Back to GetFilings.com
===================================================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2002
----------------------------------------------------------------------------
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
-------------------------------------- ----------------------------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4137452
(State or other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California
(Address of Principal 91770
Executive Offices) (Zip Code)
(626) 302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days.
Yes X No ___
-----
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:
Class Outstanding at August 9, 2002
- ------------------------------------------------------- --------------------------------------------------------
Common Stock, no par value 325,811,206
===================================================================================================================
EDISON INTERNATIONAL
INDEX
Page
No.
------
Part I.Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income (Loss) - Three and Six Months
Ended June 30, 2002, and 2001 1
Consolidated Statements of Comprehensive Income (Loss) -
Three and Six Months Ended June 30, 2002, and 2001 1
Consolidated Balance Sheets - June 30, 2002,
and December 31, 2001 2
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2002, and 2001 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 14
Item 3. Quantitative and Qualitative Disclosures About Market Risk 60
Part II. Other Information:
Item 1. Legal Proceedings 61
Item 4. Submission of Matters to a Vote of Security Holders 65
Item 6. Exhibits and Reports on Form 8-K 65
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
3 Months Ended 6 Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility $ 2,161 $ 1,590 $ 4,093 $ 3,101
Nonutility power generation 747 723 1,357 1,312
Financial services and other 18 133 63 229
- -------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,926 2,446 5,513 4,642
- -------------------------------------------------------------------------------------------------------------------
Fuel 285 269 550 511
Purchased power 581 807 835 2,531
Provisions for regulatory adjustment clauses - net (331) (90) 366 (119)
Other operation and maintenance 826 754 1,546 1,472
Depreciation, decommissioning and amortization 263 230 508 453
Property and other taxes 36 29 75 59
Net gain on sale of utility plant -- (6) -- (7)
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,660 1,993 3,880 4,900
- -------------------------------------------------------------------------------------------------------------------
Operating income (loss) 1,266 453 1,633 (258)
Interest and dividend income 62 45 178 91
Other nonoperating income 7 19 23 31
Interest expense - net of amounts capitalized (317) (347) (677) (729)
Other nonoperating deductions (37) (51) (48) (54)
Dividends on preferred securities (24) (23) (47) (46)
Dividends on utility preferred stock (6) (6) (11) (11)
- -------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before taxes 951 90 1,051 (976)
Income tax (benefit) 289 31 305 (405)
- -------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations 662 59 746 (571)
Income (loss) from discontinued operations - net of tax 3 (161) 3 (148)
- -------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 665 $ (102) $ 749 $ (719)
- -------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings (loss) per share:
Continuing operations $ 2.03 $ 0.18 $ 2.29 $ (1.75)
Discontinued operations 0.01 (0.49) 0.01 (0.46)
- -------------------------------------------------------------------------------------------------------------------
Total $ 2.04 $ (0.31) $ 2.30 $ (2.21)
- -------------------------------------------------------------------------------------------------------------------
Weighted-average shares, including effect
of dilutive securities 329 326 329 326
Diluted earnings (loss) per share:
Continuing operations $ 2.01 $ 0.18 $ 2.27 $ (1.75)
Discontinued operations 0.01 (0.49) 0.01 (0.46)
- -------------------------------------------------------------------------------------------------------------------
Total $ 2.02 $ (0.31) $ 2.28 $ (2.21)
- -------------------------------------------------------------------------------------------------------------------
Dividends declared per common share -- -- -- --
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
3 Months Ended 6 Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income (loss) $ 665 $ (102) $ 749 $ (719)
Other comprehensive income, net of tax:
Foreign currency translation adjustments 63 (6) 79 (109)
Unrealized loss on investments - net (7) -- (7) --
Cumulative effect of change in accounting for derivatives 6 -- 6 167
Unrealized gain (loss) on cash flow hedges (13) 121 28 (340)
Reclassification adjustment for gain (loss)
included in net income (loss) 2 2 3 31
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income (loss) $ 716 $ 15 $ 858 $ (970)
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 1,593 $ 3,991
Receivables, less allowances of $47 and $41 for uncollectible
accounts at respective dates 1,263 1,259
Accrued unbilled revenue 553 451
Fuel inventory 138 124
Materials and supplies, at average cost 211 203
Accumulated deferred income taxes - net 694 1,092
Trading and price risk management assets 70 65
Regulatory assets - net 58 83
Prepayments and other current assets 175 232
- -------------------------------------------------------------------------------------------------------------------
Total current assets 4,755 7,500
- -------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision for
depreciation of $875 and $706 at respective dates 6,790 6,414
Nuclear decommissioning trusts 2,248 2,275
Investments in partnerships and unconsolidated subsidiaries 2,033 2,253
Investments in leveraged leases 2,433 2,386
Other investments 235 226
- -------------------------------------------------------------------------------------------------------------------
Total investments and other assets 13,739 13,554
- -------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 13,766 13,568
Generation 1,747 1,729
Accumulated provision for depreciation and decommissioning (8,319) (7,969)
Construction work in progress 650 556
Nuclear fuel at amortized cost 138 129
- -------------------------------------------------------------------------------------------------------------------
Total utility plant 7,982 8,013
- -------------------------------------------------------------------------------------------------------------------
Goodwill 684 633
Regulatory assets - net 5,728 5,528
Other deferred charges 1,346 1,341
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 7,758 7,502
- -------------------------------------------------------------------------------------------------------------------
Assets of discontinued operations 64 205
- -------------------------------------------------------------------------------------------------------------------
Total assets $ 34,298 $ 36,774
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions, except share amounts 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 72 $ 2,445
Long-term debt due within one year 1,491 1,499
Preferred stock to be redeemed within one year 9 105
Accounts payable 1,066 3,414
Accrued taxes 746 183
Trading and price risk management liabilities 34 24
Other current liabilities 2,040 2,187
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 5,458 9,857
- -------------------------------------------------------------------------------------------------------------------
Long-term debt 13,643 12,674
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 6,322 6,367
Accumulated deferred investment tax credits 170 172
Customer advances and other deferred credits 1,748 1,675
Power-purchase contracts 319 356
Accumulated provision for pension and benefits 571 505
Other long-term liabilities 159 147
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 9,289 9,222
- -------------------------------------------------------------------------------------------------------------------
Liabilities of discontinued operations 17 71
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 2 and 4)
Minority interest 407 345
- -------------------------------------------------------------------------------------------------------------------
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 950 949
Other preferred securities 122 104
- -------------------------------------------------------------------------------------------------------------------
Total preferred securities of subsidiaries 1,348 1,333
- -------------------------------------------------------------------------------------------------------------------
Common stock (325,811,206 shares outstanding at each date) 1,972 1,966
Accumulated other comprehensive income (loss) (219) (328)
Retained earnings 2,383 1,634
- -------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 4,136 3,272
- -------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 34,298 $ 36,774
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
6 Months Ended
June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income (loss) from continuing operations $ 746 $ (571)
Adjustments to reconcile net income (loss) to net cash provided
(used) by operating activities:
Depreciation, decommissioning and amortization 508 453
Other amortization 53 40
Deferred income taxes and investment tax credits (72) 12
Equity in income from partnerships and unconsolidated
subsidiaries (109) (200)
Income from leveraged leases (57) (62)
Regulatory assets - long-term - net 220 (253)
Write-down of non-utility assets -- 184
Other assets 6 (75)
Other liabilities 120 8
Changes in working capital:
Receivables and accrued unbilled revenue (96) 81
Regulatory liabilities - short-term - net 25 2
Fuel inventory, materials and supplies (2) (5)
Prepayments and other current assets (40) 247
Accrued interest and taxes 597 (434)
Accounts payable and other current liabilities (2,457) 1,466
Distributions and dividends from unconsolidated entities 177 59
Operating cash flows from discontinued operations 33 (15)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating activities (348) 937
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 1,797 1,742
Long-term debt repaid (1,030) (1,008)
Bonds remarketed (repurchased) and funds held in trust 192 (130)
Issuance of preferred securities -- 14
Redemption of preferred securities (100) --
Rate reduction notes repaid (115) (112)
Nuclear fuel financing - net (59) (10)
Short-term debt financing - net (2,322) 520
Financing cash flows from discontinued operations -- (304)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities (1,637) 712
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (629) (462)
Purchase of power sales agreement (80) --
Proceeds from sale of nonutility property 49 172
Net funding of nuclear decommissioning trusts 7 20
Distributions from (investments in) partnerships and
unconsolidated subsidiaries 90 (127)
Net investments in leveraged leases -- 69
Sales of investments in other assets 74 28
Investing cash flows from discontinued operations -- (23)
- -------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (489) (323)
- -------------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash 20 (70)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (2,454) 1,256
Cash and equivalents, beginning of period 4,054 1,973
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period 1,600 3,229
Cash and equivalents - discontinued operations (7) (63)
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, continuing operations $ 1,593 $ 3,166
- -------------------------------------------------------------------------------------------------------------------
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 (which are of a normal recurring nature) necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting
principles generally accepted in the United States for the periods covered by this report have been included.
The results of operations for the period ended June 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 June 30, 2002, financial
statement presentation.
