used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various
outcomes.  EME cannot provide assurances, however, that fluctuations in exchange rates will be fully offset by
hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a
manner that is consistent with historical or forecasted relationships.

The First Hydro plant in the U.K. and the Loy Yang B plant in Australia have been financed in their local
currencies, pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition
costs against foreign exchange fluctuations.  Furthermore, EME has evaluated the return on the remaining equity
portion of these investments with regard to the likelihood of various foreign exchange scenarios.  These analyses
use market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to
predict ranges of expected returns.

During the first nine months of 2002, foreign currencies in the U.K., Australia and New Zealand increased in
value compared to the U.S. dollar by 8.0%, 6.2% and 12.9%, respectively (determined by the change in the exchange
rates from December 31, 2001, to September 30, 2002).  The increase in value of these currencies was the primary
reason for the foreign currency translation gain of $71 million during the first nine months of 2002.

Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency
commitments associated with transactions in the ordinary course of business.  The contracts are primarily in
Australian and U.S. dollars with varying maturities through September 2003.  At September 30, 2002, the
outstanding notional amount of the contracts totaled $32 million and the fair value of the

Page 53


contracts totaled $(300,000).  During the first nine months of 2002, Contact Energy recognized a foreign exchange
loss of $400,000 related to the contracts that matured during the period.

In addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of
business.  These cross currency swap contracts involve swapping fixed and floating-rate U.S. and Australian
dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018.

EME will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of
hedging strategies in the future.



Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used for purposes
other than trading by risk category and instrument type:

                                                                 September 30,       December 31,
 In millions                                                         2002                2001
-----------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------

 Derivatives:
    Interest rate:
      Interest rate swap/cap agreements                          $   (39.7)          $  (35.8)
      Interest rate options                                           (1.1)              (1.0)
    Commodity price:
      Forwards                                                        38.6               63.8
      Futures                                                         (0.5)              (8.4)
      Options                                                         (0.6)               0.4
      Swaps                                                         (141.8)            (137.6)
    Foreign currency forward exchange agreements                      (0.3)              (0.6)
    Cross currency interest rate swaps                                14.9               27.6
-----------------------------------------------------------------------------------------------------



In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods
and assumptions based on the market conditions and associated risks existing at each balance sheet date.  The
fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility
of the underlying commodities and other factors.  The following table summarizes the maturities, the valuation
method and the related fair value of EME's commodity risk management assets and liabilities (as of September 30,
2002):



                                                Total     Maturity     Maturity     Maturity       Maturity
                                                Fair    lesser than    1 to 3       4 to 5       greater than
 In millions                                    Value      1 year       years         years        5 years
------------------------------------------- ------------ ------------ ----------- ------------ ------------
------------------------------------------- ------------ ------------ ----------- ------------ ------------

Prices actively quoted                       $     7.5    $   5.3      $   2.3     $   (0.1)    $    --
Prices based on models and other
   valuation methods                            (111.8)      (7.3)        (7.0)       (21.2)        (76.3)
------------------------------------------- ------------ ------------ ----------- ------------ ------------
------------------------------------------- ------------ ------------ ----------- ------------ ------------
Total                                        $  (104.3)   $  (2.0)     $  (4.7)    $  (21.3)    $   (76.3)
------------------------------------------- ------------ ------------ ----------- ------------ ------------



The fair value of the electricity rate swap agreements (included under commodity price swaps) entered into by the
Loy Yang B plant has been estimated by discounting the future net cash flows resulting from the difference
between the average aggregate contract price per MW and a forecasted market price per MW multiplied by the number
of MW remaining to be sold under the contract.


Page 54



Energy Trading Derivative Financial Instruments

On September 1, 2000, EME acquired the trading operations of Citizens Power LLC and, subsequently, combined them
with its risk management and trading operations, now conducted by EME's subsidiary, Edison Mission Marketing &
Trading, Inc.  As a result of a number of industry and credit related factors, EME has minimized its price risk
management activities and its trading activities with third parties not related to its power plants or
investments in energy projects.  See Current Developments Related to EME. To the extent EME engages in trading
activities, EME seeks to manage price risk and create stability of future income by selling electricity in the
forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by
buying and selling these commodities in wholesale markets. Approximately 2,746 GWh of EME's energy trading
contracts (excluding the power sales agreement with an unaffiliated electric utility) were physically settled
during the third quarter ended September 30, 2002.  EME generally balances forward sales and purchase contracts
and manages its exposure through a value at risk analysis as described further below.

The fair value of the financial instruments, including forwards, futures, options and swaps, related to energy
trading activities as of September 30, 2002, and December 31, 2001, which include energy commodities, are set
forth below:



                                                             September 30, 2002             December 31, 2001
                       --------------------------------------------------------------------------------------------
                       --------------------------------------------------------------------------------------------
                         In millions                        Assets     Liabilities         Assets     Liabilities
                       --------------------------------------------------------------------------------------------
                             --------------------------------------------------------------------------------------------

                               Forward contracts                 $  123.5      $   27.5          $  4.6       $  2.9
                               Futures contracts                      0.1           --              0.1          0.1
                               Option contracts                       0.1           --              --           --
                               Swap agreements                        5.9           6.2             0.2          --
                             --------------------------------------------------------------------------------------------
                             --------------------------------------------------------------------------------------------

                               Total                             $  129.6      $   33.7          $  4.9       $  3.0
                             --------------------------------------------------------------------------------------------



Quoted market prices are used to determine the fair value of the financial instruments related to energy trading
activities, except for the power sales agreement with an unaffiliated electric utility that EME purchased and
restructured and a long-term power supply agreement with another unaffiliated party.  EME recorded these
agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model
using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of
the power supply agreement.  The following table summarizes the maturities, the valuation method and the related
fair value of our energy trading assets and liabilities (as of September 30, 2002):



                                             Total      Maturity      Maturity     Maturity      Maturity
                                             Fair      lesser than     1 to 3       4 to 5     greater than
In millions                                  Value       1 year         years       years        5 years
------------------------------------------ ------------ ------------ ----------- ------------- -------------
------------------------------------------ ------------ ------------ ----------- ------------- -------------
Assets:
Prices actively quoted                      $    2.5     $    5.4     $   (2.9)    $   --       $    --
Prices based on models and other
   valuation methods                            93.4         (3.4)         3.3         7.4          86.1
------------------------------------------ ------------ ------------ ----------- ------------- -------------
------------------------------------------ ------------ ------------ ----------- ------------- -------------
Total                                       $   95.9     $    2.0     $    0.4     $   7.4      $   86.1
------------------------------------------ ------------ ------------ ----------- ------------- -------------





Page 55


The net realized and unrealized gains or losses arising from energy trading activities for the three- and
nine-month periods ended September 30, 2002, and 2001 are as follows:



                                             Three Months Ended                 Nine Months Ended
                                               September 30,                      September 30,
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
 In millions                                2002          2001                2002           2001
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
 Operating Revenue
 Forward contracts                         $ 19.8        $  5.6              $ 40.0         $   7.2
 Futures contracts                           (0.1)          0.1                (0.7)           (1.8)
 Option contracts                            (0.5)         (3.0)               (1.0)           (0.1)
 Swap agreements                             (5.6)          0.4                (1.7)            0.2
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
                                           $ 13.6        $  3.1              $ 36.6         $   5.5
 Total
--------------------------------------------------------------------------------------------------------



The unrealized gain (loss) from energy trading activities included in the above amounts was $2 million and
$6 million for the three-month periods ended September 30, 2002, and 2001, respectively, and $13 million and
$(11) million for the nine-month periods ended September 30, 2002, and 2001, respectively.

Edison Capital

Edison Capital has investments with a number of counterparties and in a number of geographic regions, which may
periodically experience financial or economic difficulties and increase the risk to Edison Capital's
investments.  This includes aircraft leased to major, domestic airlines, power plants selling to domestic
utilities and investments in global emerging markets which are all currently experiencing economic difficulties.
Edison Capital cannot determine whether any adverse impact will result from difficulties in these sectors or
regions, but Edison Capital is closely monitoring its investments and will take actions necessary or appropriate
to protect its interests.

Specifically, Edison Capital has leased two aircraft to United Airlines with a current potential earnings
exposure of $37 million and three aircraft to American Airlines with a current potential earnings exposure of
$46 million, in the event of repossession of the aircrafts.  Each aircraft also secures the repayment of loans
borrowed to purchase the aircraft.  United Airlines has publicly indicated that it is considering filing for
reorganization in bankruptcy.  In the event of bankruptcy, the leases may be affirmed, rejected or renegotiated.
Each lender with a security interest in the aircraft may also seek to re-possess the aircraft in the event of
bankruptcy or default in loan repayments.  United Airlines has also contacted Edison Capital regarding its
remaining lease obligations and its desire to avoid bankruptcy.  There are no existing defaults, each required
lease payment has been timely made, and each airline had informed Edison Capital that each aircraft continues to
be in service.  The next payment from United Airlines is due in December 2002.  At this time, Edison Capital is
unable to determine the likelihood or estimate the amount of potential losses related to its aircraft leases.

Edison Capital is, and may in the future be, under examination by tax authorities in various jurisdictions
regarding tax positions taken in connection with its investments.  For example, the IRS is generally challenging
several types of leveraged lease transactions.  While Edison Capital has a number of leveraged leases, Edison
Capital believes its transactions are legally and factually distinguished from the positions taken by the IRS,
and Edison Capital believes it should prevail against both current and potential future challenges to its tax
positions.  However, an unfavorable outcome, contrary to Edison Capital's current expectations, could be material.

OFF-BALANCE SHEET TRANSACTIONS

Sale-Leaseback Transactions

On August 9, 2002, EME's subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois
peaker power units that were subject to a lease with a third-party lessor.  As disclosed in the Off-Balance Sheet
Transactions section of the year-end 2001 MD&A, this operating lease was structured

Page 56


to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in
accordance with existing guidance for leases involving special purpose entities (sometimes referred to as
synthetic leases).  In order to fund the purchase, EME received $255 million as repayment of the note receivable
held by EME and paid $300 million plus outstanding lease obligations to the owner-lessor.  Accordingly, EME's net
cash outlay was $46 million.  These peaker units were recorded as assets and are being depreciated over their
estimated useful lives of 15 years.

Master Turbine Lease

In September 2002, EME notified the lessor (Siemens Westinghouse) of its election to terminate all of its
equipment purchase contracts for nine turbines effective October 25, 2002.  The termination of the equipment
purchase order reduced EME's projected capital expenditures by $53 million.  EME recorded a $61 million pre-tax
loss in the third quarter of 2002 related to the write-off of capitalized costs associated with the turbines, as
previously discussed in the Results of Operations.

ACQUISITIONS AND DISPOSITIONS

During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and
James River projects and its 30% interest in the Harbor project.  Proceeds received from the sales were
$44 million.  During the second half of 2001, EME recorded asset impairment charges of $33 million related to
these projects based on the expected sales proceeds.  No gain or loss was recorded from the sale of EME's
interests in these projects during the first quarter of 2002.

SCE'S REGULATORY MATTERS

Generation and Power Procurement

CPUC Litigation Settlement Agreement
------------------------------------

In October 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a
ruling that SCE is entitled to full recovery of its past electricity procurement costs.  The Utility Reform
Network (TURN), a consumer advocacy group, and other parties appealed to the federal court of appeals seeking to
overturn the stipulated judgment of the district court that approved the settlement agreement.  On March 4, 2002,
the United States Court of Appeals for the Ninth Circuit heard argument on the appeal, and on September 23, 2002,
the court issued its opinion.  In the opinion, the court affirmed the district court on all claims, with the
exception of the challenges founded upon California state law, which the appeals court referred to the California
Supreme Court.  Specifically, the appeals court affirmed the district court in the following respects:  (1) the
district court did not err in denying the motions to intervene brought by entities other than TURN; (2) the
district court did not err in denying standing for the entities other than TURN to appeal the stipulated
judgment; (3) the district court was not deprived of original jurisdiction over the lawsuit; (4) the district
court did not err in declining to abstain from the case; (5) the district court did not exceed its authority by
approving the stipulated judgment without TURN's consent; (6) the district court's approval of the settlement
agreement did not deny TURN due process; and (7) the district court did not violate the Tenth Amendment of the
United States Constitution in approving the stipulated judgment.  In sum, the appeals court concluded that none
of the substantive arguments based on federal statutory or constitutional law compelled reversal of the district
court's approval of the stipulated judgment.

However, the appeals court stated in its opinion that there is a serious question whether the settlement
agreement violated state law, both in substance and in the procedure by which the CPUC agreed to it.  The appeals
court added that if the settlement agreement violated state law, the CPUC lacked capacity to consent to the
stipulated judgment, and the stipulated judgment would need to be vacated.  The appeals court indicated that, on
a substantive level, the stipulated judgment appears to violate California's electric industry restructuring
statute providing for a rate freeze.  The appeals court also indicated that, on a procedural level, the
stipulated judgment appears to violate California laws requiring open meetings and public hearings.  Because
federal courts are bound by the pronouncements of the state's highest court on applicable state law, and because
the federal appeals court found no controlling precedents from

Page 57


California courts on the issues of state law in this case, the appeals court issued a separate order certifying
those issues to the California Supreme Court and requested that the California Supreme Court accept certification.

The appeals court stayed further proceedings in the case pending a response from the California Supreme Court on
the request for certification.  The appeals court did not stay the continued operation of the settlement
agreement, thus collection of past procurement costs under PROACT is continuing.  On October 29, 2002, SCE filed
a brief requesting that the California Supreme Court answer the appeals' court certification and requesting that
the hearing of the matter be placed on the California Supreme Court's March 2003 calendar, or heard at the
court's earliest convenience.  SCE continues to operate under the settlement agreement.  SCE continues to believe
it is probable that SCE ultimately will recover its past procurement costs through regulatory mechanisms,
including the PROACT.  However, SCE cannot predict with certainty the outcome of the pending legal proceedings.

The provisions of the settlement agreement are described in the CPUC Litigation Settlement Agreement disclosure
in the year-end 2001 MD&A (pages 10 and 11).

In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition in the
California Supreme Court against the CPUC.  The FTCR's petition asserted that, among other things, the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE.  The petition sought a declaration that the CPUC cannot agree not to enforce any state law unless an
appellate court has determined that the state law is invalid, unconstitutional, or unenforceable.  The FTCR's
petition expressly stated that it did not seek any order from the California Supreme Court with respect to the
stipulated judgment implementing the settlement agreement between the CPUC and SCE; and the petition did not
request any judicial actions regarding the settlement agreement.  The FTCR is not a party to TURN's federal court
appeal concerning the stipulated judgment.  On August 14, 2002, the California Supreme Court issued a summary
denial of the FTCR's petition.

PROACT Regulatory Asset
-----------------------

In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, SCE established a
regulatory balancing account called the PROACT with an initial balance of $3.6 billion reflecting the net amount
of past procurement-related liabilities to be recovered by SCE.  Each month, SCE applies to the PROACT the
positive or negative difference between SCE's revenue from retail electric rates (including surcharges) and the
costs that SCE is authorized by the CPUC to recover in retail electric rates.  The balance in the PROACT was $2.6
billion at December 31, 2001, and $905 million on September 30, 2002.  SCE has previously projected that it will
recover the remaining balance of the procurement-related obligations in the PROACT by the end of 2003.  SCE still
believes this projection is appropriate, however, there are many important proceedings pending before the CPUC,
which depending upon decisions made, could cause the balance to be recovered by mid-2003.  Material factors that
would change SCE's estimate of the timing of PROACT recovery are:

o        the level of output of SCE's generating plants and contract power deliveries (for example, higher than
         forecasted output accelerates PROACT recovery);

o        authorized revenue changes for distribution, transmission, and SCE retained-generation costs (see
         discussion in GRC, PBR and URG Proceedings);

o        outcome of issues currently being addressed in the Generation Procurement Proceeding, including the
         allocation among the California utilities of power contracted by the CDWR and the related CDWR revenue
         requirement impacts;

o        SCE's share of the CDWR revenue requirement (see discussion in CDWR Revenue Requirement Proceeding);

o        disposition of the $0.006 temporary surcharge revenue (see discussion in Temporary Surcharge);


Page 58



o        level of retail sales (for example, higher than forecasted sales would accelerate PROACT recovery);

o        level of direct access (see Direct Access discussions below);

o        direct access customers' contribution to recovery of SCE's PROACT-related costs and to the CDWR's costs
         (see Direct Access discussions regarding the historical procurement charge and exit fees below);

o        a decision by the CPUC to allow SCE to recover $209 million used to hedge gas price risk associated with
         QF contracts (which has been incorporated into SCE's current projection of the timing of PROACT
         recovery; see discussion in Market Risk Exposures);

o        a decision by the CPUC, which could be made under the Settlement Agreement, directing $150 million of
         surplus revenue in both 2002 and 2003 to be used for any utility purpose (which would delay PROACT
         recovery); and

o        potential energy supplier refunds (see discussion in Wholesale Electricity Markets).

The following is an update on various regulatory proceedings impacting the timing of PROACT recovery:

Direct Access Proceedings
-------------------------

Direct Access - Historical Procurement Charge.  From 1998 through mid-September 2001, SCE's customers were able
to choose to purchase power directly from an energy service provider other than SCE (thus becoming direct access
customers) or continue to purchase power from SCE.  (Customers who continue to purchase power from SCE are
referred to as bundled service customers).  On March 21, 2002, the CPUC issued a final decision affirming that
new direct access arrangements entered into by SCE's customers after September 20, 2001, are invalid.  This
decision did not affect direct access arrangements in place before that date.  Direct access customers receive a
credit for the generation costs SCE saves by not serving them.  Electric utility revenue is reported net of this
credit.  Because of this credit, direct access power purchases resulted in additional undercollected power
procurement costs to SCE during 2000 and 2001.  On July 17, 2002, the CPUC issued an interim decision to
establish a nonbypassable historical procurement charge requiring direct access customers to pay $391 million of
SCE's past power procurement costs, and directed SCE to reduce the PROACT balance by $391 million and create a
new regulatory asset for the same amount.  The historical procurement charge is to be collected from direct
access customers by reducing their existing generation credit by 2.7(cent)per kWh (effective July 27, 2002)  until
the CPUC issues and implements an order to determine a surcharge for direct access customers' share of the CDWR's
costs, as discussed in the paragraph below.  Once that surcharge is implemented, the contribution by direct
access customers to the historical procurement charge would be reduced from 2.7(cent)per kWh to 1(cent)per kWh until the
$391 million is collected, with the remainder of the 2.7(cent)per kWh utilized for other costs associated with direct
access customers.  On October 16, 2002, SCE filed a petition with the CPUC to modify the historical procurement
charge interim decision to provide that direct access customers be responsible for $497 million of SCE's past
procurement costs.  Once the interim decision becomes permanent, SCE will evaluate whether a new regulatory asset
could be created.  If such a regulatory asset is created, the net effect of this action would be to accelerate
PROACT recovery.

