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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
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OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
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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 ___
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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
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EDISON INTERNATIONAL
INDEX
Page
No.
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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
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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)
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Net income (loss) $ 352 $ (413) $ 1,101 $ (1,132)
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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)
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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
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(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)
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Comprehensive income (loss) $ 276 $ (360) $ 1,133 $ (1,329)
- -------------------------------------------------------------------------------------------------------------------
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
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Total current assets 5,395 7,500
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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
- -------------------------------------------------------------------------------------------------------------------
Total utility plant 8,158 8,013
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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
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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
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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
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Total common shareholders' equity 4,417 3,272
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Total liabilities and shareholders' equity $ 33,873 $ 36,774
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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)
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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 has not 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.
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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
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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.
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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
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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
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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
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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.
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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.
o Cabazon Power Partners: Although previously stayed, the matter has been reactivated. Trial is now set
for April 2003.
o Salton 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