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 instruments and hedging
activities. An authoritative accounting interpretation issued in October 2001 precludes fuel contracts that have
variable amounts from qualifying under the normal purchases and sales exception effective April 1, 2002. The
adoption of this interpretation did not have a significant impact on Edison International's financial
statements. Under a revised authoritative accounting interpretation issued in December 2001, EME's forward
electricity contracts no longer qualify for the normal sales exception since EME has net settlement provisions
with its counterparties. However, these contracts qualify as cash flow hedges. Edison International implemented
the December 2001 interpretation, effective April 1, 2002. As a result, Edison International recorded a
$6 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.
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
has completed its benchmark assessment, and has determined that no goodwill impairment exists, except for
goodwill related to EME's September 2000 acquisition of Citizens Power. Total goodwill related to Citizens Power
was $25 million as of December 31, 2001. Under accounting rules, an additional test must now be performed to
determine the amount of the impairment loss. The impairment test will be completed by December 31, 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 impact of the new
standard and is unable to predict at this time the 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
Page 5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of a $3.6 billion procurement-related obligations account (PROACT) as of August 31, 2001. The Utility Reform
Network (TURN), a consumer advocacy group, and other parties are pursuing an appeal 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 the matter is now under
submission. A decision could be issued at any time. SCE cannot predict the outcome of the appeal or the impact
that any outcome would have upon the stipulated judgment. Possible outcomes could include affirmance, a return
to the district court, a referral of a controlling state law question to the California Supreme Court, or
reversal of the stipulated judgment. SCE cannot predict whether or how a ruling on the stipulated judgment could
also affect the settlement agreement.
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 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 for
writ of mandamus in the California Supreme Court against the CPUC. The FTCR's petition asserts that the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE, and that the CPUC further intends to exceed its authority and violate state law in proposing and consenting
to a bankruptcy reorganization plan for Pacific Gas and Electric Company (PG&E). The petition seeks 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 petition also seeks an injunction against the
CPUC's expenditure of taxpayer funds in proposing or consenting to a PG&E bankruptcy reorganization plan that
violates state law. The FTCR's petition expressly states that it does 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 does not request any judicial actions regarding the settlement agreement. The FTCR is not
a party to TURN's federal court appeal concerning the stipulated the judgment.
The CPUC filed its response to the petition on July 12, 2002, and the FTCR submitted its reply brief on July 19,
2002. The matter is currently pending before the California Supreme Court. SCE cannot predict the outcome of
this matter or whether the FTCR will attempt in this or other proceedings to prevent the CPUC from continuing to
perform its obligations under the settlement agreement.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision authorizing
the 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. SCE and Edison
International intend to challenge the CPUC decision on the first priority condition (and Edison International
intends to challenge the CPUC decision on the jurisdictional matter) and are evaluating the timing and manner of
doing so. Edison International cannot predict what effects this investigation or any subsequent actions by the
CPUC may have on Edison International or any of its subsidiaries.
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 month 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 extremely 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. The FERC did not set a specific expiration date for its
new market mitigation plan. SCE cannot predict 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.
After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges 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 2002 and further hearings are scheduled in August 2002.
SCE cannot predict the amount of any potential refunds. Under the settlement agreement with the CPUC, refunds
will be applied to reduce the PROACT balance.
Note 3. Purchased Power
SCE purchased power through the PX 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:
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3 Months Ended 6 Months Ended
June 30, June 30,
- --------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
PX/ISO:
Purchases $ 82 $ (446) $ 64 $ 635
Generation sales -- (382) -- 323
- --------------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net 82 (64) 64 312
Purchased power - bilateral contracts 15 37 30 89
Purchased power - interutility/QF contracts 484 834 741 2,130
- --------------------------------------------------------------------------------------------------------------
Total $ 581 $ 807 $ 835 $ 2,531
- --------------------------------------------------------------------------------------------------------------
PX/ISO amounts for the six months ended June 30, 2002, and the three months ended June 30, 2001, reflect billing
adjustments. These billing adjustments are recovered through the PROACT and have no impact on earnings. Since
January 17, 2001, all other power 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.
Energy Crisis Issue
In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International. As
amended in December 2000 and March 2001, the lawsuit involved securities fraud claims arising from alleged
improper accounting for the energy-cost undercollections. The second amended 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. On September 17,
2001, SCE and Edison International filed a motion to dismiss for failure to state a claim. On March 8, 2002, the
district court issued an order dismissing the complaint with prejudice. The plaintiffs have stipulated to
dismiss their appeal. On April 26, 2002, the federal court of appeals approved the parties' stipulation and
ordered the appeal dismissed 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, primarily at Edison Mission Energy (EME). There is no assurance that EME would
be able to recover increased costs from its customers or that its 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
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 40 identified sites at SCE is
$104 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 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 $288 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 $49 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 $71 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 June 30, 2002, were $19 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts
in excess of the upper limit of the estimated range 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 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.
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
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S.
results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit
1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is
$88 million per reactor, but not more than $10 million per reactor may be charged in any one year for each
incident. Based on its ownership interests, SCE could be required to pay a maximum of $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 $40 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,
setting the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as
a monthly restructuring 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 is continuing 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 May 2002, as well as the restructure
settlement payments due for those months, 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 due 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.
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EME's investment in the Paiton project increased to $514 million at June 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. The outcome of these negotiations is uncertain at the present time. However, EME believes that it
will ultimately recover its investment in the project.
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.
Storm Lake
As of June 30, 2002, Edison Capital had an investment of approximately $85 million in Storm Lake Power, a project
developed by Enron Wind, a subsidiary of Enron Corporation. As of June 30, 2002, Storm Lake had outstanding
loans of approximately $73 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.
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), an
unregulated power generation segment (EME), and a capital and financial services provider segment (Edison
Capital).
Segment information for the three and six months ended June 30, 2002, and 2001, was:
3 Months Ended 6 Months Ended
June 30, June 30,
- --------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 2,161 $ 1,590 $ 4,093 $ 3,101
Unregulated power generation 747 723 1,357 1,312
Capital & financial services 14 73 45 116
Corporate and other 4 60 18 113
- --------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,926 $ 2,446 $ 5,513 $ 4,642
- --------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 695 $ 28 $ 841 $ (570)
Unregulated power generation(2) 3 -- (33) 9
Capital & financial services 12 24 31 36
Corporate and other(3) (45) (154) (90) (194)
- -------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 665 $ (102) $ 749 $ (719)
- --------------------------------------------------------------------------------------------------------------
(1) Net income (loss) available for common stock.
(2) Includes earnings from discontinued operations of $3 million in 2002 and losses from discontinued
operations of $41 million and $22 million, respectively, for the three and six months ended June 30,
2001.
(3) Includes losses from discontinued operations of $120 million and $126 million, respectively, for the
three and six months ended June 30, 2001.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment. The
net loss of $45 million and $90 million, respectively, reported for the three and six months ended June 30, 2002,
also includes Mission Energy Holding Company's net loss of $24 million and $46 million, respectively, for the
same periods.
Total segment assets as of June 30, 2002, were: electric utility, $19 billion; unregulated power generation,
$11 billion; and, capital 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. In 2002, revenue from discontinued operations
was $3 million and pre-tax income was $3 million. For the three and six months ended June 30, 2001, revenue from
discontinued operations was $181 million and $439 million, respectively, and pre-tax loss was $253 million and
$244 million, respectively.
Page 12
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The carrying value of assets and liabilities of discontinued operations were:
June 30, December 31,
In millions 2002 2001
- -----------------------------------------------------------------------------------------------
(Unaudited)
Assets
Cash and equivalents $ 6 $ 63
Receivables - net 7 1
Other 1 90
- -----------------------------------------------------------------------------------------------
Total current assets 14 154
- -----------------------------------------------------------------------------------------------
Other noncurrent assets 50 51
- -----------------------------------------------------------------------------------------------
Total assets $ 64 $ 205
- -----------------------------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities $ 10 $ 59
Short-term debt and other -- 5
- -----------------------------------------------------------------------------------------------
Total current liabilities 10 64
Noncurrent liabilities 7 7
- -----------------------------------------------------------------------------------------------
Total liabilities $ 17 $ 71
- -----------------------------------------------------------------------------------------------
Page 13
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 six-month periods ended June 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 six-month periods ended June 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 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 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 company) 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.
INDUSTRY DEVELOPMENTS RELATED TO EME
Edison International's unregulated (nonutility) power generation segment (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 recent significant developments have adversely affected not only those companies primarily focused on
the trading of electricity but also those independent power producers who sell a sizable portion of their
generation, not pursuant to long-term contract, but rather into the wholesale energy market. Often referred to
as merchant generators, the financial performance of these companies has been affected by one or more of the
following:
o A decline in the wholesale prices of energy caused, in part, by a substantial addition of new generating
capacity, as well as weak growth in near term demand for electricity, creating oversupply in many
regions of the United States.
o The bankruptcy of Enron and the subsequent disclosure of its having engaged in questionable trading
strategies.