Direct Access - Exit Fees.  In addition to the historical procurement charge, the CPUC, in a November 7, 2002,
decision, assigned responsibility for a portion of four other cost categories to the direct access customers.
The first category consists of the CDWR's power procurement costs incurred between January 17, 2001, and
September 30, 2001.  The CDWR is in the process of selling approximately $12 billion in bonds to repay the amounts
it borrowed to pay these costs. The CPUC decision stated that the direct access customers are responsible for
payment of the bond charge to recover the principal and financing costs associated with these bonds.  The second
category relates to the CDWR's power procurement costs for the last quarter of 2001 and the year 2002.  The CPUC
stated that direct access

Page 59


customers must pay a share of these costs to make bundled service customers indifferent to suspension by the CPUC
of the direct access program on September 20, 2001, rather than July 1, 2001.  The third category includes the
CDWR long-term contract costs for 2003 and beyond.  The CPUC decision stated that a portion of these costs should
be paid by direct access customers to keep bundled service customers indifferent to the later suspension of
direct access on the premise that the CDWR signed some of its long-term contracts with the expectation of serving
the load that switched to direct access after July 1, 2001.  Finally, the last category relates to the
above-market costs of SCE's URG (e.g., qualifying facilities contract costs) that pursuant to AB 1890 are to be
recovered from all customers on an ongoing basis.  The CPUC decision states that:  (1) the bond charge is
applicable to all direct access customers except those that were continuously on direct access and never used any
CDWR power (less than 1% of SCE's load); (2) the next two categories of costs are applicable to direct access
customers who took bundled service at any time after February 1, 2001; and (3) the last category is applicable to
all direct access customers, including continuous direct access customers.  The exact amount of exit fees
associated with the CPUC's decision will be addressed in workshops to be convened by the CPUC and implemented
following the workshops.

The impact of the November 7, 2002, decision is incorporated into SCE's current projection of the timing of
PROACT recovery.

Surcharge Decision
------------------

A March 2001, CPUC decision authorized SCE a 3(cent)surcharge and made permanent a 1(cent)temporary surcharge authorized
in January 2001, with the restriction that the revenue arising from both surcharges apply only to ongoing
procurement charges and future power purchases.  On November 7, 2002, the CPUC issued a decision modifying the
March 2001 decision to allow the surcharge revenue to be used not only for power costs but also for returning SCE
to reasonable financial health.  The decision stated that the extent to which the surcharge revenue could be used
for future power costs or obtaining reasonable financial health would be the subject of future proceedings.  The
decision ordered SCE to continue tracking surcharge revenue in balancing accounts, as they remain subject to
later adjustment and possible refund.  This decision is incorporated into SCE's current projection of the timing
of PROACT recovery.

Temporary Surcharge
-------------------

As discussed in Operating Revenue, the CPUC allowed the continuation of the $0.006 surcharge that was scheduled
to terminate in June 2002 and required SCE to track the associated revenue in a balancing account, until the CPUC
determines the use of the surcharge.  The continuation of the surcharge will result in an increase to revenue and
cash by as much as $200 million in 2002 and $350 million in 2003, but will have no impact on earnings.  SCE has
filed testimony in the CDWR Revenue Requirement phase of the Rate Stabilization Proceeding proposing that this
increase in revenue be used to partially offset the CDWR's higher 2003 revenue requirement, and has incorporated
that assumption into its current projection of the timing of PROACT recovery.

URG Decision
------------

On April 4, 2002, the CPUC issued a decision to return generation assets retained by SCE (utility-retained
generation) to cost-of-service ratemaking until the implementation of the 2003 general rate case (GRC) proceeding
described below.  The URG decision:

o        Allows recovery of incurred costs for all URG components other than San Onofre Units 2 and 3, subject to
         reasonableness review by the CPUC;

o        Retains the incremental cost incentive pricing mechanism (ICIP) for San Onofre Units 2 and 3 through
         2003;



Page 60


o        Establishes an amortization schedule for SCE's nuclear facilities that reflects their current remaining
         Nuclear Regulatory Commission license durations, using unamortized balances as of January 1, 2001, as a
         starting point;

o        Establishes balancing accounts for the costs of utility generation, purchased power, and ancillary
         services from the ISO; and

o        Continues the use of SCE's last CPUC-authorized return on common equity of 11.6% for SCE's URG rate base
         other than San Onofre Units 2 and 3, and keeps in place the 7.35% return on rate base for San Onofre
         Units 2 and 3 under the ICIP.

Based on this decision, during the second quarter of 2002, SCE reestablished for financial reporting purposes
regulatory assets related to its unamortized nuclear facilities, purchased-power settlements and flow-through
taxes, reduced the PROACT regulatory asset balance (by $256 million), and recorded a corresponding credit to
earnings of $480 million after tax.  The reduction in the PROACT balance reflects a change in SCE's unamortized
nuclear facilities amortization schedule to reflect a ten-year amortization period rather than a four-year
amortization period, which was used to calculate the PROACT, for ratemaking purposes, during the last four months
of 2001.  Implementation of the URG decision, together with the PROACT mechanism, allowed SCE to reestablish
substantially all of the regulatory assets previously written off to earnings.

CDWR Revenue Requirement Proceeding
-----------------------------------

On August 16, 2002, the CDWR issued an updated revenue requirement of $5.8 billion for calendar year 2003, for
its bond costs and power procurement costs.  On November 8, 2002, however, the CDWR informed the CPUC that it was
lowering the bond-related portion of its annual revenue requirement from $1.14 billion to approximately $745
million.  As a result, its total 2003 revenue requirement is now approximately $5.4 billion.

In a decision dated September 19, 2002, the CPUC allocated the CDWR's entire portfolio of long-term contracts
among the three investor-owned utilities (further discussed in Generation Procurement Proceeding).  While the
variable costs of the contracts were also allocated to follow the contracts in that decision, allocation of the
fixed costs for the contracts was delegated to the CDWR Revenue Requirement Proceeding.

In its February 21, 2002, decision allocating the CDWR's 2001-2002 revenue requirement, the CPUC assigned $3.5
billion (38.2%) of the CDWR's total revenue requirement of $9 billion to SCE.  This resulted in an average annual
CDWR revenue requirement of $1.7 billion being allocated to SCE.  Based on the August 16, 2002, revised 2003 CDWR
revenue requirement, the modified bond charge revenue requirement and the CPUC's allocation of the CDWR contracts
and total contract costs, SCE's share of the CDWR's 2003 revenue requirement is estimated to be approximately
$2.2 billion.  This amount consists of approximately 40% of the CDWR's power charge revenue requirement of $4.7
billion and approximately 45% of the CDWR's bond charge revenue requirement of $745 million.  Therefore, SCE's
share of the total CDWR's 2003 revenue requirement is expected to be about $450 million higher than SCE's share
of the average annual 2001-2002 CDWR revenue requirement.  This amount is incorporated into SCE's current
projection of the timing of PROACT recovery.  A larger allocation would delay PROACT recovery.

In its February 21, 2002, decision, the CPUC ordered that allocation of that revenue requirement to each utility
be trued-up based on the CDWR's actual recorded costs for the 2001-2002 period and a specific methodology set
forth in that decision. The presiding administrative law judge in the Rate Stabilization Proceeding has issued a
preliminary ruling deferring the true-up of the CDWR's 2001-2002 revenue requirement and its allocation to the
utilities to the second quarter of 2003 when all of the CDWR's 2002 recorded expenses will be available.  SCE has
filed a brief opposing deferral of the true-up of the CDWR's 2001-2002 revenue requirement to the second quarter
of 2003 on the grounds that the true-up should be performed based on the available data at this time and be used
to adjust the utilities' allocation of the

Page 61


CDWR's 2003 revenue requirement.  A true-up of the CDWR's revenue requirement has not been incorporated into
SCE's current projection of the timing of PROACT recovery.

On October 24, 2002, the CPUC issued a decision which adopts a methodology for establishing a charge to repay
bond-related costs resulting from the CDWR's bond sale to refinance an interim loan taken to cover electricity
costs and to repay advances from the State's General Fund used to pay its procurement costs over the first nine
months of 2001.  The bond charge is to be set by dividing the annual revenue requirement for bond-related costs
by an estimate of the annual electricity consumption of bundled service customers subject to the charge.  The
charge will apply to electricity consumed on and after November 15, 2002.  In a November 7, 2002, decision, the
CPUC assigned responsibility for a portion of the bond charge to direct access customers. (see Direct Access -
Exit Fees).  This decision is incorporated into SCE's current projection of the timing of PROACT recovery.

Generation Procurement Proceeding
---------------------------------

In October 2001, the CPUC issued an order instituting rulemaking (OIR) directing SCE and the other major
California electric utilities to provide recommendations for establishing policies and mechanisms to enable the
utilities to resume power procurement by January 1, 2003.

SCE filed testimony on May 1, 2002, that proposed specific elements of a broad procurement framework including
processes to assure full, certain and timely recovery of reasonable procurement costs, and clear guidelines and
pre-approvals, when appropriate, instead of after-the-fact reasonableness reviews.  The testimony also set forth
a detailed plan for SCE resuming procurement beginning in 2003 that focused on how to best serve the load
requirements of its bundled retail customers that is not met by SCE's existing generation supply and SCE's
allocated share of the CDWR contracts.

SCE also requested approval by the CPUC of a proposed interim procedure allowing SCE to enter into new contracts
for capacity products jointly with the CDWR prior to January 1, 2003.

On August 22, 2002, the CPUC issued a decision authorizing the utilities to enter capacity contracts between the
effective date of the decision and January 1, 2003, referred to as the transition procurement period.  The CPUC
must approve or disapprove the transitional contracts or procurement process proposed by a utility by means of an
expedited advice letter process.  Costs incurred under these CPUC-approved contracts will be considered
reasonable and prudent for cost recovery.  The decision also requires the utilities to procure, during this
transition procurement period, at least one percent of their annual electricity sales through a set-aside
competitive procurement process for renewable resources.

Pursuant to the authority to enter into transitional procurement contracts, SCE initiated a request for offers
from a large number of suppliers for various capacity and energy products.  SCE negotiated transactions with
several suppliers and has submitted an advice letter to the CPUC on November 5, 2002, requesting review and
approval of these transactions.  A decision is expected to be made at the CPUC meeting on December 5, 2002.  If
the CPUC approves these capacity contracts, SCE will then enter into further negotiations with these suppliers to
finalize pricing and quantity, and SCE will, if the final pricing and quantity terms are acceptable, execute some
or all of the contracts.

The OIR proceeding also addressed the issue of allocating the contracts previously entered into by the CDWR among
the three major California utilities.  A decision setting the allocation of the CDWR contracts among the three
utilities was issued on September 19, 2002.  The decision allocated the contracts on a contract-by-contract
basis.  The decision significantly reduces SCE's residual net short and also increases the likelihood that SCE
will have excess power during certain periods, particularly after 2003.  Revenue from the sale of such surplus
energy is to be prorated between the CDWR contracts (to be credited to the CDWR's revenue requirement) and the
other resources in the utility's portfolio.  Under the decision, utility responsibility for the contracts is
limited to that of scheduling and dispatch.  SCE is attempting to negotiate with the CDWR the terms under which
this responsibility will be carried out.  Legal title, financial reporting and responsibility for the payment of
contract-related bills remains with the CDWR.  As such, a portion of the revenue from surplus energy sales, as
well as all of the expense for power purchased under the


Page 62


CDWR allocated contracts will not be recognized as revenue or purchased power expense by SCE.  The cost
allocation among the utilities of the CDWR revenue requirement, which is composed in large part of contract
costs, is to be determined in a separate proceeding (see CDWR Revenue Requirement Proceeding above).

AB 57, which provides for SCE and the other California utilities to resume procuring power for their customers
was signed into law by the Governor of California in September 2002.  A second bill, SB 1976, was enacted not
long after AB 57 to shorten the time period between adoption and the implementation of a utility's procurement
plan from 90 to 60 days.  Collectively, AB 57 and SB 1976 provide that a procurement plan approved for a utility
by the CPUC should, among other things:  (a) enable the utility to fulfill its obligation to serve its customers
at just and reasonable rates; (b) eliminate the need for after-the-fact reasonableness reviews of the utility's
actions in compliance with the plan; (c) ensure timely recovery of costs incurred under the plan; and
(d) moderate the price risk to the utility of serving its retail customers.  In addition, AB 57 provides that the
CPUC shall not approve a feature or mechanism in a utility's procurement plan if the CPUC finds that it would
impair the restoration of, or lead to a deterioration of, the utility's creditworthiness.

On October 24, 2002, the CPUC issued a decision ordering the utilities to resume procurement and adopting the
regulatory framework under which the utilities shall resume full procurement responsibilities on January 1,
2003.  The decision distinguishes the utilities' responsibilities on the basis of short-term (2003) versus
long-term (2004-2024) procurement.  It adopts the utilities' procurement plans filed on May 1, 2002, and directs
that they be modified prior to January 1, 2003, to reflect the decision, the allocation of existing CDWR
contracts, and any procurement done under the August 26, 2002, decision.  The October 24, 2002, decision also
sets forth a detailed process and procedural schedule to develop long-term procurement planning that includes the
filing by each utility of a long-term plan by April 1, 2003, and an evidentiary hearing in early July 2003.  In
addition, the decision calls for each of the utilities to establish a balancing account, to be known as the
energy resource recovery account, to track energy costs.  These balancing accounts will be used for examining
procurement rate adjustments on a semi-annual basis, as well as on a more expedited basis in the event fuel and
purchased-power costs exceed a prescribed threshold.  SCE believes there are a number of important issues in the
decision that must be clarified by the CPUC in order to have a procurement framework consistent with AB 57.  In
particular, the decision language regarding reasonableness of utility actions is vague in a number of respects,
and could expose SCE to after-the-fact reasonableness review.  Moreover, there is no time frame for the CPUC to
complete these reasonableness reviews.  Although the decision adopts the procurement plan SCE submitted in May
2002, it is not clear whether SCE has the authority to begin procuring before late December 2002. SCE intends to
seek rehearing of this decision and will ask for clarification in future filings.

On November 12, SCE filed its modified short-term procurement plan pursuant to the CPUC's October 24, 2002,
decision.  SCE's modified plan updates its May filing in several respects including the final allocation of the
CDWR power contracts, SCE's renewable generation solicitation, revised residual net short estimates, and
potential collateral requirements.  SCE's modified plan also seeks clarification of the CPUC's procurement
oversight framework.  In particular, SCE's plan reflects the following views:  the CPUC must exercise its
oversight authority over the entire resource portfolio in a manner consistent with AB 57; the CPUC must eliminate
after-the-fact reasonableness reviews for all actions taken in compliance with a CPUC-approved procurement plan;
to the extent deficiencies are discovered in an approved plan, the CPUC must make adjustments prospectively only;
for actions not in compliance with the plan, disallowances should be levied only based on clear and convincing
evidence that the actions were outside a range of reasonable managerial conduct and had a net detrimental effect
on customers; the burden of presenting clear and convincing proof that management has acted unreasonably should
rest with the party making such allegations; and finally, SCE's modified plan seeks a limitation on possible
disallowances to no more than its annual cost of administering the procurement function, except in cases of
fraud, willful misconduct, gross negligence or self dealing.


Page 63



Mohave Generating Station Application
-------------------------------------

On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of the
Mohave Generating Station (Mohave).  Mohave obtains all of its coal supply from a mine in northeast Arizona on
lands of the Navajo Nation and Hopi Tribe (the Tribes).  This coal is delivered from the mine to Mohave by means
of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the
Tribes in the mine vicinity.

Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water
supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend
Mohave's operation beyond 2005.  Uncertainty over a post-2005 coal supply has also prevented SCE and the other
Mohave co-owners from starting to install extensive pollution control equipment that must be put in place if
Mohave's operations are extended past 2005.

SCE intends to continue to participate in discussions to resolve the coal supply and slurry-water supply issues.
SCE's application states that if SCE obtains adequate assurance by the end of 2002 that these issues will be
satisfactorily resolved, it will seek CPUC authorization for making the necessary pollution control expenditures
and certain other investments upon determination that such expenditures are economic and in SCE's customer's
interest.  Because SCE expects that CPUC action on such a request could take a year or more, SCE's May 17, 2002,
application requests either:  a) pre-approval for SCE to immediately begin spending up to $58 million on Mohave
pollution controls in 2003, if by year-end 2002, SCE has obtained adequate assurance the outstanding coal and
slurry-water issues can be satisfactorily resolved; or b) authority for SCE to establish certain balancing
accounts and otherwise begin preparing to terminate Mohave's coal-fired operations at the end of 2005.

Several parties filed protests or responses to SCE's application.  Some of these support, at least in part,
authorization for the interim funding to extend Mohave's operation, but none of them provide, in SCE's view,
solutions to the coal and slurry-water issues that must be resolved for Mohave to be reasonably assured of a
post-2005 coal supply.  The CPUC administrative law judge has ordered all parties in the proceeding to file, by
November 21, 2002, an all-party joint statement with an updated summary of the facts and issues associated with
SCE's application.  SCE continues to request a decision on interim funding by the end of 2002.

For additional matters related to the Mohave Generating Station see the Navajo Nation Litigation discussion under
the Other Developments section.

The outcome of SCE's application is not expected to impact Mohave's operation through 2005.  Consequently, this
matter has no impact on the timing of PROACT recovery.

Transmission and Distribution

PBR Decision
------------

SCE's revenue related to distribution operations is determined through a PBR mechanism.  The distribution PBR
mechanism was to have ended in December 2001, but in June 2001 the CPUC extended the mechanism until SCE's next
GRC, which is expected to be effective in 2003.  On April 22, 2002, the CPUC issued a decision that modifies the
PBR mechanism in the following significant respects:

o        SCE's current PBR distribution sales mechanism is converted to a revenue requirement mechanism to
         prevent material revenue undercollections or overcollections resulting from changes in retail rates.  A
         balancing account will be established to record any undercollections or overcollections.  This is
         retroactively effective as of June 14, 2001.  SCE established this balancing account as of the date of
         the decision.

o        A methodology is adopted for setting SCE's distribution revenue requirement for June 14 to December 31,
         2001, calendar year 2002, and calendar year 2003 until replaced by the GRC.  The methodology
         (a) establishes 2000 as the base year, (b) annually adjusts SCE's distribution

Page 64


         revenue requirement by the change in the Consumer Price Index minus a productivity factor of 1.6%, and
         (c) annually increases SCE's distribution revenue requirement to account for additional costs of
         expanding the distribution network to connect new customers (an allowance of about $650 per customer).

o        The performance benchmarks for worker safety, customer satisfaction, and outage frequency are updated
         beginning in 2002 to reflect improvements in SCE's performance.  These changes will reduce rewards SCE
         would earn compared to the previous standards.