Page 14
o The disclosure by a number of major energy companies of having engaged in wash trading (generally referring
to two countervailing trades between the same counterparties at the same time for the same quantity and
price), and the subsequent investigation of these activities by the United States Congress and various
federal agencies.
o The deterioration of the credit ratings and stock valuations of a number of the major merchant
generators and energy trading companies.
o The decline of liquidity in the energy markets as a result of tightening credit and increasing concern
about the ability of counterparties to perform against longer term obligations.
As a result, 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, decreases in capital
expenditures, reductions in operating costs and the issuance of equity.
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 its 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 its 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, EME has this year been affected by lower wholesale prices of energy, particularly
at its Homer City facilities in Pennsylvania, and the diminished ability to enter into forward contracts for the
sale of power primarily from these facilities because of the credit constraints affecting it and many of its
counterparties.
EME's Illinois plants have been largely unaffected by these developments this year, because Exelon Generation
(ExGen) is under contract with EME to buy substantially all of the capacity of these units for the balance of
2002. However, as permitted by the contracts governing EME's coal-fired units in Illinois, ExGen has advised EME
that they will not exercise their right to purchase 2,684 megawatts (MW) of the capacity of these units for 2003
and 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 its merchant risk. See further discussion in the EME Illinois
Plants section of Market Risk Exposures.
In addition, the credit ratings of EME and some of its subsidiaries are under review for possible downgrade below
investment grade by Moody's and Standard & Poor's due to industry developments, lower wholesale energy prices and
the increase in EME's merchant risk beginning in 2003, as described above. See EME's Credit Rating.
Against this background, EME has:
o reduced its already modest proprietary trading activities and further emphasized its focus on sales of
power from, and risk management around, its Homer City facilities and Illinois plants;
o suspended new business development activities;
o initiated a review of its capital expenditure program to determine whether individual projects
appropriately can be delayed or cancelled;
o in connection with the foregoing, undertaken a review of the future plans for the three turbines in
fabrication which it has on order;
o announced that beginning in January 2003 operations will be suspended at Units 1 and 2 of its Will
County plant in Illinois; and
o initiated a company-wide review of its organization and related costs.
Page 15
In addition, EME continues to review the possibility of further sales of assets, but believes for the reasons
discussed in more detail below that current market conditions may inhibit its ability to obtain prices
commensurate with its valuation of those investments, which EME might wish to offer for sale. For a discussion of
EME's current financial condition, see EME's Liquidity Issues in the Financial Condition section.
RESULTS OF OPERATIONS
Edison International's earnings per share were $2.04 and $2.30, respectively, for the three and six months ended
June 30, 2002, compared with losses of 31(cent)and $2.21, respectively, for the three and six months ended June 30,
2001. The table below presents Edison International's net income and earnings per share for the three and six
months ended June 30, 2002, and June 30, 2001, and the relative contributions by its subsidiaries.
In millions, except per share amounts EPS Net Income
- ------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings:
SCE $ 0.66 $ 0.28 $ 215 $ 91
EME -- 0.12 -- 41
Edison Capital 0.04 0.08 12 24
Mission Energy Holding (stand alone) (0.07) -- (24) --
Edison International (parent) and other (0.07) (0.11) (21) (34)
- ------------------------------------------------------------------------------------------------------------
Edison International Core Earnings 0.56 0.37 182 122
SCE procurement-related adjustment -- (0.19) -- (63)
SCE implementation of URG decision 1.47 -- 480 --
- ------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 2.03 0.18 662 59
- ------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Discontinued Operations 0.01 (0.49) 3 (161)
- ------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 2.04 $ (0.31) $665 $ (102)
- ------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings:
SCE $ 1.11 $ 0.47 $ 361 $ 154
EME (0.11) 0.10 (36) 30
Edison Capital 0.09 0.11 31 36
Mission Energy Holding (stand alone) (0.14) -- (46) --
Edison International (parent) and other (0.13) (0.21) (44) (67)
- ------------------------------------------------------------------------------------------------------------
Edison International Core Earnings 0.82 0.47 266 153
SCE procurement-related adjustment -- (2.22) -- (724)
SCE implementation of URG decision 1.47 -- 480 --
- ------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
(Loss) from Continuing Operations 2.29 (1.75) 746 (571)
- ------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Discontinued Operations 0.01 (0.46) 3 (148)
- ------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 2.30 $ (2.21) $ 749 $ (719)
- ------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
Edison International's second quarter 2002 earnings from continuing operations were $662 million, compared with
$59 million for second quarter 2001; year-to-date 2002 earnings from continuing operations were $746 million,
compared with a loss of $571 million in 2001.
In 2002, SCE's second quarter and year-to-date earnings were $695 million and $841 million, respectively,
compared to earnings of $28 million and a loss of $570 million, respectively, for the three and six months ended
June 30, 2001. The 2002 earnings include a $480 million one-time gain in the second quarter to
Page 16
reflect the implementation of a California Public Utilities Commission (CPUC) decision in SCE's utility-retained
generation (URG) proceeding. In 2001, SCE's second quarter earnings and year-to-date loss included $63 million
and $724 million, respectively, in procurement-related adjustments for undercollected power procurement costs.
Excluding these adjustments, SCE's second quarter and year-to-date earnings for the periods ended June 30, 2002,
were $215 million and $361 million, respectively, compared to earnings of $91 million and $154 million,
respectively, for the three and six months ended June 30, 2001. The $124 million increase in SCE's second
quarter 2002 earnings and the $207 million increase in year-to-date 2002 earnings primarily reflects increased
revenue from the implementation of the CPUC's April 2002 decision in SCE's performance-based ratemaking (PBR)
proceeding, the accrual of interest income on the procurement-related obligations account (PROACT) balance and
lower interest expense. SCE's increases in 2002 also reflect lower earnings in 2001 resulting from an extended
outage at the San Onofre Nuclear Generating Station. 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 six months of 2001, SCE had $724 million 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, 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 of December 31, 2001. 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 less than $1 million in earnings from continuing operations and incurred a loss from continuing
operations of $36 million, respectively, for the quarter and year-to-date period ended June 30, 2002, compared to
earnings of $41 million and $30 million, respectively, for the same periods in 2001. The decreases were
primarily due to lower U.S. energy prices in 2002 compared to 2001, unplanned outages at the Homer City plant and
gains during 2001 related to gas swaps for EME's oil and gas activities. These decreases in earnings were
partially offset by income from the Paiton project in Indonesia and improved operating results from EME's
Illinois plants. 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 second quarter and year-to-date 2002 earnings were $12 million and $31 million, respectively,
compared to $24 million and $36 million, respectively, for the three and six months ended June 30, 2001. The
decreases are the result of a decrease in earning assets, the impact of a change from the cost method to the
equity method of accounting for its fund investments in conformance with the funds' accounting policy and no
significant asset sales in 2002, partially offset by a re-evaluation of Edison Capital's reserves and lower
expenses.
Mission Energy Holding Company (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 $46 million, respectively,
for the three- and six-month periods ending June 30, 2002, due to interest expense on debt issued in mid-2001,
the proceeds of which were used to repay Edison International's debt.
Edison International (parent company) and other incurred losses of $21 million and $44 million, respectively, in
the three and six months ended June 30, 2002, compared to losses of $34 and $67 for the same periods in 2001.
The improvement in 2002 was mostly due to lower interest expense.
Page 17
Operating Revenue
More than 95% 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 six months ended June 30, 2002, compared to the same periods
in 2001. The increases were primarily 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. To compensate for a two-month
delay in collecting the 3(cent)surcharge, the CPUC authorized an additional 1/2(cent) surcharge for a 12-month period
beginning in June 2001, which contributed to the increase in revenue. In May 2002, the CPUC allowed the
continuation of the 1/2(cent) 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 be reported as an increase to revenue and cash by as much as $200 million for
the remainder of 2002, but will have no impact on earnings (see Temporary Surcharge). The increase in revenue
from the surcharge was partially offset by a decrease in revenue arising from an increase in credits given to
direct access customers in 2002, as compared to 2001, as a result of a significant increase in the number of
direct access customers in 2002. Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the California Department of Water Resources (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
$255 million and $596 million for the three- and six-month periods ended June 30, 2002, compared to $461 million
and $718 million for the three- and six-month periods ended June 30, 2001.
With respect to the decrease in revenue in 2002 arising from the credits given to direct access customers, 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 PROACT
Regulatory Asset section below.
Nonutility power generation revenue increased for the three- and six-month periods ended June 30, 2002, compared
to the same periods in 2001, primarily due to increases at EME related to 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 plant. 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 Homer City plant, lower income from its investment in
cogeneration projects and lower income from its oil and gas activities.
Electric power at EME's Illinois plants is sold under agreements with Exelon Generation Company (ExGen). EME's
revenue related to these agreements was $274 million and $436 million, for the three and six months ended June
30, 2002, representing 37% and 32% of nonutility power generation revenue for the respective periods, and $261
million and $425 million for the three and six months ended June 30, 2001, representing 36% and 32% of nonutility
power generation revenue for the respective periods. See further discussion of the ExGen power purchase
agreements in Market Risk Exposures.