As a result of this decision,  SCE recorded credits to earnings of approximately $26 million for revenue
undercollections during the period June 14, 2001, through December 31, 2001, and has recorded credits to earnings
of $79 million for the nine-month period ended September 30, 2002.  SCE projects additional credits to earnings
for revenue undercollections of approximately $30 million for the remainder of 2002.  All of these amounts are on
an after-tax basis.  This decision is incorporated into SCE's current projection of the timing of PROACT recovery.

CPUC GRC Proceeding
-------------------

In December 2001, SCE submitted a notice of intent to file its 2003 GRC with the CPUC, requesting an increase of
approximately $500 million in revenue (compared to 2000 recorded revenue) for its distribution and generation
operations.  On May 3, 2002, SCE filed its formal application for the 2003 GRC.  After taking into account the
effects of the CPUC's April 22, 2002, PBR decision, SCE reduced the revenue increase requested in the application
to $286 million.  The requested revenue increase is primarily related to capital additions and projected
increases in pension and benefit expenses.  In October 2002, the CPUC's Office of Ratepayer Advocates issued its
testimony and recommended a $172 million decrease in SCE's base rates.  Hearings are now scheduled to begin in
November 2002.  A final decision is expected in the third quarter of 2003.  SCE's requested revenue increase has
been incorporated into the current projection of the timing of PROACT recovery.

Cost of Capital Decision
------------------------

On November 7, 2002, the CPUC issued a decision in SCE's cost of capital proceeding, adopting an 11.6% return on
common equity for 2003 for SCE's CPUC jurisdictional assets.  This decision is incorporated into SCE's current
projection of the timing of PROACT recovery.

Electric Line Maintenance Practices Proceeding

In August 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices.  The OII is based on a report issued by the CPUC's Protection and Safety
Consumer Services Division (CPSD), which alleges SCE had a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000.  The OII also alleges that noncomplying
conditions were involved in 37 accidents resulting in death, serious injury, or property damage.  The CPSD
identified 4,721 alleged violations of the General Orders during the three-year period.  The OII placed SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation.

Prepared testimony was filed on this matter in April 2002, and hearings were concluded in September 2002.  In
opening briefs filed on October 21, 2002, the CPSD recommended SCE be assessed a penalty of $97 million, while
SCE requested that the CPUC dismiss the proceeding and impose no penalties.  SCE stated in its opening brief that
it has acted reasonably, allocating its financial and human resources in pursuit of the optimum combination of
employee and public safety, system reliability, cost-effectiveness, and technological advances.  SCE also
encouraged the CPUC to transfer consideration of issues related to development of standardized inspection
methodologies and inspector training to an order instituting rulemaking to revise these General Orders opened by
the CPUC in October 2001, or to a new rulemaking proceeding.  Reply briefs are due on November 18, 2002, and a
decision is expected by year-end 2002 or early 2003.  SCE is unable to predict with certainty whether this matter
ultimately will result in any material financial penalties or impacts on SCE.


Page 65



Wholesale Electricity Markets

On July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges by energy
suppliers to the ISO and PX spot markets to sales 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 conducted
evidentiary hearings on this matter in March, August and October 2002.  An initial decision from the judge is
expected by the end of 2002 and a decision by the FERC is expected in 2003.  On August 13, 2002, in an
investigation proceeding, the FERC's staff issued an initial report on manipulation of electric and natural gas
prices, which identified fundamental flaws in the use of the gas price presently included in the methodology for
calculating refunds.  Parties have filed comments on the FERC's staff's initial report.  SCE cannot yet determine
the likelihood that the initial report will affect either the timing of the FERC's determination of refunds or
the amount of any potential refunds.  Under the settlement agreement with the CPUC, any refunds will be applied
to reduce the PROACT balance until the PROACT is fully recovered.  After PROACT recovery is complete, 90% of any
refunds will be refunded to ratepayers.  SCE has not incorporated any potential refunds into its current
projection of the timing of PROACT recovery.

On July 17, 2002, the FERC issued an order reviewing the ISO's proposals to redesign the market and implementing
a market power mitigation program for the 11-state western region.  The FERC declined to extend beyond September
30, 2002, all of the market mitigation measures it had previously adopted.  However, effective October 1, 2002,
the FERC extended a requirement, first ordered in its June 19, 2001, decision, that all western energy sellers
offer for sale all operationally and contractually available energy.  It also ordered a cap on bids for real-time
energy and ancillary services of $250/MWh to be effective beginning October 1, 2002, and ordered various other
market power mitigation measures.  Implementation of the $250/MWh bid cap and other market power mitigation
measures were delayed until October 31, 2002, by a FERC order issued September 26, 2002.  The FERC did not set a
specific expiration date for its new market mitigation plan.  SCE cannot yet determine whether the new market
mitigation plan adopted by the FERC will be sufficient to mitigate market price volatility in the wholesale
electricity markets in which SCE will be purchasing its residual net short electricity requirements.

Holding Company Proceeding

In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision authorizing
utilities to form holding companies and initiates an investigation into, among other things:  whether the holding
companies violated CPUC requirements to give first priority to the capital needs of their respective utility
subsidiaries; 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.  On January 9, 2002, the CPUC
issued an interim decision on the first priority condition.  The decision stated that, at least under certain
circumstances, the condition includes the requirement that holding companies infuse all types of capital into
their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve.  The decision
did not determine if any of the utility holding companies had violated this condition, reserving such a
determination for a later phase of the proceedings.  On February 11, 2002, SCE and Edison International filed an
application for rehearing of the decision.  On July 17, 2002, the CPUC affirmed its earlier decision on the first
priority condition and also denied Edison International's request for a rehearing of the CPUC's determination
that it had jurisdiction over Edison International in this proceeding.  On August 21, 2002, Edison International
and SCE jointly filed a petition requesting a review of the CPUC's decisions with regard to first priority
considerations, and Edison International filed a petition for a review of the CPUC decision asserting
jurisdiction over holding companies.  Edison International cannot predict with certainty what effects this
investigation or any subsequent actions by the CPUC may have on Edison International or any of its subsidiaries.


Page 66



OTHER DEVELOPMENTS

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest in Paiton Energy, which owns the Paiton project, a 1,230-MW
coal-fired power plant in Indonesia.  Under the terms of a long-term power purchase agreement between Paiton
Energy and the state-owned electric utility company, the state-owned electric utility company is required to pay
for capacity and fixed operating costs once each unit and the plant achieve commercial operation.

The state-owned electric utility company and Paiton Energy signed a binding term sheet on December 14, 2001, that
set the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a
monthly restructure settlement payment covering amounts owed by the state-owned electric utility company and the
settlement of other claims.  In addition, the binding term sheet extends the term of the power purchase agreement
from 2029 to 2040.  On June 28, 2002, Paiton Energy and the state-owned electric utility company concluded
negotiations on an amendment to the power purchase agreement that includes the agreed commercial terms in the
binding term sheet.  The binding term sheet serves as the basis under which the state-owned electric utility
company is paying Paiton Energy during 2002, while the parties complete certain actions, including approval by
Paiton Energy's lenders of the amendment to the power purchase agreement.  Such actions are required to be
completed by December 31, 2002.  Previously, the state-owned electric utility company and Paiton Energy entered
into agreements covering 2001.  The state-owned electric utility company has made all payments to Paiton Energy
as required under these agreements for 2001, which are superseded by the binding term sheet.  Paiton Energy
continues to generate electricity to meet the power demand in the region.  The state-owned electric utility
company has paid invoices for the months of January through August 2002, as well as the restructure settlement
payments due for the months of January through September 2002, as required under the binding term sheet and the
power purchase agreement.  Paiton Energy believes that the state-owned electric utility company will continue to
make payments for electricity under the binding term sheet while the parties work to complete the conditions
precedent to the effectiveness of the amendment to the power purchase agreement.  Under the binding term sheet,
past due accounts receivable under the original power purchase agreement are to be compensated through a monthly
restructuring settlement payment of $4 million for 30 years.  If the power purchase agreement amendment does not
become effective within 180 days of its signing, the parties would be entitled to revert to the terms and
conditions of the original power purchase agreement in order to pursue arbitration in an international forum.

EME's investment in the Paiton project increased to $516 million at September 30, 2002, from $492 million at
December 31, 2001.  The increase in the investment resulted from EME's subsidiary recording its proportionate
share of net income from Paiton Energy, as well as its proportionate share of other comprehensive income.  EME's
investment in the Paiton project will increase or decrease from earnings or losses from Paiton Energy and
decrease by cash distributions.  Assuming the Paiton project remains profitable, EME expects the investment
account to increase substantially during the next several years as earnings are expected to exceed cash
distributions.

As mentioned above, Paiton Energy and the state-owned electric utility company have completed negotiations on an
amendment to the power purchase agreement.  While the binding term sheet has been approved by the project
lenders, Paiton Energy has not yet obtained the approval of the amendment to the power purchase agreement by the
project lenders.  Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior
debt, which takes into account the revised payment terms contained in the amendment to the power purchase
agreement.  Paiton Energy, its government agency lenders and the commercial bank lenders have agreed to terms and
conditions for debt restructuring.  In addition, Paiton Energy must seek approval of the debt restructuring from
its bondholders.  Paiton Energy believes that the terms of the debt restructuring will receive the necessary
approvals from the bondholders.  Therefore, EME believes that it will ultimately recover its investment in the
project.

PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, has reinstated the pending
arbitration to resolve disputes under the fuel supply agreement between BHP and Paiton Energy.  The


Page 67


arbitration had been stayed since 1999 to allow the parties to engage in settlement discussions to restructure
the coal supply chain for the Paiton project.  These discussion did not result in a settlement of all potential
claims with respect to the restructuring of the coal supply chain, and BHP recently requested that the
arbitration tribunal permit BHP to amend or supplement its statement of claims to assert additional claims
against Paiton Energy for breach and termination of the fuel supply agreement.  BHP's total claim, to date, is
$250 million.

Paiton Energy has entered into settlement negotiations with BHP.  A settlement offer has been made, and BHP has
indicated that it may be willing to accept that offer, subject to execution of acceptable documentation and
timing of payment.  Such settlement is subject to Paiton Energy obtaining approval of its lenders.  EME believes
that the outcome of this arbitration will not have a material adverse effect on its consolidated financial
position or results of operations.

Environmental Protection

Edison International's projected environmental capital expenditures are $2 billion for the 2002-2006 period,
mainly for undergrounding certain transmission and distribution lines at SCE and upgrading environmental controls
at EME.  This amount has been increased from the amount projected at December 31, 2001, to reflect the results
from SCE's annual environmental cost study for 2001 completed in April 2002.

Edison International's projected capital expenditure have been reduced by $315 million for the period 2003-2005
as a result of the suspension of work related to two selective catalytic reduction systems (commonly referred to
as SCRs) for the Powerton Stations.  As a result of the decision to suspend work on this project, an impairment
charge of $25 million was recorded during the third quarter ended September 30, 2002, due to the write-off of
capitalized costs associated with these environmental improvements.  This decision to reduce capital expenditures
was made in light of current market conditions.  See Market Risk Exposures.

Electric and Magnetic Fields
----------------------------

Electric and magnetic fields (EMFs) naturally result from the generation, transmission, distribution and use of
electricity.  Since the 1970s, concerns have been raised about the potential health effects of EMFs.  After 30
years of research, a health hazard has not been established to exist.  Many of the questions about specific
diseases have been successfully resolved due to an aggressive international research program.  Potentially
important public health questions remain about whether there is a link between EMF exposures in homes or work and
some diseases, including childhood leukemia and a variety of other adult diseases (e.g., adult cancers and
miscarriages), and because of these questions, some health authorities have identified magnetic field exposures
as a possible human carcinogen.

In October 2002, the California Department of Health Services (CDHS) released its report evaluating the possible
risks from electric and magnetic fields (CDHS Report) to the CPUC and the public.  The CDHS Report's conclusions
contrast with other recent reports by authoritative health agencies in that the CDHS has assigned a substantially
higher probability to the possibility that there is a causal connection between EMF exposures and a number of
diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and
miscarriages.

This report concludes a program initiated by the CPUC's 1993 Interim EMF Decision.  Under the policies advanced
by that decision, utilities have already committed to funding research, providing education materials to
employees and customers, and taking proactive steps to lower magnetic fields from new facilities.

It is not yet clear what actions the CPUC will take to respond to the CDHS Report and to the recent EMF reports
by other health authorities such as the National Institute of Environmental Health Sciences, the World Health
Organization's International Agency for Research on Cancer, and the United Kingdom's


Page 68


National Radiation Protection Board.  Possible outcomes include, but are not limited to, continuation of current
policies and imposition of more stringent policies to implement greater reductions in EMF exposures.  The
different costs of these outcomes is unknown at this time.

Navajo Nation Litigation

Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to the Mohave Generating
Station.  In June 1999, the Navajo Nation filed a complaint in federal district court against Peabody and certain
of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE.  The complaint
asserts claims against the defendants for, among other things, violations of the federal RICO statute,
interference with fiduciary duties and contractual relations, fraudulent misrepresentation by nondisclosure, and
various contract-related claims.  The complaint claims that the defendants' actions prevented the Navajo Nation
from obtaining the full value in royalty rates for the coal.  The complaint seeks damages of not less than $600
million, trebling of that amount, and punitive damages of not less than $1 billion, as well as a declaration that
Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated.

In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation
had breached a settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.

The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of
Interior, alleging that the Government had breached its fiduciary duty concerning contract negotiations including
the Navajo Nation and the defendants.  In February 2000, the Court of Claims issued a decision in the
Government's favor, finding that while there had been a breach, there was no available redress from the
Government.  Following appeal of that decision by the Navajo Nation, an appellate court ruled that the Court of
Claims did have jurisdiction to award damages and remanded the case to the Court of Claims for that purpose.  On
June 3, 2002, the Government's request for review of the case by the United States Supreme Court was granted.
Briefing on this matter has been completed and argument is scheduled for December 2002.

SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint of the Navajo Nation's suit against the Government, or the impact of the complaint on the
operation of Mohave beyond 2005.

Employee Compensation and Benefit Plans

For detailed descriptions of Edison International's  pension and long-term incentive plans, see Note 9 - Employee
Compensation and Benefit Plans, included in the notes to financial statements of Edison International's 2001
annual report to shareholders.  As indicated in Note 9, Edison International measures compensation expense
related to stock-based compensation by the intrinsic value method.  If Edison International were to adopt the
fair-value method of accounting and charge the cost of the stock options to expense, effective with stock options
granted in 2002, earnings for the nine months ended September 30, 2002, would have been reduced by approximately
$1 million and earnings for fiscal year 2002 would be reduced by approximately $2 million, based on a
Black-Scholes option-pricing model.

Under accounting standards for pension costs, if the accumulated benefit obligation exceeds the market value of
plan assets at the measurement date, the difference may result in a reduction to shareholders' equity.  Edison
International's next measurement date is December 31, 2002.  As of September 30, 2002, the estimated accumulated
benefit obligation, measured using prevailing interest rates, compared to the estimated market value of the
pension plan assets, would not have resulted in a reduction to shareholders' equity.

San Onofre Inspection

SCE's San Onofre Unit 2 returned to service on July 2, 2002, after a 43-day outage for scheduled refueling and
maintenance.  During this outage, a detailed inspection of the reactor vessel head nozzle


Page 69


penetrations was conducted.  The subject of reactor vessel head nozzle penetrations has received industry
attention recently due to the leakage from such nozzles at the Davis Besse nuclear plant in Ohio.  The inspection
conducted at San Onofre Unit 2 found no indications of leakage or degradation in the reactor vessel head nozzle
penetrations.  San Onofre Unit 3's nozzle penetrations will be inspected as part of its scheduled refueling and
maintenance outage in the first quarter of 2003.

Federal Income Taxes

On August 7, 2002, Edison International received a notice from the IRS asserting deficiencies in federal
corporate income taxes for Edison International's 1994 to 1996 tax years.  The vast majority of the tax
deficiencies are timing differences and therefore, amounts ultimately paid, if any, would benefit Edison
International as future tax deductions.  Edison International will challenge the deficiencies asserted by the
IRS.  Edison International believes that it has meritorious legal defenses to those deficiencies and believes
that the ultimate outcome of this matter will not result in a material impact on Edison International's
consolidated results of operations or financial position.

NEW ACCOUNTING STANDARDS

On January 1, 2001, Edison International adopted a new accounting standard for derivative financial instruments
and hedging activities.  Effective April 1, 2002, Edison International also adopted two authoritative accounting
interpretations to this standard, which precludes fuel contracts with variable amounts from qualifying under the
normal purchases and sales exception and precludes EME's forward electricity contracts from qualifying for the
normal sales exception as EME has net settlement provisions with its counterparties.  However, EME's contracts
qualify as cash flow hedges.  Adoption of these interpretations did not have a significant impact on Edison
International's financial statements.

In October 2002, an accounting interpretation related to accounting for contracts involved in energy trading and
risk management activities was rescinded.  The rescission means that energy trading and risk management
activities will no longer be marked-to-market as trading activities, but will instead follow accounting standards
for derivatives, where each energy contract must be assessed to determine whether or not it meets the definition
of a derivative.  If an energy contract meets the definition of a derivative, then it would be recorded at fair
value (i.e. marked-to-market), subject to permitted exceptions.  If an energy contract does not meet the
definition of a derivative, then it would be recorded on an accrual basis.  EME is conducting a review of its
existing contracts to determine the impact of this change in accounting for contracts outstanding at October 25,
2002.

On January 1, 2002, Edison International adopted a new accounting standard for Goodwill and Other Intangibles.
The new accounting standard required a benchmark assessment for goodwill by June 30, 2002.  Edison International
completed its benchmark assessment and determined that the only goodwill impairment is related to EME's September
2000 acquisition of Citizens Power.  Total goodwill related to Citizens Power was $25 million as of December 31,
2001.  In accordance with the new accounting standard, during third quarter 2002 an additional test was performed
to determine the amount of the impairment.  The result of this test was a $23 million ($14 million after tax)
goodwill impairment associated with the Citizens Power acquisition.  Adoption of this standard was not material
to Edison International; therefore, the impact of adoption was recorded in the other nonoperating deductions line
item of the September 30, 2002, consolidated statements of income (loss), rather than a cumulative effect of a
change in accounting principle, retroactive to January 1, 2002.

A new accounting standard, Accounting for Asset Retirement Obligations, requires entities to record the fair
value of a liability for a legal asset retirement obligation in the period in which it is incurred.  When the
liability is initially recorded, the entity capitalizes the 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 Edison International on January 1, 2003.  Edison International is studying the effects of the new
standard and has not yet determined the potential impact on its financial statements.


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FORWARD-LOOKING INFORMATION AND RISK FACTORS

In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates,
believes, predict, and other similar expressions are intended to identify forward-looking information that
involves risks and uncertainties.  Actual results or outcomes could differ materially from those anticipated.
Risks, uncertainties and other important factors that could cause results to differ, or that otherwise could
impact Edison International and its subsidiaries, include among other things:

o        the outcome of the pending appeals of the stipulated judgment approving SCE's settlement agreement with
         the CPUC, and the effects of other legal actions, if any, attempting to undermine the provisions of the
         settlement agreement or otherwise adversely affecting SCE;

o        changes in prices and availability of wholesale electricity, natural gas, fuel costs and other changes
         in operating costs, which could affect the timing of SCE's past procurement cost recovery and/or cause
         EME's revenue and earnings to be adversely affected;

o        the operation of some of EME's power plants without long-term power purchase agreements, and other
         plants with agreements with a single customer, which may adversely affect EME's ability to sell the
         plants' output at profitable terms;

o        changing conditions in wholesale power markets, such as general credit constraints and thin trading
         volumes, that could make it difficult for EME or SCE to sell power or enter into hedging agreements;

o        the actions of securities rating agencies, including the determination of whether or when to make
         changes in SCE's credit ratings, the ability of Edison International, SCE, EME and Edison Capital to
         regain investment-grade ratings, and the impact of current or lowered ratings and other financial market
         conditions on the ability of the respective companies to obtain needed financing on reasonable terms;

o        the possibility that existing tax allocation agreements may not operate as contemplated, for example, if
         the consolidated group does not have sufficient taxable income to use the tax benefits of each group
         member, or if any member ceases to be a part of the consolidated group;

o        actions by state and federal regulatory bodies setting rates, adopting or modifying cost recovery,
         holding company rules, accounting and rate-setting mechanisms, as well as legislative or judicial
         actions affecting the same matters (see Generation Procurement Proceeding discussion in SCE's Regulatory
         Matters section);

o        the effects of increased competition in energy-related businesses, including new market entrants and the
         effects of new technologies that may be developed in the future;

o        threatened attempts by municipalities within SCE's service territory to form public power entities
         and/or acquire SCE's facilities for customers;

o        political and business risks of doing business in foreign countries, including uncertainties associated
         with currency exchange rates, currency repatriation, expropriation, political instability, privatization
         and other issues;

o        power plant construction and operation risks, including construction delays, equipment failures, and
         labor issues;

o        new or increased environmental liabilities; and

o        weather conditions, natural disasters, and other unforeseen events.


Page 71






Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 3 is included in Item 2, Management's Discussion and Analysis of Results of
Operations and Financial Condition, under Market Risk Exposures, and is incorporated herein by reference.




Item 4.    Controls and Procedures

Under the Sarbanes-Oxley Act of 2002 and implementing rules and regulations adopted by the Securities and
Exchange Commission (SEC), Edison International must maintain disclosure controls and procedures.  The term
"disclosure controls and procedures" is defined in the SEC's regulations to mean, as applied to Edison
International, controls and other procedures that are designed to ensure that information required to be
disclosed by Edison International in reports filed with the SEC is recorded, processed, summarized, and reported,
within the time frames specified in the SEC's rules and forms.  Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information required to be disclosed by
Edison International in its SEC reports is accumulated and communicated to Edison International's management,
including its Chief Executive Officer and its Chief Financial Officer, as appropriate to allow timely decisions
regarding disclosure.  The SEC's regulations also require Edison International to carry out evaluations, under
the supervision and with the participation of Edison International's management, including its Chief Executive
Officer and its Chief Financial Officer, of the effectiveness of the design and operation of Edison
International's disclosure controls and procedures.  These evaluations must be carried out within the 90-day
period prior to the filing date of certain reports, including this Quarterly Report on Form 10-Q.

The Chief Executive Officer and the Chief Financial Officer of Edison International have evaluated the
effectiveness of the design and operation of Edison International's disclosure controls and procedures as of
November 7, 2002.  They have concluded that those disclosure controls and procedures, as of the evaluation date,
were effective in ensuring that information required to be disclosed by Edison International in its reports filed
with the SEC was (1) accumulated and communicated to Edison International's management, as appropriate to allow
timely decisions regarding disclosure, and (2) recorded, processed, summarized, and reported within the time
frames specified in the SEC's rules and forms.

The Chief Executive Officer and the Chief Financial Officer of Edison International also have concluded that
there were no significant changes in Edison International's internal controls or in other factors that could
significantly affect those controls subsequent to the date of their evaluation, including any corrective actions
with regard to significant deficiencies and material weaknesses.




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PART II - OTHER INFORMATION



Item 1.    Legal Proceedings

Edison International

Edison Mission Energy

                                                Sunrise Proceedings

As previously reported in Part II, Item 1 of Edison International's Quarterly Report on Form 10-Q for the
quarterly period ending March 31, 2002 (First Quarter 10-Q) and for the quarterly period ending June 30, 2002
(Second Quarter 10-Q), the CPUC and the California Electricity Oversight Board (CEOB) filed complaints with the
FERC against all sellers of long-term contracts to the CDWR, including Sunrise Power Company (Sunrise).  Sunrise,
in which EME owns a 50% interest, sells all its output to the CDWR under a power purchase agreement entered into
on June 25, 2001.  The CPUC complaint alleges that the contracts are "unjust and unreasonable" on price and other
terms, and requests that the contracts be abrogated.  The CEOB complaint makes a similar allegation and requests
that the contracts be deemed voidable at the request of the CDWR.

After hearings and intermediate rulings, on July 23, 2002, the FERC dismissed with prejudice the CPUC and CEOB
complaints against Sunrise.  The CPUC and CEOB have a right of appeal to the federal courts of appeal within
60 days of the date of the order.  Notwithstanding the fact that the July 23 order was, in part, a denial of
rehearing sought previously by the CPUC and CEOB, such complainants then filed a request for rehearing of the
July 23 order.  In a notice issued on September 20, 2002, FERC stated that it did not intend to act on such
request.  Complainants may try to appeal within 60 days after FERC's notice of September 20, 2002.

On May 15, 2002, Sunrise was served with a complaint filed in the Superior Court of the State of California, City
and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a
representative taxpayer suit" against sellers of long-term power to the CDWR, including Sunrise.  The lawsuit
alleges that the defendants, including Sunrise, engaged in unfair and fraudulent business practices by knowingly
taking advantage of a manipulated power market to obtain unfair contract terms.  The lawsuit seeks to enjoin
enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the
defendants of excessive monies obtained by the defendants.  Plaintiffs in several other lawsuits are seeking to
have the Millar lawsuit consolidated with other class action suits pending in the San Francisco area.  The
defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District
Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of
the jurisdictional issue.  Various plaintiffs have filed pleadings opposing the removal and requesting that the
matters be remanded to state court.  The motions are still pending.

                                       PMNC Litigation (Brooklyn Navy Yard)

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, 2001 (2001 Form 10-K), and in Part II, Item 1 of Edison International's Second Quarter 10-Q,
in February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County,
entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy New
York, Inc. and B-41 Associates, L.P., in which Plaintiffs asserted general monetary claims under the construction
turnkey agreement for the project in the amount of $136.8 million.  Brooklyn Navy Yard has also filed an action
entitled Brooklyn Navy Yard Cogeneration Partners, L.P., v. PMNC, Parsons Main of New York, Inc., Nab
Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the
State of New York, Kings County, asserting general monetary claims in excess of $13 million under the
construction turnkey agreement.


Page 73


On February 14, 2002, PMNC moved to amend the complaint in the New York action to add EME as a defendant and to
seek a $43 million attachment against EME.  This motion was heard on May 10, 2002, and the court issued an order
denying the motion on June 21, 2002.  Trial was originally scheduled for October 21, 2002, and has now been
rescheduled for January 2, 2003.  The parties filed motions for summary judgment in October 2002, but no hearings
have been scheduled.  EME agreed to indemnify Brooklyn Navy Yard and EME's partner in the venture from all claims
and costs arising from or in connection with this litigation.

                                                 Paiton Labor Suit

As previously reported in Part II, Item 1 of Edison International's Second Quarter 10-Q, EME owns a 40% interest
in Paiton Energy, which constructed the Paiton project in East Java, Indonesia.  The Paiton project has achieved
commercial operation.  In 1994, Paiton Energy entered into a power purchase agreement with Indonesia's
state-owned electricity company, P.T. Perusahaan Listrik Negara ("PT PLN"), pursuant to which PT PLN is obligated
to purchase the capacity and energy of the Paiton project.  In April 2001, Paiton Energy was sued in the Central
Jakarta District Court by the PLN Labor Union.  PT PLN, the Indonesian Minister of Mines and Energy and the
former President Director of PT PLN are also named as defendants in the suit.  The union sought to set aside the
power purchase agreement between Paiton Energy and PT PLN and the interim agreement then in effect between Paiton
Energy and its lenders, as well as damages and other relief.  On April 16, 2002, the Central Jakarta District
Court dismissed the lawsuit against Paiton Energy and the other defendants on the basis that the PLN Labor Union
was not authorized under the law to bring such an action.  On April 23, 2002, the PLN Labor Union filed a notice
that it would appeal this decision.  There has been no action on such appeal because the trial court has yet to
relinquish jurisdiction of the matter to the appeals court.  Paiton Energy intends to contest the appeal when
same is formally filed.

                                       BHP Fuel Supply Agreement Arbitration

As previously reported in Part II, Item 1 of Edison International's Second Quarter 10-Q, in early September 2002,
PT Batu Hitam Perkasa (BHP), one of EME's partners in Paiton Energy, reinstated a pending arbitration to resolve
disputes under the fuel supply agreement between BHP and Paiton Energy.  Paiton Energy filed its original
pleading on September 13, 2002.  BHP's filing was made on October 14, 2002.  The arbitration had been stayed
since 1999 to allow the parties to engage in settlement discussions to restructure the coal supply chain for the
Paiton project.  These discussions did not result in a settlement of all potential claims with respect to the
restructuring of the coal supply chain, and BHP recently requested that the arbitration tribunal permit BHP to
amend or supplement its statement of claims to assert additional claims against Paiton Energy for breach, and
termination, of the fuel supply agreement.  BHP's total claim to date is $250 million.

Paiton Energy has entered into settlement negotiations with BHP.  A settlement offer has been made and BHP has
indicated that it may be willing to accept that offer, subject to the execution of acceptable documentation and
the timing of payment.  Such settlement is subject to Paiton Energy obtaining approval of its lenders.

                                       EcoElectrica Environmental Proceeding

EME owns an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a
liquefied natural gas import terminal and cogeneration project at Penuelas, Puerto Rico.  In 2000, the U.S.
Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging
violations of the Federal Clean Air Act primarily related to start-up activities.  On August 15, 2002, the U.S.
Department of Justice notified EcoElectrica that it was preparing to bring a federal court action for violations
of the Clean Air Act and regulations promulgated thereunder, and requested a meeting with EcoElectrica to discuss
and possibly settle the matter.  EcoElectrica has informed the Department of Justice of its willingness to
participate in such a meeting.  EME expects that the initial meeting with the Department of Justice will take
place in December 2002.


Page 74



Southern California Edison Company

                                             Navajo Nation Litigation

As previously reported in Part I, Item 3 of Edison International's 2001 Form 10-K, and in Part II, Item 1 of
Edison International's Second Quarter 10-Q, on June 18, 1999, SCE was served with a complaint filed by the Navajo
Nation in the United States District Court for the District of Columbia (D.C. District Court) against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project Agricultural Improvement and Power
District, and SCE.  The complaint asserts claims against the defendants for, among other things, violations of
the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims.

The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of
Interior, alleging that the Government had breached its fiduciary duty concerning contract negotiations including
the Navajo Nation and the defendants.  On February 4, 2000, the Court of Claims issued a decision in the
Government's favor, finding that while there had been a breach, there was no available redress from the
Government.  Following an appeal of that decision by the Navajo Nation, an appellate court ruled that the Court of
Claims did have jurisdiction to award damages and remanded the case for that purpose.  The Government filed for a
writ of certiorari to the United States Supreme Court which was granted on June 3, 2002.  Briefing has been
completed and argument is scheduled for December 2002.

                                         Qualifying Facilities Litigation

As previously reported in Part I, Item 3 of Edison International's 2001 Form 10-K, and in Part II, Item 1 of
Edison International's First Quarter 10-Q and Second Quarter 10-Q, SCE has been involved in a number of legal
actions brought by various QFs, alleging SCE's failure to timely pay for power deliveries made from November 1,
2000, through March 26, 2001.  The QF plaintiffs have included gas-fired cogenerators and owners of solar, wind,
geothermal and biomass projects, with the lawsuits, in aggregate, seeking 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 have sought an order allowing the suppliers to stop providing power to SCE so that they may sell to
other purchasers.  Plaintiffs in most of these cases have entered into settlement agreements providing 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.  On March 1,
2002, and with several exceptions related to unique disputes or other unique circumstances, including the status
of regulatory approval, SCE paid the amounts due under the settlement agreements with these QFs, which triggered
the releases and other provisions effectuating the settlements.

As a result of SCE's above-mentioned payments, and with certain exceptions described below, the lawsuits have
either been dismissed or are in the process of being dismissed.

oCabazon Power Partners:  Although previously stayed, the matter has been reactivated.  Trial is now set
     for April 2003.

oSalton Sea Power Generation, LP, IMC Chemicals, Inc. and Luz Solar Partners, Ltd. III:  These lawsuits
     have been dismissed.

                                          CPUC Litigation and Settlement

As previously reported in Part I, Item 3 of Edison International's 2001 Form 10-K, in November 2000, SCE filed a
complaint in federal district court against the commissioners of the CPUC, alleging that their refusal to allow
SCE to recover its wholesale costs of purchasing power in its retail rates violated federal law.  See the
discussion under Regulatory Matters, "CPUC Litigation Settlement Agreement" for a description of SCE's lawsuit
against the CPUC, its settlement (referred to as the CPUC Settlement Agreement), and the

Page 75


legal proceedings associated with the CPUC Settlement Agreement, including the appeal thereof and the opinion and
order on the appeal issued on September 23, 2002, by the United States Court of Appeals for the Ninth Circuit.

                                South Coast Air Quality Management District Claims

In September 2002, SCE entered into a settlement with the South Coast Air Quality Management District in
satisfaction of claims that EPTC Dominguez Hills operated with a faulty gas flow meter which was attached to an
oil heater from 1999 through 2000.  The alleged faulty gas flow meter caused the reporting of the gas usage to be
significantly less than the actual usage of gas in the heater.  SCE paid a penalty of $127,750.00.  The meter has
since been repaired.

                      CPUC Investigation Regarding SCE's Electric Line Maintenance Practices

On August 25, 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and
underground electric line maintenance practices.  The OII was based on a report issued by the CPUC's Protection
and Safety Consumer Services Division ("CPSD"), which alleges a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000.  The OII also alleges that noncomplying
conditions were "involved" in 37 accidents resulting in death, serious injury, or property damage.  CPSD
identified 4,721 alleged violations of the general orders during the three-year period; and the OII put SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation.  The OII also
allowed the CPSD to allege additional violations of General Orders, as they are identified while the
investigation is pending.

In their opening brief on October 21, 2002, CPSD recommended a penalty of $97,080,000.  SCE will respond to the
CPSD penalty recommendation in its reply brief by November 18, 2002.  A decision is expected by year-end 2002 or
early 2003.  See the discussion under Regulatory Matters, "Electric Line Maintenance Practices Proceeding" for
additional information.



Page 76





Item 6.  Exhibits and Reports on Form 8-K



(a)        Exhibits

           3.1      Restated Articles of Incorporation of Edison International dated May 9, 1996
                    (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 January 1,
                    2002 (File No. 1-9936, Form 10-K for year ended December 31, 2001)*

           10.1     Separation Agreement with William J. Heller (File No. 000-24890, filed as Exhibit 10.104 to
                    the Edison Mission Energy Form 10-Q for the quarter ended September 30, 2002)*

           10.2     Consulting Agreement with William J. Heller

           10.3     Amended and Restated Agreement for the Allocation of Income Tax Liabilities and Benefits
                    among Edison International, Southern California Edison Company and The Mission Group

           10.3.1   Amended and Restated Tax Allocation Agreement among The Mission Group and its first-tier
                    subsidiaries

           10.3.2   Amended and Restated Tax Allocation Agreement between Edison Capital and Edison Funding
                    Company (formerly Mission First Financial and Mission Funding Company)

           10.3.3   Tax Allocation Agreement between Mission Energy Holding Company and Edison Mission Energy

           10.3.4   Administrative Agreement re Tax Allocation Payments among Edison International, Southern
                    California Edison Company, The Mission Group, Edison Capital, Mission Energy Holding Company,
                    Edison Mission Energy, Edison O&M Services, Edison Enterprises, and Mission Land Company

           11.      Computation of Primary and Fully Diluted Earnings per Share

           99.1     Homer City Facilities Funds Flow From Operations for the twelve months ended September 30,
                    2002 (File No.  000-24890, filed as Exhibit 99.1 to the Edison Mission Energy Form 10-Q for
                    the quarter ended September 30, 2002)*

           99.2     Illinois Plants Funds Flow From Operations for the twelve months ended September 30, 2002
                    (File No. 000-24890, filed as Exhibit 99.2 to the Edison Mission Energy Form 10-Q for the
                    quarter ended September 30, 2002)*

           99.3     Statement Pursuant to 18 U.S.C. 1350




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


Page 77




(b)        Reports on Form 8-K:

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

              July 1, 2002                      July 2, 2002                        5
              August 14, 2002                   August 14, 2002                     7
              September 23, 2002                September 24, 2002               5 and 7






Page 78






                                                    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       /S/ THOMAS M. NOONAN
                                                              ---------------------------------
                                                              THOMAS M. NOONAN
                                                              Vice President and Controller


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


November 14, 2002










                                                       CERTIFICATION


I, JOHN E. BRYSON, certify that:


1.   I have reviewed this quarterly report on Form 10-Q of Edison International;

2.   Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly report;

3.   Based on my knowledge, the financial statements, and other financial information included in this quarterly report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this quarterly report;

4.   The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)   designed such disclosure controls and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b)   evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the "Evaluation Date"); and

c)   presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;

5.   The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent
function):

a)   all significant deficiencies in the design or operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant's internal controls; and

6.   The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and
material weaknesses.


Date:  November 13, 2002


                                                    /S/ JOHN E. BRYSON
                                           -----------------------------------------
                                                      JOHN E. BRYSON
                                           Chairman of the Board, President and
                                                  Chief Executive Officer












                                                       CERTIFICATION


I, THEODORE F. CRAVER, JR., certify that:


1.   I have reviewed this quarterly report on Form 10-Q of Edison International;

2.   Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly report;

3.   Based on my knowledge, the financial statements, and other financial information included in this quarterly report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this quarterly report;

4.   The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)   designed such disclosure controls and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b)   evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the "Evaluation Date"); and

c)   presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;

5.   The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent
function):

a)   all significant deficiencies in the design or operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant's internal controls; and

6.   The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and
material weaknesses.

Date:  November 13, 2002

                                            /S/ THEODORE F. CRAVER, JR.
                                 --------------------------------------------------
                                              THEODORE F. CRAVER, JR.
                                 Executive Vice President, Chief Financial Officer
                                                   and Treasurer



CONSULTING AGREEMENT



         This Consulting Agreement (Agreement) is entered into by Edison International, a California corporation
(the Company) and William J. Heller (Consultant) effective August 1, 2002 (Effective Date).