Financial services and other revenue decreased for both the quarter and year-to-date period ended June 30, 2002,
primarily from Edison Capital's decrease in earning assets and no significant asset sales in 2002, and 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.
Page 18
Operating Expenses
Purchased-power expense decreased significantly for the three- and six-month periods ended June 30, 2002, as
compared to the respective periods in 2001. The decreases resulted primarily from lower expenses related to
qualifying facilities (QFs), bilateral contracts and interutility contracts. In addition, the six-month period
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 and second quarters of 2002, spot natural gas prices were significantly lower than the same
periods in 2001. The decrease in purchased-power expense related to bilateral contracts and interutility
contracts was also due to the decrease in natural gas prices.
SCE has contracts with certain QFs in which EME has 49% - 50% ownership interests. The terms and pricing of
these contracts are approved by the CPUC. SCE's power purchases from these facilities were $138 million and $221
million for the three and six months ended June 30, 2002, compared to $185 million and $350 million for the
respective periods in 2001. The decrease was attributable to the effect of lower gas prices in the QF pricing
formula adopted by the CPUC.
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 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. The increase for the three months
ended June 30, 2002, in PX/ISO purchased power was partially due to these invoicing adjustments.
Provisions for regulatory adjustment clauses decreased for the second quarter of 2002, compared to the same
period in 2001. The second quarter decrease in the provisions was primarily due to the impact of SCE's
implementation of CPUC decisions related to URG and the PBR mechanism, as well as the impact of other regulatory
issues, all partially offset by overcollections used to reduce the PROACT balance.
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). The decreases discussed above were
partially offset by 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.
These overcollections were used to reduce the PROACT balance.
Provisions for regulatory adjustment clauses increased for the six months ended June 30, 2002, compared to the
respective period in 2001, as a result of overcollections used to reduce the PROACT balance, partially offset by
the impact of the URG and PBR decisions discussed above.
Page 19
Other operating and maintenance expense increased for the three- and six-month periods ended June 30, 2002,
compared to the same periods in 2001. The increases were primarily due to increases at SCE and EME, partially
offset by decreases at Edison Capital and other non-utility subsidiaries.
Other operating and maintenance expense at SCE increased for the three- and six-month periods ended June 30,
2002, compared to the same periods in 2001, primarily due to increases resulting from ISO-related grid management
expenses and expenses related to the San Onofre Unit 2 refueling outage that occurred during second quarter 2002.
EME's operating and maintenance expenses increased for both periods in 2002, primarily due to the consolidation
of Contact Energy and higher lease costs related to the sale-leaseback commitments for Homer City.
Employees at EME's Illinois plants in union-represented positions are covered by collective bargaining agreements
that expire December 31, 2005. EME is currently discussing with the union-represented employees their employee
benefits agreement that expired on June 15, 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,
which means that EME is assuming, for accounting purposes, that postretirement benefits will be provided to these
employees following conclusion of negotiations, although there is no legal obligation to do so. If no
postretirement benefits were provided, EME would treat this as a plan termination and record a gain. Negotiations
are in process and are expected to be finalized by the end of 2002.
The decrease in operating and maintenance expense at Edison Capital and other non-utility subsidiaries was mainly
due to the re-evaluation of the various reserve requirements during second quarter of 2002, and lower
administrative and general expenses during the first six months of 2002 at Edison Capital, as well as lower
operational costs due to 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.
Depreciation, decommissioning and amortization expense increased for both the three- and six-month periods ended
June 30, 2002, as compared to the respective periods in 2001, mainly due to an increase in depreciation expense
associated with SCE's distribution assets, as well as an increase related to SCE's nuclear 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).
Property and other taxes increased for the six-month period ended June 30, 2002, compared to the respective
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 three- and six-month periods ended June 30, 2002, compared to the
respective periods 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 the second quarter of 2002, as compared to second quarter
2001.
Other nonoperating income decreased for both the three and six months ended June 30, 2002, compared to the
year-earlier periods. The decreases were primarily due to lower earnings from corporate-owned life insurance at
SCE, as well as a decrease at EME primarily related to foreign exchange losses on intercompany loans during 2002.
Page 20
Interest expense - net of amounts capitalized decreased for the three and six months ended June 30, 2002, mainly
due to lower short-term debt balances during 2002, partially offset by an increase in interest expense related to
higher long-term debt balances at both SCE and MEHC in second quarter 2002.
Other nonoperating deductions decreased for the three and six months ended June 30, 2002, primarily due to lower
accruals at SCE for regulatory matters in 2002, offset by an increase resulting from EME's minority interest
expense arising from the consolidation of Contact Energy effective June 1, 2001, as a result of increasing
ownership to majority control.
Income Taxes
Income tax expense increased for the three- and six-month periods in 2002, primarily due to the income tax
benefit SCE recorded in 2001 related to its power procurement cost undercollection and the deferred income tax
expense associated with the reestablishment of generation-related regulatory assets upon implementation of the
URG decision. The effective income tax rate for both periods decreased as a result of this benefit.
Earnings (Loss) from Discontinued Operations
Edison International recorded earnings from discontinued operations of $3 million for both the three- and
six-month periods ended June 30, 2002, due to an insurance recovery at EME for claims filed prior to the sale of
the Ferrybridge and Fiddler's Ferry coal stations. Edison International recorded losses from discontinued
operations of $161 million and $148 million, respectively for the three- and six-month periods ended June 30,
2001. EME recorded losses from discontinued operations of $41 million and $22 million, respectively, at the
Ferrybridge and Fiddler's Ferry coal stations located in the U.K., which were sold later in 2001. Edison
Enterprises (a nonutility subsidiary of Edison International that formerly provided retail services) recorded
losses from discontinued operations of $120 million and $126 million, respectively, for the three- and six-month
periods ended June 30, 2001, reflecting operating losses and a $117 million impairment charge in the second
quarter of 2001 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.
At June 30, 2002, Edison International's principal subsidiaries had $681 million of borrowing capacity available
under lines of credit totaling $1.1 billion. SCE has drawn on its entire $300 million line of credit, which
expires March 2004. EME had borrowing capacity of $681 million available to finance general cash requirements,
under its total lines of credit of $750 million, which includes a one-year $538 million component that expires
September 2002, 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.
Page 21
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 has notified the administrative agent that it will
repay $300 million of this loan on August 14, 2002.
SCE expects to meet its continuing obligations in 2002 from remaining cash on hand and future operating cash
flows. Material factors affecting the timing of recovery of the PROACT balance are discussed below in PROACT
Regulatory Asset. SCE's liquidity after 2002, may, among other things, be affected by matters described in the
CPUC Litigation Settlement Agreement and the Generation Procurement Proceeding sections.
EME's Liquidity Issues
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 six months of each year
are not necessarily indicative of annual distributions due to the seasonal fluctuations in EME's business.
Page 22
Six Months Ended
June 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 4.3 0.3
Distributions from Non-Consolidated Operating Projects:
Distributions from Big 4 projects(1) 82.0 --
Distributions from Four Star Oil and Gas Company 21.0 40.7
Distributions from other non-consolidated operating
projects 29.4 14.3
-------------------------------------------------------------------- --------------- --------------
Total Distributions $ 136.7 $ 150.6
-------------------------------------------------------------------- --------------- --------------
(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 return of the capital
subsequently. Distributions reflect the amount received by EME after debt service payments by
EME Funding Corp.
Changes in distributions between the six-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 half of 2002.
o Lower profitability of the First Hydro project.
o Current payment during the first half of 2002 of accounts receivable by the Big 4 Projects from SCE ,
compared to delayed payment during the first half of 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.
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 EME affiliate. 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:
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
Page 23
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 the following financial performance
requirements measured on the date of distribution:
1. At the end of each quarter, the debt service coverage ratio for the prior twelve-month period (taken as
a whole) must be greater than 1.75 to 1. The debt service coverage ratio is defined as cash receipts
from sales less cash disbursements for operating expenses and required capital expenditures divided by
the aggregate of the amounts due under the credit facility and the Collins lease.
2. The debt service coverage ratio projected for each of the next two twelve-month periods must be greater
than 1.75 to 1.
3. The debt-to-capital ratio must be no greater than 0.60 to 1.
4. Credit ratings of long-term debt of Edison Mission Midwest Holdings must be investment grade. See EME's
Credit Ratings section for further discussion regarding the impact of a downgrade on the ability of
Edison Mission Midwest Holdings to make distributions to EME.
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. 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.
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.
At June 30, 2002, Edison Mission Midwest Holdings met the historical financial performance measures. However, as
a result of lower wholesale energy prices and the possible downgrade of Edison Mission Midwest Holdings' credit
rating, EME cannot predict at this time whether Edison Mission Midwest Holdings expects to meet the forward
looking tests or ratings requirements on distribution dates in the future. If Edison Mission Midwest Holdings is
unable to meet the forward looking tests or rating requirements, EME would be unable to receive distributions of
cash from Edison Mission Midwest Holdings on the next distribution date (October 1, 2002), notwithstanding the
projected availability of $138 million of cash for distribution on that date.
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:
1. 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.
Page 24
2. At the end of each quarter, the equity and debt portions of rent then due and payable must have been
paid.
3. The senior rent service coverage ratio (discussed in item 1 above) projected for each of the following
two twelve-month periods must be greater than 1.7 to 1.
4. 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 June 30, 2002, EME Homer City met the above financial performance measures. However, as a result of lower
wholesale prices of electricity and the adverse impact of the plant outages during the first half of 2002, EME
does not expect EME Homer City to have funds available for distributions to EME in 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 financial performance requirement:
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 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 was below the threshold required to permit distributions. 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 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:
1. The debt service coverage ratio for the preceding four fiscal quarters is at least 1.25 to 1.
2. 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 June 30, 2002,
Page 25
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 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 as agreed in the amendment to the power purchase agreement. 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 2005.
Loy Yang B Project - During 2001, EME began construction of a 300 MW gas-fired peaker plant located adjacent to
the Loy Yang B coal-fired power plant site, which EME refers to as the Valley Power Peaker project. 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 other power generators and distribution businesses. EME
completed the construction of the peaker plant during the first half of 2002. EME financed construction of the
project in part through an interim financing which it is in the process of replacing with long-term financing.
Until the long-term financing is completed, EME is not permitted to make cash distributions, which it would
otherwise have been able to make, from the Loy Yang B project. EME expects that the long-term financing of the
project will be completed prior to September 30, 2002.
Doga Project - A distribution of approximately $20 million from the Doga project has been approved by project
lenders. EME is in discussions with its minority partner on the most efficient means of making a distribution
from this project and expects that this will be completed by the end of 2002.
Lakeland Project - With the introduction of the new electricity trading arrangements and the U.K. government's
so-called transfer scheme, the Lakeland power sales agreement and related documents required amendment to be
consistent with the procedures under the new trading arrangements and to implement the separation of the supply
and distribution businesses of the counterparty to the power sales agreement mandated by the transfer scheme.
These amendments require lender approval without which no distributions are permitted from the project. EME is
currently seeking approval of agreed amendments and anticipate that the approval process will be completed no
later than October 2002 and that distributions will then be made. As of June 30, 2002, approximately $18 million
was otherwise available for distribution.
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, the project is required to provide the
lending group periodically 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
Page 26
been resolved with the project's lending group. It is anticipated that these matters will be resolved by
December 31, 2002.
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
are 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 June 30, 2002 was 1.93 to 1. See further details of
EME's financial ratios below. Accordingly, until EME's interest coverage ratio exceeds 2.2 to 1 for the
immediately preceding four quarters, it can only pay dividends to MEHC if it has an investment grade rating and
has received rating agency confirmation that a dividend will not result in a downgrade or has received unanimous
approval of its board of directors, including its independent director. EME has not paid or declared a dividend
to MEHC during the first half of 2002 and, based on the current expectations, does not expect to make any
distributions during the remainder of 2002 and 2003.
EME's Financial Ratios
EME and its principal bank lenders use two primary financial ratios: a recourse debt to recourse capital ratio
and an interest coverage ratio. These ratios are determined in accordance with financial covenants that have
been included in EME's corporate credit facilities and are not determined in accordance with generally accepted
accounting principles as reflected in its Consolidated Statements of Cash Flows. While the ratios included in
EME's corporate credit facilities are designed to measure the leverage and ability of EME to meet its debt service
obligations, they do not measure the liquidity or ability of EME's subsidiaries to meet their debt service
obligations. Furthermore, these ratios are not necessarily comparable to other similarly titled captions of
other companies due to differences in methods of calculations.
EME's corporate credit facilities include covenants tied to these financial ratios(1):
Actual at
Financial Ratio Covenant June 30, 2002 Description
- ----------------------------------------------------------------------------------------------------------
Recourse Debt to Less than or 62.4% Ratio of (a) senior recourse debt to (b) sum
Recourse Capital equal to 67.5% of (i) shareholder's equity per EME's
Ratio balance sheet adjusted by comprehensive
income after December 31, 1999, plus (ii)
senior recourse debt
Interest Coverage Greater than 1.93 to 1.00 For prior 12-month period, ratio of (a)
Ratio or equal to funds flow from operations to (b) interest
1.50 to 1.00 expense on senior recourse debt
- ----------------------------------------------------------------------------------------------------------
(1) EME's corporate credit facilities and corporate debt securities include a Tangible Net Worth Covenant,
which is determined based on EME's shareholder's equity adjusted for changes in other comprehensive
income after December 31, 1999. At June 30, 2002, EME's tangible net
Page 27
worth as determined in accordance with the covenant was $968 million, which exceeds the covenant
requirement of $615 million.
At June 30, 2002, EME met the above financial covenants. The actual interest coverage ratio during 2001 and the
twelve months ended June 30, 2002, was adversely 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 2.06 to 1 for the twelve months ended June 30, 2002. Compliance with these
covenants is subject to future financial performance, including items that are beyond EME's control.
Discussion of Recourse Debt to Recourse Capital Ratio
- -----------------------------------------------------
The recourse debt to recourse capital ratio of EME at June 30, 2002, and December 31, 2001, was calculated as
follows:
June 30, December 31,
In millions 2002 2001
- ----------------------------------------------------- --------------------- ----------------------
Recourse Debt(1)
Corporate Credit Facilities $ 76.7 $ 203.6
Senior Notes 1,600.0 1,700.0
Guarantee of termination value of
Powerton/Joliet operating leases 1,442.5 1,431.9
Coal and Capex Facility 172.0 251.6
Other 45.5 46.3
- ----------------------------------------------------- --------------------- ----------------------
Total Recourse Debt to EME 3,336.7 3,633.4
Adjusted Shareholder's Equity(2) 2,008.5 2,039.0
Recourse Capital(3) $ 5,345.2 $ 5,672.4
- ----------------------------------------------------- --------------------- ----------------------
Recourse Debt to Recourse Capital Ratio 62.4% 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 six months ended June 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
$60 million;
o final repayment of the $100 million senior notes in June 2002; and
o payments on a Coal and Capex facility with proceeds from Ferrybridge and Fiddler's Ferry working capital
settlements that occurred after the divestiture.
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
Page 28
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.
Discussion of Interest Coverage Ratio
- -------------------------------------
The following table sets forth the major components of EME's interest coverage ratio for the twelve months ended
June 30, 2002, and the year ended December 31, 2001:
June 30, December 31,
In millions 2002 2001
- -------------------------------------------------------------------------- ---------------- -------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating
Projects(2):
Illinois Plants $ 284.7 $ 201.3
Homer City 101.8 175.2
Ferrybridge and Fiddler's Ferry (57.8) (104.5)
First Hydro 50.6 45.9
Other consolidated operating projects 64.7 64.1
Trading and price risk management 8.8 28.2
Distributions from non-consolidated Big 4 projects(3) 210.9 128.8
Distributions from other non-consolidated operating projects 88.8 93.5
Interest income 6.4 9.0
Operating expenses (154.3) (143.1)
- -------------------------------------------------------------------------- ---------------- -------------------
Total funds flow from operations $ 604.6 $ 498.4
- -------------------------------------------------------------------------- ---------------- -------------------
Interest Expense:
From obligations to unrelated third parties $ 198.2 $ 188.7
From notes payable to Midwest Generation 115.1 116.1
- -------------------------------------------------------------------------- ---------------- -------------------
Total interest expense $ 313.3 $ 304.8
- -------------------------------------------------------------------------- ---------------- -------------------
Interest Coverage Ratio 1.93 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 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 on 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 June 30, 2002, compared to
the year ended December 31, 2001, were:
o Lower market prices for energy and capacity and major unplanned outages at the Homer City facilities.
o Decline in fuel costs, lower operating expenses, and higher capacity revenue for the Illinois plants.
o As a result of the sale of the Ferrybridge and Fiddler's Ferry plants in December 2001, EME did not
incur negative cash flow from this project in the quarter ended June 30, 2002. However,
Page 29
since the interest coverage ratio test measures the prior four quarters, this project will still affect
the ratio until the quarter ended December 31, 2002.
o Distributions from EME's investments in partnerships subsequent to their receipt of payments of past due
accounts receivable from SCE.
Interest expense increased $9 million during the twelve months ended June 30, 2002, from the year ended
December 31, 2001, as a result of:
o an increase in borrowing costs from refinancing short-term debt with 2001 issuances of $1 billion
long-term fixed rate debt as well as higher interest margins on EME's corporate credit facilities; and
o including Coal and Capex Facility interest expense as corporate interest expense after the divestiture
of Ferrybridge and Fiddler's Ferry in December 2001-prior to the sale, this interest expense was
classified as part of Operating Cash Flow of this project.