         WHEREAS, the Company desires to engage the services of Consultant and Consultant agrees to act as an
independent contractor on behalf of the Company;

         NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter contained, the parties
agree as follows:

         1.       Consultant agrees that for a period of one year commencing on the Effective Date, he will be
available to serve as an independent contractor by rendering advice and assistance to the Company in connection
with its business affairs with which he became familiar while he was employed by the Company or any of its
affiliates, under the direction of the Chief Executive Officer the Company, or such other Company officers the
CEO may designate.  The scope of such work may be spelled out in one or more purchase orders or engagement
letters.  The Company will give Consultant reasonable prior notice of its need for his services and will make
reasonable scheduling accommodations to recognize Consultant's other business and personal activities and plans.

         2.       In consideration of the services to be performed during the term of this Agreement, the Company
will pay Consultant a retainer of $100,000 within two weeks following the Effective Date.  Consultant will make
himself reasonably available for consulting services for up to 40 hours per month for the first six months of
this Agreement, and for up to 20 hours per month for the second six months of this Agreement.  Consultant will be
paid at a rate of $200 per hour for his consulting services.  The Company is not obligated to use a minimum
number of hours of Consultant's services.


Page 1




         3.       The Company agrees to reimburse Consultant for any expenses reasonably incurred by him in
connection with the performance of his consulting services pursuant to this Agreement.  Such expenses will
include lodging, meals, travel, telephone, mileage and parking expense.  Consultant will submit written invoices
accounting for his time and expenses on a monthly basis in accordance with the terms of any purchase order or
engagement letter to the Company's Controller.

         4.       Consultant is not and will not be deemed an employee of the Company, or any affiliate of the
Company, while performing consulting services pursuant to this Agreement.  This Agreement will not, in any way,
affect Consultant's rights to receive any and all Company benefits to which he may be entitled in accordance with
the provisions of any other agreement or plan in which he was or is a participant.  The Company will comply with
all applicable governmental reporting requirements with respect to compensation paid pursuant to this Agreement.
Consultant agrees that any federal, state, local and other applicable taxes which may become due and payable as a
result of the compensation paid pursuant to this Agreement are the sole responsibility of Consultant.

         5.       Consultant agrees that the services to be rendered by Consultant pursuant to this Agreement are
personal in nature and may not be assigned without prior written approval of the Chief Executive Officer or
General Counsel of the Company.

         6.       Consultant acknowledges that he is in possession of confidential trade secret and/or business
information not publicly available concerning the Company and Company affiliates.  Consultant specifically agrees
that he will not at any time, in any fashion, form, or manner use or divulge, disclose or communicate to any
person, firm, or corporation, in any manner whatsoever, any such confidential information concerning any matters
affecting or relating to the business of the Company or any Company affiliate.

         7.       Consultant agrees that during the term of this Agreement he will not, directly or indirectly,
   for his own benefit, for the benefit of any person or entity other than the Company, or any Company affiliate,
   or otherwise:

Page 2



         (a)      solicit, encourage or induce, or assist others to solicit, encourage or induce, any officer,
         director, executive or employee of the Company, or any Company affiliate, to leave his or her employment
         with the Company, or any Company affiliate for any reason;

         (b)      interfere  with any Company  business or  regulatory  relationship  existing as of the  Effective
         Date with any  customer,  supplier,  financier,  government  agency,  independent  contractor,  developer,
         promoter or others  having any  business  or  regulatory  relationship  with the  Company,  or any Company
         affiliate; or

         (c)      make or cause  to be made  any  public  statement  that is  disparaging  of the  Company,  or any
         Company  affiliate,  or their respective  businesses or that materially injures the business or reputation
         of the Company, or any Company affiliate, or their respective businesses.

         8.       Consultant further agrees that while this Agreement is in effect he will not, except with the
written consent of the General Counsel of the Company, (a) render advice or services of any kind to any of the
entities listed on Exhibit A, or their successors or affiliates, (b) render advice or services of any kind to any
person or entity in respect to (i) any proposed or actual transaction or business relationship in locations
outside Europe in which the Company or any of its affiliates is or would be a party, or (ii) any business
activity that would be directly competitive with a business activity of the Company or any of its affiliates in
locations outside Europe, (c) render advice or services to, or have any other business relationship with, any
person or entity in respect to (i) any aspect of the COWL (Off-Shore Project in North Wales), or (ii) any
activity that is competitive with any of the Company's trading or marketing activities related to its First Hydro
operations, or (d) render advice or services of any kind to any person or entity in respect to any litigation,
administrative proceeding or other contested matter in which Consultant knows that the Company or any of its
affiliates has an interest adverse to that of the person or entity to whom Consultant may be considering
providing advice or services.

         9.       If, during the term of this Agreement, Consultant engages in discussions with any entity or
person regarding Consultant providing services to such entity or


Page 3




person, or regarding engaging in any business enterprise with such entity or person, he may disclose the
fact that he has agreed to the provisions of Section 8 for a period of one year beginning on the Effective Date,
and he may also disclose the provisions of Section 8 to such entity or person.

         10.      WJH agrees that any violation of Section 7 or Section 8 shall constitute a material breach of
this Agreement and that EME shall be entitled to injunctive interim relief to halt and/or prohibit any actual or
threatened action by WJH in violation of Section 7 or Section 8.

         11.      If any provision of this Agreement or the application thereof is held invalid, the invalidity
will not affect other provisions or applications of this Agreement which can be given effect without the invalid
provisions or applications, and to this extent, the provisions of this Agreement are declared to be severable.

         12.      This Agreement is made and will be construed under the laws of the State of California.

         IN WITNESS THEREOF, the Company has caused this Agreement to be executed by its duly authorized officer
and Consultant has hereunto set his hand.





William J. Heller                                            Edison International



                   [W. J. Heller]                            By               [Bryant C. Danner]
-------------------------------------------------------        ------------------------------------
                                                                               Bryant C. Danner



                                                             Title    [Exec. VP and General Counsel
                                                                   --------------------------------

Dated  [July 18, 2002] at                                    Dated [August 5, 2002] at

[Irvine], California.                                        [Rosemead], California.


Page 4




                                                      Exhibit A

1.  Exelon Corporation
2.  National Grid Group plc
3.  California Public Utilities Commission
4.  Federal Energy Regulatory Commission

5.  Office of Gas and Electricity Markets (Great Britain)
6.  PG&E Corporation
7.  Sempra Energy



EDISON INTERNATIONAL


                                                    AMENDED AND RESTATED
                                              AGREEMENT FOR THE ALLOCATION OF
                                            INCOME TAX LIABILITIES AND BENEFITS



                  This  amendment  is  entered  into as of  September  10,  1996 for the  purpose of  amending  and
restating the Agreement for the Allocation of Income Tax  Liabilities  and Benefits dated July 1, 1988 and restated
May 1, 1995 (as so amended and  restated,  being  herein  referred  to as this  "Agreement"),  by and among  Edison
International,  a California corporation ("Parent"), and its wholly-owned subsidiaries,  Southern California Edison
Company  ("SCE")  and The  Mission  Group  ("Mission  Group"),  acting on their own  behalf  and on behalf of their
Subsidiaries  (SCE and Mission Group being herein referred to together as the  "Companies,"  and each separately as
a "Company").



RECITALS

A.       Parent and/or the Companies  have  previously  filed and intend to continue to file  consolidated  federal
         income tax returns and combined state franchise or income tax returns.

B.       In Decision  84-05-036 (OII 24) the California  Public Utilities  Commission  ("CPUC") found the "separate
         return  method"  to be "the more  reasonable  basis for  calculating  test-year  income tax  expense"  for
         utility ratemaking purposes.

C.       The Companies  previously  entered into an agreement  for the  allocation  of income tax  liabilities  and
         benefits,  which  agreement  was  replaced by this  Agreement  as a result of a  corporate  reorganization
         wherein Parent became the common parent of the Companies.

D.       The parties  desire that the income tax  liabilities  and benefits of the Companies  and their  respective
         Subsidiaries  as  reflected  in or  resulting  from the filing of  consolidated  or  combined  tax returns
         continue  to be  allocated  and  apportioned  using  the  "separate  return  method"  as set forth in this
         Agreement.

E.       The parties desire that the "separate  return method"  continue to be used to further their desire that no
         cross-subsidizations arise between the utility and nonutility activities of the Consolidated Group.


Page 1




AGREEMENT

                  NOW,  THEREFORE,  in  consideration  of the premises and of the mutual covenants herein contained
and for other good and  valuable  consideration,  the receipt of which is hereby  acknowledged,  the parties  agree
that this  Agreement  is amended in its  entirety  to read as  provided in the  heading  and  recitals  hereto,  as
provided in this paragraph, and as follows:

1.Definitions.  The following terms as used herein shall have the meanings set forth below:

         1.1      "Consolidated  Group" means the affiliated  group of  corporations  of which Parent is the common
                  parent  (and of which SCE was the common  parent  prior to July 1, 1988) and which duly elects to
                  file a Consolidated Return.

         1.2      "Consolidated  Return" means a federal  income tax return filed with respect to the  Consolidated
                  Group  pursuant to Section 1501 of the Internal  Revenue Code and/or a state  franchise or income
                  tax return or report  filed  with  respect  to the  Consolidated  Group  pursuant  to  applicable
                  sections of any state tax code.

         1.3      "Net Losses" has the meaning assigned to that term pursuant to Section 3 below.

         1.4      "Separate  Return"  means a  separate  federal  income  tax  return  that is  computed  with  the
                  modifications listed in Treasury Regulation
                  1.1552-1(a)(2)(ii)  or a state  franchise  or income tax return  that is  computed  with  similar
                  modifications corresponding to applicable state law.

         1.5      "Separate Tax Benefit" has the meaning assigned to that term pursuant to Section 3 below.

         1.6      "Separate Tax Liability" has the meaning assigned to that term pursuant to Section 2 below.

         1.7      "Subsidiary" and "Subsidiaries" mean, respectively,  a corporation or corporations,  the majority
                  of whose voting stock or other controlling  ownership interest is owned,  directly or indirectly,
                  by SCE or Mission  Group,  as the case may be, and which is  included  in a  Consolidated  Return
                  filed by the Consolidated Group.

2.Separate Tax  Liability. For each taxable period ending on or after December 31, 1986, with respect
         to which Parent files, or  reasonably  anticipates  that it will  file,  a  Consolidated  Return  with the
         Companies, Parent shall determine the amount


Page 2



         of federal  income tax and state  franchise or income tax that each of the Companies and each of their respective
         Subsidiaries  would have paid (if any) if each of the Companies and each of their respective  Subsidiaries
         had filed Separate  Returns for such taxable period (such amount being called herein,  with respect to any
         person,  a "Separate Tax  Liability").  Each of the Companies  shall pay to Parent the amount by which (a)
         the aggregate of the Separate Tax Liability of such Company,  if it has a Separate Tax Liability,  and the
         Separate Tax  Liability of each of its  Subsidiaries  which has a Separate Tax  Liability  exceeds (b) the
         aggregate  of the  Separate  Tax  Benefit of such  Company,  if it has a  Separate  Tax  Benefit,  and the
         Separate Tax Benefit of each of its  Subsidiaries  which has a Separate Tax  Benefit.  Such payment  shall
         be made in the manner provided in Section 4 below.

3.Separate  Tax  Benefits.  For each  taxable  period  ending on or after  December 31, 1986 with respect to
         which  Parent  files,  or  reasonably  anticipates  that it will  file,  a  Consolidated  Return  with the
         Companies,  Parent shall  determine  the amount of net  operating  losses,  net capital  losses or credits
         against  tax in excess of the  amounts  of such  losses or  credits  that may be  utilized  to reduce  the
         Separate Tax Liability (such amounts being called herein,  with respect to any person,  "Net Losses") with
         respect to each of the Companies and each of their  respective  Subsidiaries.  With respect to each of the
         Companies  which has Net Losses for any taxable  period and each  Subsidiary  which has Net Losses for any
         taxable period,  Parent shall calculate the increase in the tax liability of the Consolidated  Group which
         would  arise if the Net  Losses of each such  member of the  Consolidated  Group  were  excluded  from the
         Consolidated  Return for such taxable period (such amount being called  herein,  with respect to each such
         person,  a "Separate Tax  Benefit").  If, for any such taxable  period,  (a) the aggregate of the Separate
         Tax Benefit of a Company,  if it has a Separate Tax  Benefit,  and the Separate Tax Benefit of each of its
         Subsidiaries  which has a Separate Tax Benefit  exceeds (b) the  aggregate  of the Separate Tax  Liability
         of such  Company,  if it has a Separate  Tax  Liability,  and the  Separate  Tax  Liability of each of its
         Subsidiaries  which has a Separate  Tax  Liability,  Parent  shall pay to such  Company an amount equal to
         such  excess.  Such  payment  shall be made in the manner  provided  in Section 4 below.  If more than one
         member of the  Consolidated  Group  has a Net Loss and any  portion  of the  aggregate  Net  Losses of the
         Companies  and their  Subsidiaries  is not used to reduce  the income tax  liability  of the  Consolidated
         Group for the taxable  period,  the amount of the payments to be made to Mission Group shall be determined
         after the Net Losses of SCE and each of its  Subsidiaries  that is subject to  regulation by the CPUC have
         been fully utilized,  but before any  utilization of or credit for the Net Losses of any other  subsidiary
         of Parent other than SCE and its such regulated Subsidiaries and Mission Group and its Subsidiaries.

4.Payments.  The Companies  shall provide  Parent  monthly,  or upon demand as necessary,  with all relevant
         information  necessary for Parent to, and Parent shall,  calculate the periodic estimated tax installments
         on a Consolidated Return


Page 3



         basis.  Each Company's  share,  if any, of each such  installment,  or of the amounts payable to it with respect to
         the  Separate  Tax  Benefits,  if any,  of such  Company  and its  Subsidiaries,  shall be  calculated  in
         accordance  with  Sections  2 and 3,  above.  Such  calculations  shall  be made  by  Parent  in its  sole
         discretion  but shall be  consistent  with  elections  made by Parent under the Internal  Revenue Code and
         applicable state tax codes and this Agreement.

         Parent  shall  invoice  each  Company  for  its  share  of  federal  and  state  quarterly  estimated  tax
         installments  as soon as it is practically  possible prior to the date of any  installment  payment.  Each
         Company shall pay Parent such  quarterly tax liability or receive  payment for any amount due such Company
         on the date Parent remits any installment payment to the appropriate taxing authority.

5.Reconciliation  of Tax Liability.  Parent shall  reconcile the federal and state  quarterly  estimated tax
         installments  against the Separate Tax  Liabilities  and the  Separate Tax Benefits  attributable  to each
         Company  and its  Subsidiaries  resulting  from the  filing  of the  Consolidated  Returns.  Parent  shall
         invoice each Company and each Company shall pay to Parent any  additional  tax  liability  due, or receive
         payment  from  Parent  for any  overpayment,  based  upon such  reconciliation  within  90 days  after the
         Consolidated Returns are filed.

6.Adjustments to Tax Liability.  If any adjustments are made to the income,  gains, losses,  deductions,  or
         credits  pertaining  to the  Companies or their  respective  Subsidiaries,  as reported in a  Consolidated
         Return,  by reason of the filing of any amended return or claim for refund,  or arising out of an audit of
         such  Consolidated  Return by the Internal Revenue Service or applicable state agency,  then the aggregate
         Separate Tax Liabilities or aggregate  Separate Tax Benefits,  as the case may be, of each Company and its
         Subsidiaries  shall be  redetermined  to give effect to any such adjustment as if it had been made as part
         of the filed  Consolidated  Return.  If any  interest or penalty is to be paid or  interest  received as a
         result of a tax deficiency or refund,  such interest or penalty shall be allocated in accordance  with the
         item(s)  giving rise to such  interest or penalty.  Either  Parent or the Company  affected may contest or
         cause to be  contested  any  adjustments  to income,  gains,  losses,  deductions,  credits or interest or
         penalty  assessments  and the  reasonable  costs  incurred in contesting  such  adjustments or assessments
         shall be  allocated  upon such  basis as is  mutually  agreed to by Parent  and the  Company  affected  in
         advance of such  contest.  If, as a result of such  redetermination,  any  amounts due to Parent or either
         of the Companies  under this  Agreement,  as the case may be, shall exceed the amounts  previously paid to
         such party,  then payment of such excess shall be made by the  appropriate  party,  as the case may be, on
         the  earliest  date on which (i)  Parent  shall  pay,  or be deemed to have  paid,  any  additional  taxes
         resulting from any such  adjustment,  (ii) Parent shall receive,  or be deemed to have received,  a refund
         of taxes  resulting  from any such  adjustment or (iii) such  adjustment  shall become final;  any payment
         between  Parent and a Company  pursuant to (i) or (ii) above,  however,  shall not become  final until the
         adjustment


Page 4



         with respect to which the  redetermination  was made becomes  final.  For purposes of this Section 6, an adjustment
         shall become final at the time of the  expiration of the applicable  statute of  limitations  with respect
         to the taxable  period to which such  adjustment  relates,  or, if such  adjustment was made pursuant to a
         decision of a court, at the time such decision shall become final.

7.Carryovers  and  Carryback.  If, for any taxable  period  ending on or after  December 31, 1986, a Company
         and its Subsidiaries  have aggregate Net Losses which,  under the applicable tax codes may be carried over
         or carried  back to any taxable  period in which  Parent or SCE filed,  or Parent  reasonably  anticipates
         that it will file, a Consolidated  Return which includes such Company,  and such aggregate Net Losses give
         rise to a reduction  in the tax  liability  of the  Consolidated  Group that would not have arisen if such
         Company and its  Subsidiaries  were  excluded  from the  Consolidated  Group for any such taxable  period,
         Parent  shall pay to such  Company an amount  equal to the actual  reduction  in the tax  liability of the
         Consolidated  Group for the taxable  period to which such  aggregate  Net Losses may be carried,  which is
         attributable  to such  carryover or  carryback.  Payment of such amount shall be made by Parent (i) in the
         case of a  carryover,  on or before the later of (a) the  15th day of the third month after the end of the
         taxable period with respect to which the tax liability of the  Consolidated  Group was reduced and (b) the
         date on which such  reduction  in tax  liability is finally  determined,  which shall be not later than 90
         days  after  the  Consolidated  Return  for  such  taxable  period  is  filed,  and  (ii) in the case of a
         carryback,  when the Consolidated Group shall receive,  or be deemed to receive,  the refund  attributable
         to such  carryback.  If more than one member of the  Consolidated  Group has a carryover or carryback of a
         Net Loss to a taxable  period and any portion of the  carryovers  or  carrybacks is not used to reduce the
         tax liability of the  Consolidated  Group for that taxable  period,  the amount of the payments to be made
         to Mission Group  pursuant to this Section 7 shall be  determined  after the Net Losses of SCE and each of
         its  Subsidiaries  that is subject to  regulation  by the CPUC have been  fully  utilized,  but before any
         utilization  of or credit  for the Net  Losses of any other  subsidiary  of Parent  other than SCE and its
         such regulated Subsidiaries and Mission Group and its Subsidiaries.

8.Miscellaneous.

         8.1Consents,  Waiver,  etc.  Parent,  SCE and  Mission  Group each  agree to  execute  and file such
                  consents,  waivers and other  documents  as may be  necessary  to effect the  provisions  of this
                  Agreement.

         8.2Verification of  Computation.  Parent,  Mission Group and SCE shall each provide  promptly to the
                  other parties copies of the  computations  of all amounts payable under this Agreement and access
                  to all records, work papers, or other documents necessary to verify such computations.


Page 5



         8.3Tax  Allocation  Method  Elected  Under  Treasury  Regulations  or  Imposed by State  Statutes,
Regulations or Policies.  The respective  obligations of the parties  hereunder in respect of any
                  period for which Parent files a federal  Consolidated  Return  and/or state  Consolidated  Return
                  shall be  determined  in  accordance  with the  provisions  of this  Agreement  regardless of the
                  actual  method  for  allocation  of  federal  income  tax   liabilities   specified  in  Treasury
                  Regulations  Section  1.1552-1(a)  and Section  1.1502-33(d)(2)  elected,  or deemed to have been
                  elected,  by the  Consolidated  Group,  and/or  the  allocation  of  state  income/franchise  tax
                  liabilities imposed by state statutes, regulations or policies, respectively, for such period.

         8.4Successors  and  Beneficiaries.  This  Agreement  may not be assigned,  pledged,  transferred  or
                  hypothecated  by any party without the express  written  consent of the other parties;  provided,
                  that,  without obtaining such consent,  this Agreement may be assigned,  pledged,  transferred or
                  hypothecated by either party as security for its obligations to any third party.

         8.5Termination.  This  Agreement  shall  be  applicable  to all  taxable  periods  ended on or after
                  December  31,  1986 and prior to  termination  of this  Agreement  by  written  agreement  of the
                  parties.  Notwithstanding  termination of this  Agreement,  its provisions  will remain in effect
                  with  respect to any period of time during the taxable year in which the  termination  occurs for
                  which the  income  or loss of the  Companies  and  their  Subsidiaries  must be  included  in the
                  Consolidated  Return of Parent.  In  addition,  such  termination  shall not relieve any party of
                  any obligation arising hereunder with respect to taxable periods covered by this Agreement.

         8.6Effect  on Prior  Agreement.  This  Agreement  replaces  and  supersedes  the  Agreement  for the
                  Allocation  of Income Tax  Liabilities  and  Benefits  dated  November  1, 1987,  between SCE and
                  Mission  Group (the "Prior  Agreement")  in the following  manner,  effective  July 1, 1988:  (a)
                  Parent assumes all of SCE's  obligations to Mission Group under the Prior Agreement,  (b) Mission
                  Group  shall pay to Parent all amounts  which  Mission  Group was or would have been  required to
                  pay to SCE under the Prior  Agreement  and which remain  unpaid on, or arise  after,  the date of
                  this  Agreement,  and (c) SCE shall pay to Parent,  or Parent  shall pay to SCE,  as the case may
                  be, any amounts arising from  reconciliations  or adjustments under Sections 5 and 6 of the Prior
                  Agreement and this Agreement.

         8.7Governing  Law. This  Agreement  shall be governed by and  construed in accordance  with the laws
                  of the State of California.


Page 6



         8.8Additional  Companies.  Any other wholly-owned first tier Edison International  subsidiary may be
                  added to this  Agreement  as an  additional  Company at any time by  addendum  executed by Edison
                  International  and the  subsidiary.  The addendum must provide such  subsidiary  will be bound by
                  the terms of the  Agreement.  Edison  International  shall  provide a copy of the addendum to the
                  Companies.

                  IN WITNESS  WHEREOF,  the parties  have  executed  this  Agreement by their  respective  officers
thereunto duly authorized as of the date first above written.


         EDISON INTERNATIONAL



         By       /s/ Alan J. Fohrer
           ------------------------------------------------------------
                  Alan J. Fohrer
                  Executive Vice President, Treasurer and
                  Chief Financial Officer


         SOUTHERN CALIFORNIA EDISON COMPANY



         By       /s/ R. K. Bushey
           ------------------------------------------------------------
                  R. K. Bushey
                  Vice President and Controller


         THE MISSION GROUP



         By       /s/ Alan J. Fohrer
           ------------------------------------------------------------
                  Alan J. Fohrer
                  Office of the President

THE MISSION GROUP

                                   AMENDED AND RESTATED TAX ALLOCATION AGREEMENT


         This  amendment  is entered into as of September  10, 1996 for the purpose of amending and  restating  the
Tax  Allocation  Agreement  dated  November 1, 1987 and  restated  May 1, 1995 (as so amended and  restated,  being
referred to herein as this  "Agreement"),  by and between The Mission  Group,  a California  corporation  ("Mission
Group"),  and its  wholly-owned  subsidiaries,  Edison Capital,  Edison EV, Edison Mission  Energy,  Edison Source,
Edison Spectrum and Mission Land Company (the "First Tier Subsidiaries").

RECITALS

A.       Edison  International,  a California  corporation,  which is the corporate  parent of Mission  Group,  has
         entered into an Amended and Restated  Agreement for the Allocation of Income Tax  Liabilities and Benefits
         (the "Master  Agreement") dated as of September 10, 1996, with Southern  California Edison Company ("SCE")
         and Mission Group providing,  among other things, for an equitable  allocation among Edison  International
         ("Parent"),  SCE and Mission Group of tax benefits and tax liabilities  reflected in or resulting from the
         filing of consolidated or combined income or franchise tax returns.

B.       Pursuant to the Master  Agreement,  Mission Group makes payments to and receives payments from Parent from
         time to time  reflecting tax  liabilities  and benefits  realized by the corporate  group arising from net
         operating  income and losses,  net capital  gains and losses,  and credits  against tax,  attributable  to
         Mission  Group and the First  Tier  Subsidiaries  and their  respective  subsidiaries  (collectively,  the
         "Subsidiaries").

C.       The  parties  desire to provide  for the  continued  payment  by  Mission  Group to each of the First Tier
         Subsidiaries  or from each of the First Tier  Subsidiaries  to Mission  Group,  as the case may be, of the
         respective  Separate Tax Benefit or Separate  Tax  Liability of each of the  Subsidiaries,  calculated  in
         accordance  with the Master  Agreement.  Terms used and not defined herein have the meanings given them in
         the Master Agreement.

AGREEMENT

         NOW,  THEREFORE,  in  consideration  of the premises and of the mutual  covenants herein contained and for
other good and valuable consideration,  the receipt of which is hereby acknowledged,  the parties hereto agree that
this  Agreement is amended in its entirety to read as provided in the heading and recitals  hereto,  as provided in
this paragraph, and as follows:


Page 1



1.Tax  Liability  and  Benefit  Payments.  For  each  taxable  period  to  which  the  Master  Agreement  is
         applicable,  Mission Group shall utilize the calculation  made by Parent under the Master Agreement of the
         amount of the  Separate  Tax  Liability  or Separate  Tax Benefit (as such terms are defined in the Master
         Agreement) of each of the  Subsidiaries.  On each date that any payment  under the Master  Agreement is to
         be made or  received  by Mission  Group (or would have been made or received if an amount had been owed or
         receivable),  (a)  Edison  Capital  shall pay to Mission  Group an amount  equal to the  aggregate  of the
         Separate Tax  Liabilities of Edison Capital and of each  Subsidiary  which is owned directly or indirectly
         by Edison  Capital for such taxable  period  (without  deducting,  with  respect to any such  member,  the
         amount of any  Separate  Tax  Benefit  of any other  member)  and (b)  Mission  Group  shall pay to Edison
         Capital an amount  equal to the  aggregate  of the  Separate  Tax  Benefits of Edison  Capital and of each
         Subsidiary  which is owned directly or indirectly by Edison Capital  (without  deducting,  with respect to
         any such member, the amount of any Separate Tax Liability of any other member).

         On each date that any payment  under the Master  Agreement is to be made or received by Mission  Group (or
         would  have been made or  received  if an amount  had been  owed or  receivable),  each of the First  Tier
         Subsidiaries  (other  than  Edison  Capital)  shall  pay to  Mission  Group  the  amount  by which (a) the
         aggregate  of the  Separate  Tax  Liability  of such  First  Tier  Subsidiary,  if it has a  Separate  Tax
         Liability,  and the  Separate  Tax  Liabilities  of each of the  Subsidiaries  which is owned  directly or
         indirectly  by such  First Tier  Subsidiary  ("Lower  Tier  Subsidiaries")  and which has a  Separate  Tax
         Liability,  exceeds (b) the  aggregate of the Separate  Tax Benefit of such First Tier  Subsidiary,  if it
         has a Separate Tax Benefit,  and the  Separate Tax Benefits of each of its Lower Tier  Subsidiaries  which
         has a Separate  Tax  Benefit.  If, for any such  taxable  period,  (a) the  aggregate  of the Separate Tax
         Benefit of a First Tier  Subsidiary  (other than Edison  Capital),  if it has a Separate Tax Benefit,  and
         the  Separate  Tax  Benefits  of each of its Lower  Tier  Subsidiaries  which has a Separate  Tax  Benefit
         exceeds (b) the aggregate of the Separate Tax Liability of such First Tier  Subsidiary,  if has a Separate
         Tax  Liability,  and the  Separate  Tax  Liabilities  of each of its Lower Tier  Subsidiaries  which has a
         Separate Tax  Liability,  Mission  Group shall pay to such First Tier  Subsidiary  an amount equal to such
         excess.

         All  payments  either by  Mission  Group or by any First Tier  Subsidiary  shall be made  without  setoff,
         counterclaim or deduction of any kind  whatsoever,  and whether or not payment is due or has been received
         from  Parent  under the  Master  Agreement.  Mission  Group  shall  give  notice to each of the First Tier
         Subsidiaries  immediately  after receipt of each invoice  described in Section 4 of the Master  Agreement,
         which  notice  shall  state the date and amount of each  payment to be made by Mission  Group or the First
         Tier  Subsidiary,  as the case may be. Each of the First Tier  Subsidiaries  shall provide (or cause to be
         provided) to Parent on a monthly basis, or upon demand as necessary, all

Page 2


         relevant information necessary to calculate  federal and state tax liabilities and payments for itself and
         its Subsidiaries.

2.Reconciliation  of Tax  Liability.  Upon receipt of each  invoice  provided for in Section 5 of the Master
         Agreement,  relating to  reconciliation  of  quarterly  estimated  tax payments  against the  Consolidated
         Returns,  Mission Group shall  forthwith  determine and notify each of the First Tier  Subsidiaries of the
         effect,  if any,  of such  reconciliation  on the  payments  made to or  received  from  such  First  Tier
         Subsidiary.  Each First Tier  Subsidiary  shall pay to Mission Group any  additional tax liability due, or
         receive  payment  from Mission  Group for any  overpayment,  on the same date that Mission  Group makes or
         receives any payments under Section 5 of the Master Agreement.

3.Adjustments to Tax Liability.  If any adjustments  are made to the income,  gains,  losses,  deductions or
         credits  pertaining to the Subsidiaries,  as reported in a Consolidated  Return filed by Parent, by reason
         of the filing of an amended  return or claim for refund,  or arising out of an audit of such  Consolidated
         Return by the Internal  Revenue  Service or applicable  state  agency,  then the Separate Tax Liability or
         the Separate Tax Benefit of the  Subsidiaries  shall be redetermined to give effect to any such adjustment
         as if it had been made as part of the filed  Consolidated  Return.  If any  interest  or  penalty is to be
         paid or interest  received as a result of a tax  deficiency  or refund,  such interest or penalty shall be
         allocated in accordance  with the item(s)  giving rise to such  interest or penalty.  Mission Group agrees
         to exercise its contest rights under the Master  Agreement on behalf of any First Tier  Subsidiary and the
         reasonable  costs so incurred by Mission  Group shall be allocated  upon such basis as is mutually  agreed
         to by Mission Group and such First Tier  Subsidiary  in advance of such  contest.  If, as a result of such
         redetermination,  any  amounts  due to  Mission  Group or any of the First  Tier  Subsidiaries  under this
         Agreement,  as the case may be, shall exceed the amounts  previously  paid to such party,  then payment of
         such excess shall be made by the  appropriate  party,  as the case may be, on the  earliest  date on which
         (i)  Parent  shall  pay,  or be  deemed  to have  paid,  any  additional  taxes  resulting  from  any such
         adjustment;  (ii) Parent shall receive,  or be deemed to have received,  a refund of taxes  resulting from
         any such  adjustment;  or (iii) such adjustment  shall become final; any payment between Mission Group and
         any of the First Tier Subsidiaries  pursuant to (i) or (ii) above,  however,  shall not become final until
         the adjustment  with respect to which the  redetermination  was made becomes  final.  For purposes of this
         Section 3, an adjustment  shall become final at the time of the  expiration of the  applicable  statute of
         limitations  with respect to the taxable period to which such adjustment  relates,  or, if such adjustment
         was made pursuant to a decision of a court, at the time such decision shall become final.

4.Carryovers  and  Carrybacks.  If, for any taxable  period ending on or after December 31, 1986, any of the
         Subsidiaries  have Net Losses which,  under the  applicable  tax codes may be carried over or carried back
         to any taxable period in

Page 3


         which Parent filed, or reasonably anticipates that it will file, a Consolidated Return which includes such
         Subsidiary,  and such Net Losses give rise to a reduction in the tax liability of the  Consolidated  Group
         that would not have arisen if such  Subsidiary  were  excluded  from the  Consolidated  Group for any such
         taxable  period,  Mission Group shall pay to the applicable  First Tier  Subsidiary an amount equal to the
         actual reduction in the tax liability of the  Consolidated  Group for the taxable period to which such Net
         Losses may be carried,  which is  attributable  to such  carryover  or  carryback.  Payment of such amount
         shall be made by  Mission  Group (i) in the case of a  carryover,  on or before  the later of (a) the 15th
         day of the third month after the end of the taxable  period  with  respect to which the tax  liability  of
         the  Consolidated  Group was reduced and (b) the date on which such  reduction in tax liability is finally
         determined,  which shall be not later than 90 days after the  Consolidated  Return for such taxable period
         is filed;  and (ii) in the case of a carryback,  when the Consolidated  Group shall receive,  or be deemed
         to receive, the refund attributable to such carryback.

5.Priority of Tax  Benefits.  Notwithstanding  anything  to the  contrary  in this  Agreement  or the Master
         Agreement,  payment by Mission  Group to the First Tier  Subsidiaries  for Separate Tax Benefits  shall be
         made (i) first to Edison  Capital  for any  Separate  Tax  Benefits  of Edison  Capital and its Lower Tier
         Subsidiaries  and (ii) then to each of the other First Tier  Subsidiaries  in the ratio that the  Separate
         Tax Benefits of each of the other First Tier  Subsidiaries  and its Lower Tier  Subsidiaries  bears to the
         total of the aggregate Separate Tax Benefits of all Subsidiaries.

6.Termination.  Except with respect to Edison  Capital,  this  Agreement  may be  terminated  or modified by
         Mission  Group with respect to any tax year and all  subsequent  tax years by written  notice given to the
         First  Tier  Subsidiaries  prior to the  first  day of the  first  tax year  with  respect  to which  such
         termination is to be effective.  With respect to Edison  Capital,  this Agreement  shall not be terminated
         or modified to the  detriment  of Edison  Capital  and its Lower Tier  Subsidiaries  as long as the Edison
         Funding Company  Revolving  Credit  Agreement  dated as of June 13, 1995 (or a successor  agreement) is in
         effect or there are notes outstanding under the Edison Funding Company  Medium-Term  Notes,  Series A. Any
         termination  shall not relieve any party of any  obligation  arising under this  Agreement with respect to
         any tax year commencing prior to the giving of such notice.

7.Successors and  Beneficiaries.  This Agreement may not be assigned,  pledged,  transferred or hypothecated
         by any of the  Subsidiaries  without the express written  consent of Mission Group.  This Agreement may be
         assigned  to or assumed  by any  successor  in  interest  of  Mission  Group or any person to whom all the
         common stock of the  Subsidiaries is transferred.  The parties  acknowledge  that Parent became the parent
         holding  company of SCE and Mission Group  effective  July 1, 1988, at which time Parent  entered into the
         Master Agreement and assumed SCE's obligations to Mission Group under a

Page 4


         prior agreement for the allocation of income tax liabilities and benefits, as provided in Section 8.6 of the
         Master  Agreement.  References in this  Agreement to "Parent" shall be deemed to refer to SCE with respect
         to periods prior to July 1, 1988.

8.Governing  Law.  This  Agreement  shall be governed by and  construed in  accordance  with the laws of the
         State of California.