EME's Credit Ratings
To isolate itself from the impact of the California power crisis on Edison International and SCE, and to
facilitate its ability and the ability of its subsidiaries to maintain its respective investment grade credit
ratings, on January 17, 2001, EME amended its articles of incorporation and its bylaws to include so-called
ring-fencing provisions. These ring-fencing provisions are intended to preserve EME as a stand-alone investment
grade rated entity. These provisions require the unanimous approval of its board of directors, including at
least one independent director, before EME can do any of the following:
o declare or pay dividends or distributions unless either of the following are true: EME then has an
investment grade credit rating and receives rating agency confirmation that the dividend or
distribution will not result in a downgrade; or the dividends do not exceed $32.5 million in any fiscal
quarter and EME meets an interest coverage ratio (calculated as described under Discussion of Interest
Coverage Ratio) of not less than 2.2 to 1 for the immediately preceding four fiscal quarters.
o institute or consent to bankruptcy, insolvency or similar proceedings or actions; or consolidate or
merge with any entity or transfer substantially all EME's assets to any entity, except to an entity
that is subject to similar restrictions.
In January 2001, Moody's and Standard & Poor's downgraded EME's senior unsecured credit ratings to Baa3 from Baa1
and to BBB- from A-, respectively. On July 3, 2002, Moody's placed under review for possible downgrade MEHC's
rating (senior secured at Ba3), and the ratings of EME (senior unsecured at Baa3), and EME's wholly owned
indirect subsidiaries, Edison Mission Midwest Holdings Co. (bank facility at Baa2) and Midwest Generation, LLC
(lessor bonds at Baa2). On July 25, 2002, Standard & Poor's changed its outlook to negative from stable on its
BBB- corporate credit ratings of EME, Edison Mission Midwest Holdings Co., and Edison Mission Marketing and
Trading. In addition, Standard & Poor's changed its outlook to negative from stable on its BBB- ratings on the
lessor bonds of the Homer City lease and the lessor bonds of the Powerton and Joliet leases. On August 7, 2002,
Standard & Poor's lowered its senior unsecured credit rating on Edison Mission Energy Funding Corp. to BB from
BBB-. There is no assurance that Moody's and Standard & Poor's will not downgrade these credit ratings below
investment grade.
If the credit rating of EME is downgraded below investment grade, EME could be required to, among other things:
o provide additional collateral in the form of letters of credit or cash for the benefit of counterparties
in its domestic trading and price risk management activities related to accounts receivable and
unrealized losses ($7 million at June 30, 2002); and
o post a letter of credit or cash collateral to support its $49 million equity contribution obligation in
connection with its acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd.
Page 30
project in the Philippines, which equity contribution would otherwise be payable commencing after full
drawdown of the debt facility currently scheduled for late 2002.
More generally, a downgrade of EME's credit ratings below investment grade could increase its cost of capital,
increase its credit support obligations, affect its ability to meet debt service coverage and other financial
ratios specified in various financing agreements binding on it and its subsidiaries, make efforts to raise
capital more difficult and have an adverse impact on EME and its subsidiaries. In addition, in order to continue
to market the power from its Illinois plants, Homer City facilities and First Hydro plants in the U.K. as well as
purchase natural gas or fuel oil at its Illinois Plants, EME may be required to provide substantial additional
credit support in the form of letters of credit or cash. Finally, changes in forward market prices and margining
requirements could further increase the need for credit support for EME's trading and risk management activities.
Possible Downgrade of Edison Mission Midwest Holdings
- -----------------------------------------------------
In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the
agreements binding on Edison Mission Midwest Holdings and Midwest Generation would limit the ability of Edison
Mission Midwest Holdings to use excess cash flow to make distributions to EME. The following 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:
Cost of Borrowing
S&P Rating Moody's Rating Margin Cash Trap
-------------------- ------------------- ------------------- ----------------------------------------------
(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
(excess free cash required to be used to
repay debt)
-------------------- ------------------- ------------------- ----------------------------------------------
As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds
($1,367 million) 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) section for a discussion of implications for the Powerton and Joliet leases.
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
Page 31
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
is permitted to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool
(PJM) at any time. See Homer City Facilities discussion in Market Risk Exposures.
EME Financing Plans
EME Corporate Financing Plans
- -----------------------------
EME has a $750 million corporate credit facility which includes a one-year $538 million component, Tranche A,
that expires on September 17, 2002, and a three-year $212 million component, Tranche B, that expires on September
17, 2004. At June 30, 2002, EME had borrowing capacity under this facility of $681 million and corporate cash
and cash equivalents of $31 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 its 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 was $415 million, of which EME's share was $206 million.
In addition, EME received $211 million in tax-allocation payments from the parent company, which included
$73 million related to the amount due at December 31, 2001, and $138 million as an estimated tax-allocation
payment for 2002. EME expects to receive approximately $146 million in tax-allocation payments during the
remainder of 2002. Furthermore, EME expects to receive tax-allocation payments during 2003 of approximately
$200 million. These payments and cash distributions from its subsidiaries represent major sources of cash of EME
to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by
many factors beyond its control, some of which are described 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.
In addition, EME plans to seek a new $300 million to $400 million corporate facility with financial institutions
by September 17, 2002, as a replacement of Tranche A of its existing corporate facility. EME is aware that a
number of merchant energy companies have recently been in discussions with their lenders regarding new credit
facilities or extensions to their existing lines of credit. EME understands that, as a result of market
conditions surrounding these companies, they have been either unable to renew, extend or otherwise enter into
similar credit facilities or have entered into new or amended credit facilities with a reduced size, increased
cost of borrowing and more restrictive terms. Accordingly, there is no assurance that EME will be able to enter
into a new line of credit or, if EME is able to enter into a new or extended line of credit, that the amount and
the terms would not be substantially different from those under its current credit facility. Tranche B of EME's
corporate facility ($212 million) does not expire until September 17, 2004.
EME Subsidiary Financing Plans
- ------------------------------
The estimated capital and construction expenditures of EME's subsidiaries for the remaining two quarters of 2002
are $98 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 $23 million in 2002 to fund the estimated capital expenditures of this project,
of which $13 million was contributed during the first half of 2002.
EME has anticipated that upgrades to environmental controls at the Illinois Plants to reduce nitrogen oxide
emissions would result in expenditures of approximately $318 million for the period 2003-2005. As a result of
changes in the merchant energy marketplace, EME is evaluating its capital expenditure program, including
environmental improvements. At June 30, 2002, EME had capitalized $34 million as construction in progress
related to environmental improvements. EME is currently updating its capital
Page 32
expenditure program and evaluating whether to proceed, delay or cancel individual projects. EME expects to
complete the update of its capital expenditure program by the end of 2002.
Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, EME's
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. 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 MAIN)
region and the improved reliability of power generation in the Chicago area, EME has undertaken preliminary
discussion with Commonwealth Edison, ExGen, and the City of Chicago regarding alternatives to construction of 500
MW of capacity which EME does not believe is needed at this time. If EME were to install this additional
capacity, it estimates that the cost could be as much as $320 million.
On August 9, 2002, EME 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). This transaction represents the
only synthetic lease that EME had outstanding at June 30, 2002. The exercise of the purchase option resulted in
the payment of $300 million to the owner-lessor, of which EME received $255 million as repayment of the note
receivable held by EME. Accordingly, the net cash outlay required to exercise the purchase option was
$45 million. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated
useful lives.
EME has commitments to purchase three turbines for a new gas-fired project. These turbines are planned to be used
to meet EME's additional gas-fired generation obligations at the Illinois plants, or for a new development project.
The amount capitalized at June 30, 2002, related to these three turbines was $75 million. Due to continued changes in the
wholesale energy markets and discussions regarding the additional gas-fired generation obligation at the Illinois
plants (as discussed above), EME is evaluating whether to consummate the purchase of these turbines and maintain
them in storage until market conditions improve or cancel the equipment purchase contracts. If EME cancels the
contracts, under the terms of the purchase contracts, EME would be entitled to recover amounts paid in excess of
50% of the turbine purchase price, but it would also result in a pre-tax loss of $61 million. EME expects to
make a decision regarding the plan for these turbines by September 30, 2002.
Valley Power Peaker Project
- ---------------------------
During 2001, EME began construction of the Valley Peaker project, 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, with the remaining interest held by its 51.2% affiliate, 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 other power generators and distribution businesses. EME completed the construction
of the peaker plant during the first half of 2002. EME financed construction of this project in part through an
interim financing which it is in the process of replacing with long-term financing. Until the long-term
financing is completed, EME is not permitted to make cash distributions, which it would otherwise be able to
make, from the Loy Yang B project. EME expects that the long-term financing of the project will be completed
prior to September 30, 2002.
Sunrise Project Financing
- -------------------------
EME owns a 50% interest in Sunrise Power Company, 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
Page 33
June 25, 2001. 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 return of a portion
of its equity contribution.
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 the 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. MEHC has not received any distributions from EME during
the first half of 2002 and, based on the current expectations, no distributions are expected during the remainder
of 2002 and 2003.
At June 30, 2002, MEHC had $30 million of cash and cash equivalents and $220 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,
expected to be approximately $60 million during the remainder of 2002, 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.