9.Additional  First Tier  Subsidiaries.  Any other  wholly-owned  first tier Mission Group subsidiary may be
         added to this Agreement as a First Tier  Subsidiary at any time by addendum  executed by Mission Group and
         the  subsidiary.  The addendum must provide such  subsidiary  will be bound by the terms of the Agreement.
         Mission Group shall provide a copy of the addendum to all other First Tier Subsidiaries.

         IN WITNESS WHEREOF,  the parties have executed this Agreement by their respective  officers thereunto duly
authorized as of the date first above written.

THE MISSION GROUP                                            EDISON CAPITAL



By: /s/ Thomas R. McDaniel                                   By: /s/ Thomas R. McDaniel


EDISON EV                                                    EDISON MISSION ENERGY



By: /s/ Diane O. Wittenberg                                  By: /s/ Edward R. Muller


EDISON SOURCE                                                EDISON SPECTRUM



By: /s/ C. Alex Miller                                       By: /s/ C. Alex Miller


MISSION LAND COMPANY



By: /s/ Thomas R. McDaniel




Page


ADDENDUM A TO

                                                 THE MISSION GROUP

                                   AMENDED AND RESTATED TAX ALLOCATION AGREEMENT


         This Addendum A to The Mission Group Amended and Restated Tax  Allocation  Agreement  dated  September 10,
1996 (the "Mission Group Agreement"), is effective April 30, 1998.

RECITALS

         WHEREAS, Edison International, a California corporation, which is the corporate parent of The Mission
Group ("Mission Group"), has entered into an Amended and Restated Agreement for the Allocation of Income Tax
Liabilities and Benefits (the "Master Agreement") dated as of September 10, 1996, with Southern California Edison
Company ("SCE") and Mission Group providing, among other things, for an equitable allocation among Edison
International ("Parent"), SCE and Mission Group of tax benefits and tax liabilities reflected in or resulting
from the filing of consolidated or combined income or franchise tax returns;

         WHEREAS,  pursuant to the Master  Agreement,  Mission Group makes  payments to and receives  payments from
Parent from time to time reflecting tax  liabilities and benefits  realized by the corporate group arising from net
operating  income and losses,  net capital  gains and losses,  and credits  against  tax,  attributable  to Mission
Group,  its  first  tier  subsidiaries  (the  "First  Tier   Subsidiaries")   and  their  respective   subsidiaries
(collectively, the "Subsidiaries");

         WHEREAS,  the Mission Group Agreement  provides for the continued  payment by Mission Group to each of the
First Tier  Subsidiaries  or from each of the First Tier  Subsidiaries to Mission Group, as the case may be, of the
respective  Separate Tax Benefit or Separate Tax  Liability of each of the  Subsidiaries,  calculated in accordance
with the Master Agreement;

         WHEREAS,  the Mission  Group  Agreement  provides  that any other  wholly-owned  first tier  subsidiary of
Mission  Group may be added to the  Mission  Group  Agreement  as a First Tier  Subsidiary  at any time by addendum
executed by Mission Group and the first tier subsidiary;

         WHEREAS,  Edison  Enterprises has been incorporated as a first tier subsidiary of Mission Group and as the
parent of Edison EV,  Edison Source and Edison  Select  (successor to Edison  Spectrum) so they are no longer first
tier subsidiaries of Mission Group;


Page


         WHEREAS,  it is deemed  appropriate for Edison  Enterprises to be substituted in place of its subsidiaries
under the Mission Group Agreement;

         NOW,  THEREFORE,  the parties  executing this Addendum A agree to the  substitution of Edison  Enterprises
under the Mission Group  Agreement in place of Edison EV, Edison Source and Edison Select,  and Edison  Enterprises
hereby agrees to be bound by the terms and conditions of the Mission Group Agreement.

         IN WITNESS  WHEREOF,  the parties have  executed this Addendum A by their  respective  officers  thereunto
duly authorized as of the effective date written above.


THE MISSION GROUP                                            EDISON ENTERPRISES



By: /s/ Thomas E. McDaniel                                   By: /s/ Stephen E. Pazian


EDISON EV                                                    EDISON SOURCE



By: /s/ Stephen E. Pazian                                    By: /s/ Stephen E. Pazian


EDISON SELECT (SUCCESSOR TO EDISON SPECTRUM)



By: /s/ Stephen E. Pazian



Page


ADDENDUM B TO

                                                 THE MISSION GROUP

                                   AMENDED AND RESTATED TAX ALLOCATION AGREEMENT


         This  Addendum  B to The  Mission  Group  Amended  and  Restated  Tax  Allocation  Agreement,  dated as of
September 10, 1996 (the "Mission Group Agreement"), is effective July 2, 2001.

RECITALS

         WHEREAS, Edison International, a California corporation, which is the corporate parent of The Mission
Group ("Mission Group"), has entered into an Amended and Restated Agreement for the Allocation of Income Tax
Liabilities and Benefits (the "Master Agreement"), dated as of September 10, 1996, with Southern California
Edison Company ("SCE") and Mission Group providing, among other things, for an equitable allocation among Edison
International ("Parent"), SCE and Mission Group of tax benefits and tax liabilities reflected in or resulting
from the filing of consolidated or combined income or franchise tax returns (capitalized terms not otherwise
defined herein have the meanings given them in the Master Agreement);

         WHEREAS,  pursuant to the Master  Agreement,  Mission Group makes  payments to and receives  payments from
Parent from time to time reflecting tax  liabilities and benefits  realized by the corporate group arising from net
operating  income and losses,  net capital  gains and losses,  and credits  against  tax,  attributable  to Mission
Group,  its  first  tier  subsidiaries  (the  "First  Tier   Subsidiaries")   and  their  respective   subsidiaries
(collectively, the "Subsidiaries");

         WHEREAS,  the Mission Group Agreement  provides for the continued  payment by Mission Group to each of the
First Tier  Subsidiaries  or from each of the First Tier  Subsidiaries to Mission Group, as the case may be, of the
respective  Separate Tax Benefit or Separate Tax  Liability of each of the  Subsidiaries,  calculated in accordance
with the Master Agreement;

         WHEREAS,  the Mission  Group  Agreement  provides  that any other  wholly-owned  first tier  subsidiary of
Mission  Group may be added to the  Mission  Group  Agreement  as a First Tier  Subsidiary  at any time by addendum
executed by Mission Group and the first tier subsidiary;

         WHEREAS,  Mission Energy Holding  Company has been  incorporated  and Mission Group has contributed all of
the capital  stock of Edison  Mission  Energy to Mission  Energy  Holding  Company in exchange  for all the capital
stock of Mission Energy Holding Company, so that Mission Energy Holding Company has become a first

Page


tier  subsidiary of Mission Group and Edison Mission Energy is no longer a first tier  subsidiary of Mission Group;
and

         WHEREAS,  it is deemed  appropriate  for Mission  Energy  Holding  Company to be  substituted  in place of
Edison Mission Energy in the Mission Group Agreement;

AGREEMENT

         NOW,  THEREFORE,  the parties  executing  this  Addendum B hereby  agree that (a) Mission  Energy  Holding
Company shall be  substituted  under the Mission Group  Agreement in place of Edison Mission Energy as a First Tier
Subsidiary,  (b) Mission  Energy  Holding  Company shall be bound by the terms and  conditions of the Mission Group
Agreement as a First Tier  Subsidiary,  and (c) Edison  Mission  Energy  shall be a Subsidiary  for purposes of the
Mission Group Agreement.

         IN WITNESS  WHEREOF,  the parties have  executed this Addendum B by their  respective  officers  thereunto
duly authorized as of the effective date written above.


THE MISSION GROUP                                            EDISON MISSION ENERGY



By: /s/ Theodore F. Craver, Jr.                              By: /s/ John E. Bryson


MISSION ENERGY HOLDING COMPANY



By: /s/ Theodore F. Craver, Jr.



Page


ADDENDUM C TO

                                                 THE MISSION GROUP

                                   AMENDED AND RESTATED TAX ALLOCATION AGREEMENT



         This  Addendum  C to The  Mission  Group  Amended  and  Restated  Tax  Allocation  Agreement,  dated as of
September 10, 1996 (the "Mission Group Agreement"), is effective July 2, 2001.

RECITALS

         WHEREAS, Edison International, a California corporation, which is the corporate parent of The Mission
Group ("Mission Group"), has entered into an Amended and Restated Agreement for the Allocation of Income Tax
Liabilities and Benefits (the "Master Agreement"), dated as of September 10, 1996, with Southern California
Edison Company ("SCE") and Mission Group providing, among other things, for an equitable allocation among Edison
International ("Parent"), SCE and Mission Group of tax benefits and tax liabilities reflected in or resulting
from the filing of consolidated or combined income or franchise tax returns (capitalized terms not otherwise
defined herein have the meanings given them in the Master Agreement);

         WHEREAS,  pursuant to the Master  Agreement,  Mission Group makes  payments to and receives  payments from
Parent from time to time reflecting tax  liabilities and benefits  realized by the corporate group arising from net
operating  income and losses,  net capital  gains and losses,  and credits  against  tax,  attributable  to Mission
Group,  its  first  tier  subsidiaries  (the  "First  Tier   Subsidiaries")   and  their  respective   subsidiaries
(collectively, the "Subsidiaries");

         WHEREAS,  the Mission Group Agreement  provides for the continued  payment by Mission Group to each of the
First Tier  Subsidiaries  or from each of the First Tier  Subsidiaries to Mission Group, as the case may be, of the
respective  Separate Tax Benefit or Separate Tax  Liability of each of the  Subsidiaries,  calculated in accordance
with the Master Agreement;

         WHEREAS,  the Mission  Group  Agreement  provides  that any other  wholly-owned  first tier  subsidiary of
Mission  Group may be added to the  Mission  Group  Agreement  as a First Tier  Subsidiary  at any time by addendum
executed by Mission Group and the first tier subsidiary; and

         WHEREAS,  Edison O&M Services has been  incorporated  as a wholly-owned  first tier  subsidiary of Mission
Group and it is deemed appropriate that Edison O&M Services be added to the Mission Group Agreement;



Page


AGREEMENT

         NOW,  THEREFORE,  the parties executing this Addendum C hereby agree that (a) Edison O&M Services is added
to the Mission  Group  Agreement  as a First Tier  Subsidiary,  and (b) Edison O&M  Services  shall be bound by the
terms and conditions of the Mission Group Agreement as a First Tier Subsidiary.

         IN WITNESS  WHEREOF,  the parties have  executed this Addendum C by their  respective  officers  thereunto
duly authorized as of the effective date written above.


THE MISSION GROUP                                            EDISON O&M SERVICES



By: /s/ Theodore F. Craver, Jr.                              By: /s/  Wesley C. Moody




AMENDED AND RESTATED TAX ALLOCATION AGREEMENT


         This amendment is entered into as of May 1, 1995 for the purpose of amending and restating the Tax
Allocation Agreement dated November 1, 1987 (as so amended and restated, being referred to herein as this
"Agreement"), by and between Mission First Financial, a California corporation ("Mission Financial"), and its
wholly-owned subsidiary, Mission Funding Company, a California corporation ("Funding").

RECITALS

A.       The Mission Group, a California corporation ("Mission Group"), has entered into a tax allocation
         agreement with its wholly-owned subsidiary, Mission Financial (the "Group Agreement") providing, among
         other things, for an equitable allocation between Mission Group and Mission Financial (as well as other
         wholly-owned subsidiaries of Mission Group) of tax benefits and tax liabilities reflected in or
         resulting from the filing of combined or consolidated income or franchise tax returns.

B.       Pursuant to the Group Agreement, Mission Financial makes payments to and receives payments from Mission
         Group from time to time reflecting tax liabilities and benefits realized by the corporate group arising
         from net operating income and losses, net capital gains and losses, and credits against tax,
         attributable to Mission Financial and its Subsidiaries.

C.       The parties desire to provide for the continued payment by Mission Financial to Funding or from Funding
         to Mission Financial, as the case may be, of the Separate Tax Benefits or Separate Tax Liabilities of
         Funding and its Subsidiaries, calculated in accordance with the Master Agreement (as such term is
         defined in the Group Agreement).  Terms used and not defined herein have the meanings given them in the
         Master Agreement or the Group Agreement.

AGREEMENT

         NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained and for
other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that
this Agreement is amended in its entirety to read as provided in the heading and recitals hereto, as provided in
this paragraph, and as follows:

1.Tax Liability and Benefit Payments.  For each taxable period to which the Master Agreement is
         applicable, Mission Financial shall utilize the

Page 1


         calculation made by SCEcorp under the Master Agreement of the amount of the Separate Tax Liability or Separate
         Tax Benefit (as such terms are defined in the Master Agreement) of Funding and its Subsidiaries.  On
         each date that any payment under the Master Agreement is to be made or received by Mission Group (or
         would have been made or received if an amount had been owed or receivable), (a) Funding shall pay to
         Mission Financial an amount equal to the Separate Tax Liabilities of Funding and each Subsidiary which
         is owned directly or indirectly by Funding for such taxable period (without deducting, with respect to
         any such member, the amount of any Separate Tax Benefit of any other member) and (b) Mission Financial
         shall pay to Funding an amount equal to the aggregate of the Separate Tax Benefits of Funding and of
         each Subsidiary which is owned directly or indirectly by Funding (without deducting, with respect to any
         such member, the amount of any Separate Tax Liability of any other member).  All payments by either of
         Mission Financial or Funding shall be made without setoff, counterclaim or deduction of any kind
         whatsoever, and whether or not payment is due or has been received from SCEcorp under the Master
         Agreement or from Mission Group under the Group Agreement.  Funding and its Subsidiaries shall provide
         to SCEcorp on a monthly basis, or upon demand as necessary, all relevant information necessary to
         calculate federal and state tax liabilities and payments.

2.Reconciliation of Tax Liability.  Upon receipt of each notice provided for in Section 2 of the Group
         Agreement, relating to reconciliation of quarterly estimated tax payments against the Consolidated
         Returns, Mission Financial shall forthwith determine and notify Funding of the effect, if any, of such
         reconciliation on the payments made to or received from Funding.  Funding shall pay to Mission Financial
         any additional tax liability due, or receive payment from Mission Financial for any overpayment, on the
         same date that Mission Financial makes or receives any payments under Section 2 of the Group Agreement.

3.Adjustments to Tax Liability.  If any adjustments are made to the income, gains, losses, deductions or
         credits pertaining to Funding or any Subsidiary which is owned directly or indirectly by Funding, as
         reported in a Consolidated Return filed by SCEcorp, by reason of the filing of an amended return or
         claim for refund, or arising out of an audit of such Consolidated Return by the Internal Revenue Service
         or applicable state agency, then the Separate Tax Liability or the Separate Tax Benefit of Funding or
         such Subsidiary shall be redetermined to give effect to any such adjustment as if it had been made as
         part of the filed Consolidated Return.  If any interest or penalty is to be paid or interest received as
         a result of a tax deficiency or refund, such interest or penalty shall be allocated in accordance with
         the item(s) giving rise to such interest or penalty.  Mission Financial agrees to

Page 2


         exercise its contest rights under the Group Agreement on behalf of Funding and the reasonable costs so incurred
         by Mission Financial shall be allocated upon such basis as is mutually agreed to by Mission Financial
         and Funding in advance of such contest.  If, as a result of such redetermination, any amounts due to
         Mission Financial or Funding under this Agreement, as the case may be, shall exceed the amounts
         previously paid to such party, then payment of such excess shall be made by the appropriate party, as
         the case may be, on the earliest date on which (i) SCEcorp shall pay, or be deemed to have paid, any
         additional taxes resulting from any such adjustment; (ii) SCEcorp shall receive, or be deemed to have
         received, a refund of taxes resulting from any such adjustment; or (iii) such adjustment shall become
         final; any payment between Mission Financial and Funding pursuant to (i) or (ii) above, however, shall
         not become final until the adjustment with respect to which the redetermination was made becomes final.
         For purposes of this Section 3, an adjustment shall become final at the time of the expiration of the
         applicable statute of limitations with respect to the taxable period to which such adjustment relates,
         or, if such adjustment was made pursuant to a decision of a court, at the time such decision shall
         become final.

4.Carryovers and Carrybacks.  If, for any taxable period ending on or after December 31, 1986, Funding or
         any Subsidiary which is owned directly or indirectly by Funding has Net Losses which, under the
         applicable tax codes may be carried over or carried back to any taxable period in which SCEcorp filed,
         or reasonably anticipates that it will file, a Consolidated Return which includes Funding, and such Net
         Losses give rise to a reduction in the tax liability of the Consolidated Group that would not have
         arisen if Funding or such Subsidiary were excluded from the Consolidated Group for any such taxable
         period,  Mission Financial shall pay to Funding an amount equal to the actual reduction in the tax
         liability of the Consolidated Group for the taxable period to which such Net Losses may be carried,
         which is attributable to such carryover or carryback.  Payment of such amount shall be made by Mission
         Financial (i) in the case of a carryover, on or before the later of (a) the 15th day of the third month
         after the end of the taxable period with respect to which the tax liability of the Consolidated Group
         was reduced and (b) the date on which such reduction in tax liability is finally determined, which shall
         be not later than 90 days after the Consolidated Return for such taxable period is filed; and (ii) in
         the case of a carryback, when the Consolidated Group shall receive, or be deemed to receive, the refund
         attributable to such carryback.

5.Priority of Tax Benefits.  Notwithstanding anything to the contrary in this Agreement or the Master
         Agreement, payment by Mission Financial to the subsidiaries of Mission Financial for Separate Tax
         Benefits shall be made first to Funding and then to other subsidiaries of Mission Financial.


Page 3


6.Termination.  This Agreement may not be terminated or modified by Mission Financial with respect to any
         tax year until the obligations secured by the Amended and Restated Security Agreement between Funding
         and Bank of America National Trust and Savings Association, as Security Representative, as the same may
         hereafter from time to time be amended, modified, restated or replaced, have been fully paid and
         discharged and any commitments related thereto have been terminated, including without limitation the
         obligations and commitments under the Amended and Restated Loan and Credit Agreement among Funding, the
         Banks listed in Schedule I thereto, Barclays Bank PLC as Co-Agent and Fronting Bank, and Bank of America
         National Trust and Savings Association, as Administrative Agent, as the same may hereafter from time to
         time be amended, modified, restated or replaced.  Any termination shall not relieve any party of any
         obligation arising under this Agreement with respect to any tax year commencing prior to the giving of
         such notice.

7.Successors and Beneficiaries.  This Agreement may not be assigned, pledged, transferred or hypothecated
         by Funding without the express written consent of Mission Financial.  This Agreement may be assigned to
         or assumed by any successor in interest of Mission Financial or any person to whom all the common stock
         of Funding is transferred.  The parties acknowledge that SCEcorp became the parent holding company of
         Edison and Mission Group effective July 1, 1988, at which time SCEcorp entered into the Master Agreement
         and assumed Edison's obligations to Mission Group under a prior agreement for the allocation of income
         tax liabilities and benefits, as provided in Section 8.6 of the Master Agreement.  References in this
         Agreement to "SCEcorp" shall be deemed to refer to Edison with respect to periods prior to July 1, 1988.

8.Governing Law.  This Agreement shall be governed by and construed in accordance with the laws of the
         State of California.

         IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers thereunto duly
authorized as of the date first above written




MISSION FIRST FINANCIAL                                      MISSION FUNDING COMPANY



By:  /s/ Thomas R. McDaniel                                  By:  /s/ Lawrence W. Yu


TAX ALLOCATION AGREEMENT


         This Agreement is entered into as of July 2, 2001, by and between Mission Energy Holding Company, a
Delaware corporation ("MEH"), and its wholly-owned subsidiary, Edison Mission Energy, a Delaware corporation
("EME").

RECITALS

A.       The Mission Group, a California corporation ("Mission Group"), has entered into a tax allocation
         agreement with its wholly-owned first-tier subsidiaries, including MEH (the "Group Agreement"),
         providing for an allocation between Mission Group and its wholly-owned first-tier subsidiaries of tax
         benefits and tax liabilities reflected in or resulting from the filing of combined or consolidated
         income or franchise tax returns.

B.       Pursuant to the Group Agreement, the first-tier subsidiaries of Mission Group make and receive payments
         from time to time reflecting tax liabilities and benefits realized by the corporate group arising from
         net operating income and losses, net capital gains and losses, and credits against tax, attributable to
         such first-tier subsidiaries and their subsidiaries.

C.       The parties desire to further provide for the payment by MEH to EME or from EME to MEH, as the case may
         be, of the Separate Tax Benefits or Separate Tax Liabilities of EME and each of the subsidiaries which
         is owned directly or indirectly by EME ("Lower Tier Subsidiaries"), calculated in accordance with the
         Master Agreement (as such term is defined in the Group Agreement).

D.       Terms used and not defined herein have the meanings given them in the Master Agreement or the Group
         Agreement.

AGREEMENT

         NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained and for
other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree as
follows:

1.Tax Liability and Benefit Payments.  For each taxable period to which the Master Agreement is
         applicable, MEH shall utilize the calculation made by Edison International under the Master Agreement of
         the amount of the Separate Tax Liability or Separate Tax Benefit (as such terms are defined in the
         Master Agreement) of EME and its Lower Tier Subsidiaries.  On each date that any payment under the
         Master Agreement is to be made or received by MEH (or would have been made or received if an amount had
         been owed or receivable), EME shall pay to MEH the amount by which (a) the aggregate of the Separate Tax
         Liability of EME, if it has a Separate Tax Liability, and the Separate Tax



Page 1




         Liabilities of each of its Lower Tier Subsidiaries which has a Separate Tax Liability, exceeds (b) the aggregate
         of the Separate Tax Benefit of EME, if it has a Separate Tax  Benefit, and the Separate Tax Benefits of
         each of its Lower Tier Subsidiaries which has a Separate Tax Benefit.  If, for any such taxable period,
         (a) the aggregate of the Separate Tax Benefit of EME, if it has a Separate Tax Benefit, and the Separate
         Tax Benefits of each of its Lower Tier Subsidiaries which has a Separate Tax Benefit exceeds (b) the
         aggregate of the Separate Tax Liability of EME, if it has a Separate Tax Liability, and the Separate Tax
         Liabilities of each of its Lower Tier Subsidiaries which has a Separate Tax Liability, MEH shall pay to
         EME an amount equal to such excess.

         All payments by either of MEH or EME shall be made without setoff, counterclaim or deduction of any kind
         whatsoever, and whether or not payment is due or has been received from Edison International under the
         Master Agreement or from Mission Group under the Group Agreement.  EME and its subsidiaries shall
         provide to Edison International, Mission Group, and MEH, on a monthly basis, or upon demand as
         necessary, all relevant information necessary to calculate federal and state tax liabilities and
         payments.

2.Reconciliation of Tax Liability.  Upon receipt of each notice provided for in Section 2 of the Group
         Agreement, relating to reconciliation of quarterly estimated tax payments against the Consolidated
         Returns, MEH shall forthwith determine and notify EME of the effect, if any, of such reconciliation on
         the payments made to or received from EME.  EME shall pay to MEH any additional tax liability due, or
         receive payment from MEH for any overpayment, on the same date that MEH makes or receives any payments
         under Section 2 of the Group Agreement.

3.Adjustments to Tax Liability.  If any adjustments are made to the income, gains, losses, deductions or
         credits pertaining to EME or any of its Lower Tier Subsidiaries, as reported in a Consolidated Return
         filed by Edison International, by reason of the filing of an amended return or claim for refund, or
         arising out of an audit of such Consolidated Return by the Internal Revenue Service or applicable state
         agency, then the Separate Tax Liability or the Separate Tax Benefit of EME or such Lower Tier Subsidiary
         shall be redetermined to give effect to any such adjustment as if it had been made as part of the filed
         Consolidated Return.  If any interest or penalty is to be paid or interest received as a result of a tax
         deficiency or refund, such interest or penalty shall be allocated in accordance with the item(s) giving
         rise to such interest or penalty.  MEH agrees to exercise its contest rights under the Group Agreement
         on behalf of EME and the reasonable costs so incurred by MEH shall be allocated upon such basis as is
         mutually agreed to by MEH and EME in advance of such contest.  If, as a result of such redetermination,
         any amounts due to MEH or EME under this Agreement, as the case may be, shall exceed the amounts
         previously paid to such party, then payment of such excess shall be made by the appropriate party, as
         the case may be, on the earliest date on which (i) Edison


Page 2




         International shall pay, or be deemed to have paid, any additional taxes resulting from any such adjustment;
         (ii) Edison International shall receive, or be deemed to have received, a refund of taxes resulting from
         any such adjustment; or (iii) such adjustment shall become final.  Any payment between MEH and EME
         pursuant to (i) or (ii) above, however, shall not become final until the adjustment with respect to
         which the redetermination was made becomes final.  For purposes of this Section 3, an adjustment shall
         become final at the time of the expiration of the applicable statute of limitations with respect to the
         taxable period to which such adjustment relates, or, if such adjustment was made pursuant to a decision
         of a court, at the time such decision shall become final.

4.Carryovers and Carrybacks.  If, for any taxable period ending on or after December 31, 1986, EME or any
         of its Lower Tier Subsidiaries has Net Losses which, under the applicable tax codes may be carried over
         or carried back to any taxable period in which Edison International filed, or reasonably anticipates
         that it will file, a Consolidated Return which includes EME, and such Net Losses give rise to a
         reduction in the tax liability of the Consolidated Group that would not have arisen if EME or such Lower
         Tier Subsidiary were excluded from the Consolidated Group for any such taxable period, MEH shall pay to
         EME an amount equal to the actual reduction in the tax liability of the Consolidated Group for the
         taxable period to which such Net Losses may be carried, which is attributable to such carryover or
         carryback.  Payment of such amount shall be made by MEH (i) in the case of a carryover, on or before the
         later of (a) the 15th day of the third month after the end of the taxable period with respect to which
         the tax liability of the Consolidated Group was reduced and (b) the date on which such reduction in tax
         liability is finally determined, which shall be not later than 90 days after the Consolidated Return for
         such taxable period is filed; and (ii) in the case of a carryback, when the Consolidated Group shall
         receive, or be deemed to receive, the refund attributable to such carryback.

5.Priority of Payments.  Notwithstanding anything to the contrary in this Agreement, all payments from MEH
         to EME for Separate Tax Benefits of EME and its Lower Tier Subsidiaries shall be subject to (a) the
         provisions of the Master Agreement establishing a priority for payments of Separate Tax Benefits to
         Southern California Edison Company and its subsidiaries and (b) the provisions of the Group Agreement
         establishing a priority for payments of Separate Tax Benefits to Edison Capital and its subsidiaries.
         Should any question arise as to the proper calculation of the Separate Tax Benefits or Separate Tax
         Liabilities of EME and its Lower Tier Subsidiaries, the determination of such question by Edison
         International shall be final.

6.Termination.  MEH and EME recognize that the Group Agreement may be terminated or modified by Mission
         Group in accordance with its terms.  Should the Group Agreement be so terminated or modified, this
         Agreement shall be terminated or deemed to be similarly modified, as the case may be, as of the


Page 3



         same effective date and to the same extent as the termination or modification of the Group Agreement.

7.Successors and Beneficiaries.  This Agreement may not be assigned, pledged, transferred or hypothecated

         by MEH or EME without the express, mutual, written consent of MEH and EME, and the express, written
         consent of Mission Group.

8.Counterparts.  This Agreement may be executed in one or more counterparts, each of which shall be an
         original and all of which taken together shall constitute one and the same agreement.

9.Governing Law.  This Agreement shall be governed by and construed in accordance with the laws of the
         State of California.

         IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers thereunto duly
authorized as of the date first above written


                                                             MISSION ENERGY HOLDING COMPANY



                                                             By:  /s/ Theodore F. Craver, Jr.


                                                             EDISON MISSION ENERGY



                                                             By:  /s/ Keven M. Smith


ADMINISTRATIVE AGREEMENT RE TAX ALLOCATION PAYMENTS


         This Agreement is entered into as of July 2, 2001, among Edison International, Southern California Edison Company, The
Mission Group, Edison Capital, Mission Energy Holding Company, Edison Mission Energy, Edison O&M Services, Edison Enterprises, and
Mission Land Company (the parties other than EIX are referred to herein collectively as the "Subsidiary Parties" and each
individually as a "Subsidiary Party").

RECITALS

A.       Edison International has entered into an Amended and Restated Agreement for the Allocation of Income Tax Liabilities and
         Benefits, dated as of September 10, 1996 (the "Master Agreement"), with its first-tier subsidiaries, Southern California
         Edison Company and The Mission Group, providing for an allocation among the parties of tax benefits and tax liabilities
         reflected in or resulting from the filing of consolidated or combined income or franchise tax returns.  The Master Agreement
         provides for Edison International to calculate the Separate Tax Liabilities and Separate Tax Benefits (as such terms are
         defined in the Master Agreement) of Southern California Edison Company and The Mission Group and of each of their respective
         directly or indirectly owned subsidiaries, and to make to or receive from Southern California Edison Company and The Mission
         Group, respectively, net payments with respect to the aggregate Separate Tax Benefit or Separate Tax Liability of each such
         company and all its respective subsidiaries.

B.       The Mission Group has entered into a related Amended and Restated Tax Allocation Agreement, dated as of September 10, 1996,
         as supplemented by addenda thereto (the "Group Agreement"), with its first-tier subsidiaries, Edison Capital, Mission Energy
         Holding Company, Edison O&M Services, Edison Enterprises, and Mission Land Company.  The Group Agreement provides for The
         Mission Group to use the calculations made by Edison International under the Master Agreement and to make to or receive from
         Edison Capital, Mission Energy Holding Company, Edison O&M Services, Edison Enterprises, and Mission Land Company,
         respectively, net payments with respect to the aggregate Separate Tax Benefit or Separate

Page 1




         Tax Liability of each such company and all its respective subsidiaries.

C.       Mission Energy Holding Company has entered into a related Tax Allocation Agreement, dated as of July 2, 2001 (the "Mission
         Energy Agreement"), with its first-tier subsidiary, Edison Mission Energy.  The Mission Energy Agreement provides for
         Mission Energy Holding Company to use the calculations made by Edison International under the Master Agreement and to make
         to or receive from Edison Mission Energy net payments with respect to the aggregate Separate

         Tax Benefit or Separate Tax Liability of Edison Mission Energy and all its subsidiaries.

D.       To promote efficient administration of payments under the Master Agreement, Group Agreement, and Mission Energy Agreement
         (referred to collectively herein, together with any amendments, supplements, addenda, or successor agreements, as the "Tax
         Allocation Agreements"), Edison International and the Subsidiary Parties desire to provide for payments under the Tax
         Allocation Agreements to be made directly between Edison International and each of the Subsidiary Parties as set forth
         herein.

AGREEMENT

         NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained and for other good and
valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree as follows:

1.Tax Liability and Benefit Payments.  On each date that any payments under the Tax Allocation Agreements are to be made or
         received by Edison International or the Subsidiary Parties (or would have been made or received if an amount had been owed
         or receivable), payments shall be made as follows:

         (a) Edison International shall pay to Southern California Edison Company or Southern California Edison Company shall pay to
         Edison International, as the case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and
         Separate Tax Liabilities of Southern California Edison Company and its subsidiaries;

         (b) Edison International shall pay to The Mission Group or The Mission Group shall pay to Edison International, as the case
         may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of The Mission
         Group and its subsidiaries (other than Mission Energy Holding Company, Edison Capital, Edison O&M Services, Edison
         Enterprises, Mission Land Company, and their subsidiaries);

         (c) Edison International shall pay to Edison Capital or Edison Capital shall pay to Edison International, as the case may
         be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of Edison Capital
         and its subsidiaries;

         (d) Edison International shall pay to Mission Energy Holding Company or Mission Energy Holding Company shall pay to Edison
         International, as the case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax
         Liabilities of Mission Energy Holding Company and its subsidiaries (other than Edison Mission Energy and its subsidiaries);


Page 2




         (e) Edison International shall pay to Edison Mission Energy or Edison Mission Energy shall pay to Edison International, as
         the case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of
         Edison Mission Energy and its subsidiaries;

         (f) Edison International shall pay to Edison O&M Services or Edison O&M Services shall pay to Edison International, as the
         case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of Edison
         O&M Services and its subsidiaries

         (g) Edison International shall pay to Edison Enterprises or Edison Enterprises shall pay to Edison International, as the
         case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of Edison
         Enterprises and its subsidiaries; and

         (h) Edison International shall pay to Mission Land Company or Mission Land Company shall pay to Edison International, as the
         case may be, an amount equal to the aggregate net amount of the Separate Tax Benefits and Separate Tax Liabilities of
         Mission Land Company and its subsidiaries.

2.Additional Subsidiaries.  Any Subsidiary Party may request Edison International to make payments for Separate Tax Benefits,
         if any, directly to any subsidiary of that Subsidiary Party.  In such case, that Subsidiary Party shall cause that
         subsidiary to make payments for Separate Tax Liabilities, if any, directly to Edison International.

3.Effect on Tax Allocation Agreements.  This Agreement establishes arrangements for the efficient administration of payments
         under the Tax Allocation Agreements.  Those payment arrangements and this Agreement shall not be construed to modify the
         rights and obligations of the parties under the Tax Allocation Agreements, except to the extent that any obligation to make
         a payment under any of the Tax Allocation Agreements is satisfied by a payment made in accordance with this Agreement.
         Notwithstanding anything to the contrary in this Agreement, all payments shall be subject to (a) the provisions of the
         Master Agreement establishing a priority for payments of Separate Tax Benefits to Southern California Edison Company and its
         subsidiaries and (b) the provisions of the Group Agreement establishing a priority for payments of Separate Tax Benefits to
         Edison Capital and its subsidiaries.  Should any question arise as to the proper calculation or payment of the Separate Tax
         Benefits or Separate Tax Liabilities of Edison International or any of the Subsidiary Parties, the determination of such
         question by Edison International shall be final.

4.Termination.  This Agreement may be terminated at any time by Edison International in its sole discretion.  Any termination
         shall not by itself effect a termination of any of the Tax Allocation Agreements.


Page 3


5.Successors and Beneficiaries.  This Agreement may not be assigned, pledged, transferred or hypothecated by any of the
         Subsidiary Parties without the express written consent of Edison International.

6.Counterparts.  This Agreement may be executed in one or more counterparts, each of which shall be an original and all of
         which taken together shall constitute one and the same agreement.

7.Governing Law.  This Agreement shall be governed by and construed in accordance with the laws of the State of California.

         IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers thereunto duly authorized as of
the date first above written.


EDISON INTERNATIONAL                                         SOUTHERN CALIFORNIA EDISON COMPANY


                                                             By:  /s/  W. James Scilacci
By:  /s/ Theodore F. Craver, Jr.


THE MISSION GROUP                                            EDISON CAPITAL


By:  /s/ Theodore F. Craver, Jr.                             By:  /s/ Thomas R. McDaniel


MISSION ENERGY HOLDING COMPANY                               EDISON MISSION ENERGY


By:  /s/ Theodore F. Craver, Jr.                             By:  /s/ Kevin M. Smith


EDISON O&M SERVICES                                          EDISON ENTERPRISES


By:  /s/ Wesley C. Moody                                     By:  /s/  Theodore F. Craver, Jr.


MISSION LAND COMPANY


By:  /s/ Thomas R. McDaniel


                                                                                          EXHIBIT 11

                                               EDISON INTERNATIONAL



                                COMPUTATION OF BASIC AND DILUTED EARNINGS PER SHARE





                                                                      For the Quarter ended
                                                                          September 30,
----------------------------------------------------------------------------------------------------

         In millions, except per-share amounts                   2002                     2001
----------------------------------------------------------------------------------------------------

         Consolidated net income (loss)                        $    352                 $   (413)
         Basic weighted average shares                              326                      326
         Diluted weighted average shares                            329                      326
         Basic earnings (loss) per share                       $   1.08                 $  (1.27)
         Diluted earnings (loss) per share                     $   1.07                 $  (1.27)


                                                                    For the Nine Months ended
                                                                          September 30,
----------------------------------------------------------------------------------------------------

         In millions, except per-share amounts                   2002                     2001
----------------------------------------------------------------------------------------------------

         Consolidated net income (loss)                        $ 1,101                  $ (1,132)
         Basic weighted average shares                             326                       326
         Diluted weighted average shares                           329                       326
         Basic earnings (loss) per share                       $  3.38                  $  (3.47)
         Diluted earnings (loss) per share                     $  3.35                  $  (3.47)






STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350,

                            AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (the
Quarterly Report) of Edison International (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by
Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, based on his or her knowledge,
that:

        1.    The Quarterly Report fully complies with the requirements of section 13(a) or 15(d) of the
              Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

        2.    The information contained in the Quarterly Report fairly presents, in all material respects, the
              financial condition and results of operations of the Company


                                                     /s/ John E. Bryson
                                                     ----------------------------------
                                                     John E. Bryson
                                                     Chief Executive Officer
                                                     Edison International



                                                     /s/ Theodore F. Craver, Jr.
                                                     ----------------------------------
                                                     Theodore F. Craver, Jr.
                                                     Chief Financial Officer
                                                     Edison International


This statement accompanies the Quarterly Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and
shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for
purposes of Section 18 of the Securities Exchange Act of 1934, as amended.