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 financing documents, 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 Financial Ratios above. The following
table sets forth an actual
Page 34
and pro forma calculation of MEHC's interest coverage ratio for the twelve months ended June 30, 2002, and the
year ended December 31, 2001:
December 31, 2001
Pro Forma
June 30, Adjust-
In millions 2002 Actual ments(1) Pro Forma
- ------------------------------------------------- ------------- -- ----------- ---------------- ------------
Funds Flow From Operations:
EME $ 604.6 $ 498.4 $ 498.4
Less: Operating cash flow from
unrestricted subsidiaries (15.9) -- --
Add: Outflows of funds from
operations of projects sold 56.8 103.3 103.3
MEHC (stand alone) 9.2 4.9 $ 4.9 9.8
- -------------------------------------------------- ------------ -- ------------ --------------- ------------
$ 654.7 $ 606.6 $ 4.9 $ 611.5
- -------------------------------------------------- ------------ -- ------------ --------------- ------------
Interest Expense:
EME $ 313.3 $ 304.7 $ 304.7
EME - affiliate debt 2.2 3.4 3.4
MEHC interest expense 161.5 82.2 $ 79.7 161.9
Less: Interest savings on projects sold (1.8) (4.5) (4.5)
- -------------------------------------------------- ------------ -- ------------ --------------- ------------
$ 475.2 $ 385.8 $ 79.7 $ 465.5
- -------------------------------------------------- ------------ -- ------------ --------------- ------------
Interest Coverage Ratio 1.38 1.57 1.31
- -------------------------------------------------- ------------ -- ------------ --------------- ------------
(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 financing documents governing the term loan agreement.
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 June 30, 2002, Edison Capital had cash on hand of $224 million and current liabilities of approximately
$203 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 during the remainder of 2002,
and expected cash flow from operating activities.
Edison Capital has unfunded commitments of $167 million for both current and long-term liabilities for both
affordable housing projects and energy 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 the receipt of these
tax-allocation payments. In 2001, none of the benefits and incentives generated by Edison Capital was utilized
on the Edison International consolidated tax return and therefore Edison Capital did not receive any payments
during the year. In 2002, Edison Capital received $283 million in tax-allocation payments through June 2002, and
expects to receive an additional $280 million by year-end.
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.
Page 35
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 various cash flows related to income taxes. 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. In addition, 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. See
additional discussion below in CPUC Litigation Settlement Agreement. 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
pay dividends in the first and second quarters 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
above. EME did not pay or declare a dividend during the first six months of 2002. As of June 30, 2002, Edison
International's investment in MEHC, through a wholly owned subsidiary, 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. Edison International expects to continue to pay
all other obligations, as they are due.
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. At June 30, 2002, the parent company had $135 million of cash on hand,
accumulated primarily from payments received under the tax-allocation agreement. In 2002, Edison International
received $46 million in tax-allocation payments through June 2002, and expects to receive an additional $25
million by year end.
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.
Cash Flows from Operating Activities
Net cash provided (used) by operating activities:
Six Months Ended
June 30,
- ----------------------------------------------------------------------------------------------------------
In millions 2002 2001
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ (381) $ 952
Discontinued operations 33 (15)
- ----------------------------------------------------------------------------------------------------------
$ (348) $ 937
- ----------------------------------------------------------------------------------------------------------
Page 36
Cash used by operating activities from continuing operations for the six months ended June 30, 2002, was
primarily due to SCE's March 2002 repayment of past-due obligations, mainly related to purchased power, partially
offset by overcollections used to reduce the PROACT balance during the first six months of 2002.
Cash provided by operating activities from continuing operations for the six months ended June 30, 2001, was
primarily due to SCE temporarily suspending payments for interest on outstanding debt and for purchased power
beginning in January 2001.
Cash provided by operating activities also reflects the CPUC-approved surcharges (1(cent)per kWh in January 2001, 3(cent)
per kWh in June 2001, and a temporary 1/2(cent) per kWh in June 2001) that were billed.
Cash Flows from Financing Activities
Net cash provided (used) by financing activities:
Six Months Ended
June 30,
- ----------------------------------------------------------------------------------------------------------
In millions 2002 2001
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ (1,637) $ 1,016
Discontinued operations -- (304)
- ----------------------------------------------------------------------------------------------------------
$ (1,637) $ 712
- ----------------------------------------------------------------------------------------------------------
Cash used by financing activities in the six months ended June 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, and long-term debt
repayments in second quarter 2002. 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 first quarter 2002.
Also contributing to the usage of cash were EME's net payments on its corporate credit facility and short-term
borrowings in connection with the restructuring of a power sales agreement with an unaffiliated electric utility.
Cash provided by financing activities in the six months ended June 30, 2001, was primarily due to SCE's draw on
its credit line, partially offset by the repurchase of pollution control bond in early 2001 that could not be
remarketed in accordance with their terms, and EME's issuances of debt, net of payments.
Cash used by financing activities from discontinued operations in 2001 was primarily related to the early
repayment of the term-loan facility related to the Ferrybridge and Fiddler's Ferry power plants.
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 has notified the administrative agent that it will prepay $300 million of this
loan on August 14, 2002.
Cash Flows from Investing Activities
Net cash provided (used) by investing activities:
Six Months Ended
June 30,
- ----------------------------------------------------------------------------------------------------------
In millions 2002 2001
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ (489) $ (300)
Discontinued operations -- (23)
- ----------------------------------------------------------------------------------------------------------
$ (489) $ (323)
- ----------------------------------------------------------------------------------------------------------
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.
Page 37
COMMITMENTS
Edison International's long-term debt maturities and sinking fund requirements for the five twelve-month periods
following June 30, 2002 are: 2003 - $1.5 billion; 2004 - $2.8 billion; 2005 - $3.4 billion; 2006 - $605 million;
and 2007 - $908 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 June 30, 2002, are:
2003 - $9 million; 2004 - $9 million; 2005 - $9 million; 2006 - $9 million; and 2007 - $113 million. These
amounts have been updated to reflect SCE's redemption of 100,000 shares of Series 6.45% preferred stock due in
second quarter 2002.
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 procurement costs during the PROACT
recovery period. After the PROACT recovery period, SCE expects to recover its procurement costs through ongoing
ratemaking proceedings.
Depending upon regulatory or legislative actions, SCE may resume procurement of its residual net short (i.e., the
amount of energy SCE must procure for its customers from sources other than its own generating plants, power
purchase contracts and energy allocated by the CPUC from the CDWR contracts) beginning January 1, 2003. If SCE
is required to resume procurement responsibility, SCE's liquidity will be subject to market risk to the extent
there is not a regulatory or legislative framework in place to provide assurance of timely recovery of SCE's
costs of procuring power in retail rates. See the discussion under Generation Procurement Proceeding below.
Currently, SCE is seeking CPUC authority to enter into contracts for capacity and related natural gas and gas
transmission arrangements, for up to five years in length, to hedge its residual net short exposure. To the
extent SCE is not allowed to enter into these contracts or the CPUC does not allow SCE to purchase sufficient
quantities to adequately hedge its risk, SCE could be subject to greater impacts from fluctuations in the market
price of energy. SCE's ability to enter into capacity contracts also will be affected by the current financial
condition of potential counterparties. Many potential counterparties with capacity products available were
recently downgraded below investment grade by the rating agencies. Even if the CPUC permits SCE to enter into
contracts, and if SCE is successful in finding counterparties, SCE would still be subject to commodity price
risk.
SCE's residual net short exposure is significant during the first quarter of 2003, because of a planned refueling
outage of 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. See additional discussion in CPUC Litigation
Settlement Agreement and Generation Procurement Proceeding.
On July 17, 2002, the FERC issued an order implementing a market power mitigation program for the 11-state
western region. SCE cannot predict 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.
Page 38
See additional discussion on these matters in CPUC Litigation Settlement Agreement, Generation Procurement
Proceeding and Wholesale Electricity Markets.
EME
EME's primary market risk exposures are associated with the sale of electricity from its uncontracted generating
plants and the procurement of fuel for them and, therefore, 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 Industry Developments Related to EME and EME's Credit Ratings for a discussion of the market developments and
their impact on EME's credit and credit of its counterparties.
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 daily reporting to senior management. 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 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 EME's 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
Page 39
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 EME's market area is set forth below.
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 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 the energy and capacity sales from the Illinois plants in the first six 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.
Under the power purchase agreement related to EME's coal-fired generation units, ExGen had the option,
exercisable not later than 180 days prior to January 1, 2003, to retain under the terms of the agreement for 2003
the capacity of certain option coal units having a capacity of 3,949 MW, with any such capacity not retained
being released after January 1, 2003, from the terms of the agreement. 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. It remains committed to purchase the capacity of certain committed
units having 1,696 MW of capacity for both 2003 and 2004.
In July 2002, ExGen notified Midwest Generation 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.
The following table lists the committed coal units, the units for which ExGen has exercised its call option for
2003, and the units which, 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.
Page 40
Coal-Fired Units
Summer(1) Non-Summer(1)
Capacity Charge Capacity Charge Energy Prices
Unit Size ($ per MW Month ($ per MW Month) ($/MWh)
Unit Name (MW) 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.
(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.
ExGen also has the option, which it may exercise on or before October 2, 2002, to terminate the power purchase
agreements related to the Collins Station and the peaker plants effective as of January 1, 2003. EME is unable to
predict whether ExGen will exercise this option as to any of the Collins or peaker units. The exercise of these
options will have no effect on ExGen's commitments to purchase capacity from these units for the remainder of
2002.
In July 2002, Midwest Generation and ExGen amended the power purchase agreement related to EME's peaker plants to
reinstate, as of July 1, 2002, within the terms of that agreement four of the oil peaker units at its Fisk
Station with a capacity of 160 MW. These units had been released from the terms of that agreement by ExGen
previous exercise of its options.
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, the Illinois plants will
be subject to the market risks related to the price of energy and capacity described above. EME intends to
manage this 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.
Page 41
During 2003, the primary markets available to EME for electricity sales 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 six 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 42
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
- -----------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------
(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.
EME 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 EME will
hedge its market price risk through forward over-the-counter sales depends on several factors. First, EME 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, EME's ability to enter into
hedging transactions will depend upon EME's liquidity and upon the over-the-counter forward sales markets' having
sufficient liquidity to enable EME to identify counterparties who are able and willing to enter into hedging
transactions with EME. 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. This decrease in market liquidity may require EME to
rely more heavily on sales to end user counterparties in the direct customer markets. EME is unable to predict
the credit quality that such end user counterparties may have. 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 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.
In addition to the prevailing market prices, the ability of EME 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
Page 43
vary from unit to unit. In this regard, EME has announced a plan to suspend operations of Units 1 and 2 at its
Will County plant 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.
EME'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, EME cannot predict how quickly or how effectively such issues
will be resolved.
A group of transmission-owning utilities have 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. As recently filed by Commonwealth Edison with FERC, Commonwealth Edison will
join PJM either as an individual transmission owner, or as a member of an Independent Transmission Company (ITC).
Furthermore, as filed by Commonwealth Edison and approved by FERC, the Commonwealth Edison transmission system,
to which the Illinois Plants are directly interconnected, will be fully integrated into the PJM market structure
by the last quarter of 2003. EME believes that the integration into the PJM market will allow EME 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.
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.
The following table depicts the average historical market prices per megawatt hour in PJM during the first six
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
--------------------------------------------------------------
Six-month Average $ 23.01 $ 31.85
--------------------------------------------------------------
* Prices were calculated using historical hourly prices
provided on the PJM-ISO web-site.
As shown on the above table, the average historical market prices during the first six months of 2002 are below
the average market prices during the first six months of 2001. These forward prices will continue to
Page 44
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. At the end of July
2002, EME's forecasted yearly average 24-hour PJM price for 2002 was $25.31, 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 six 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
-----------------------------------------------------------------
* Prices were obtained by gathering publicly available broker quotes.
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 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. In connection with the new electricity
trading arrangements, the First Hydro plant entered into forward contracts with varying terms that expire on
various dates through October 2003. In addition, two long-term contracts with a three-year termination provision
entered into in March 1999 from the First Hydro plant to buy and sell electricity were amended as forward
contracts.
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,
Page 45
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
affiliated 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 a 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 $105.9 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. Generation capacity on the U.K. system was in excess of demand due to generators holding plant on the
system at part load to protect themselves against the adverse affects of being out of balance in the new market
and the mild weather experienced during 2001.
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.
Credit Risks
- ------------
In conducting its trading and price risk management activities, EME contracts with a number of utilities, energy
companies and financial institutions. 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 its 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. 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, initiates actions to lower credit exposure and takes credit reserves if appropriate.
ExGen accounted for 36% and 42% of EME's consolidated operating revenue in 2001 and 2000, respectively. EME
expects ExGen to represent a similar amount of EME's consolidated revenue in 2002. Any failure of ExGen to make
payments under the power purchase agreements could adversely affect EME's results of operations and financial
condition.
Page 46
Foreign Exchange Rate Risk
- --------------------------
As discussed in the 2001 MD&A, 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, its 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. There are no assurances, however, that fluctuations in exchange rates
will be fully offset by hedges or that currency movements and the relationship between certain macro economic
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 six months of 2002, foreign currencies in the U.K., Australia and New Zealand increased in value
compared to the U.S. dollar by 4.8%, 10.1% and 17.4%, respectively (determined by the change in the exchange
rates from December 31, 2001, to June 30, 2002). The increase in value of these currencies was the primary
reason for the foreign currency translation gain of $79 million during the first six months of 2002.
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:
June 30, December 31,
In millions 2002 2001
- ---------------------------------------------------------------------------------------
Derivatives:
Interest rate:
Interest rate swap/cap agreements $ (24.6) $ (35.8)
Interest rate options (0.2) (1.0)
Commodity price:
Forwards 50.5 63.8
Futures (0.5) (8.4)
Options 0.2 0.4
Swaps (127.8) (137.6)
Foreign currency forward exchange agreements (0.6) (0.6)
Cross currency interest rate swaps 3.9 27.6
- ---------------------------------------------------------------------------------------
Page 47
In assessing the fair value of its 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 risk management assets and liabilities (as of June 30, 2002):
Total Maturity Maturity Maturity Maturity
Fair Less than 1 to 3 4 to 5 greater than
In millions Value 1 year years years 5 years
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Assets:
Prices actively quoted $ 26.0 $ 23.7 $ 2.3 $ -- $ --
Prices based on models and other valuation
methods 40.3 14.9 22.4 3.0 --
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Total Assets $ 66.3 $ 38.6 $ 24.7 $ 3.0 $ --
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Liabilities:
Prices actively quoted $ 10.0 $ 7.9 $ 2.1 $ -- $ --
Prices based on models and other valuation
methods 133.9 10.2 18.3 11.4 94.0
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Total Liabilities $ 143.9 $ 18.1 $ 20.4 $ 11.4 $ 94.0
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Grand Total $ (77.6) $ 20.5 $ 4.3 $ (8.4) $ (94.0)
- ------------------------------------------------- ----------- ----------- ----------- ----------- -----------
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.
Energy Trading Derivative Financial Instruments
- -----------------------------------------------
On September 1, 2000, EME acquired the trading operations of Citizens Power LLC and, subsequently, combined them
with its trading and risk management operations, now conducted by its subsidiary, Edison Mission Marketing &
Trading, Inc. As a result of a number of industry and credit related factors, EME has minimized its trading
activities and its price risk management activities with third parties not related to its power plants or
investments in energy projects. See Industry Developments Related to EME. To the extent EME engages in trading
activities, it seeks to manage price risk and creates 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. EME generally balances forward sales and purchases
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 June 30, 2002, and December 31, 2001, which include energy commodities, are set forth
below:
June 30, 2002 December 31, 2001
In millions Assets Liabilities Assets Liabilities
-------------------------------------------------------------------------------
Forward contracts $ 115.5 $ 25.8 $ 4.6 $ 2.9
Futures contracts -- 0.1 0.1 0.1
Option contracts 0.8 0.2 -- --
Swap agreements 10.5 4.8 0.2 --
-------------------------------------------------------------------------------
Total $ 126.8 $ 30.9 $ 4.9 $ 3.0
-------------------------------------------------------------------------------
Page 48
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 EME's energy trading assets and liabilities (as of June 30, 2002):
Total Maturity Maturity Maturity Maturity
Fair Less than 1 to 3 4 to 5 Greater than
In millions Value 1 year years years 5 years
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
Assets:
Prices actively quoted $ 13.9 $ 13.9 $ -- $ -- $ --
Prices based on models and other
valuation methods 115.4 4.3 7.7 10.2 93.2
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
Total Assets $ 129.3 $ 18.2 $ 7.7 $ 10.2 $ 93.2
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
Liabilities:
Prices actively quoted $ 11.3 $ 11.3 $ -- $ -- $ --
Prices based on models and other
valuation methods 22.1 6.9 4.3 3.7 7.2
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
Total Liabilities $ 33.4 $ 18.2 $ 4.3 $ 3.7 $ 7.2
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
Grand Total $ 95.9 $ -- $ 3.4 $ 6.5 $ 86.0
- ----------------------------------------------- ------------ ----------- ----------- ------------ -----------
The net realized and unrealized gains or losses arising from energy trading activities for the three and six
month periods ended June 30, 2002, and 2001 are as follows (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
- -----------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- -----------------------------------------------------------------------------------
Operating Revenue
Forward contracts $ 2.6 $ 7.2 $ 20.2 $ 1.6
Futures contracts (0.4) (0.4) (0.6) (1.9)
Option contracts (0.1) (0.3) (0.5) 2.9
Swap agreements 4.4 -- 3.9 (0.2)
- -----------------------------------------------------------------------------------
Total $ 6.5 $ 6.5 $ 23.0 $ 2.4
- -----------------------------------------------------------------------------------
The unrealized gain (loss) from energy trading activities included in the above amount were $(100,000) and
$11 million for the three- and six-month periods ended June 30, 2002, and $(100,000) and $(17) million for the
three- and six-month periods ended June 30, 2001.
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 predict any adverse impact that may 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.
Page 49
OFF-BALANCE SHEET TRANSACTIONS
Sale-Leaseback Transactions
On August 9, 2002, EME 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). This transaction represents the
only synthetic lease that EME had outstanding at June 30, 2002. The exercise of the purchase option resulted in
the payment of $300 million to the owner-lessor, of which EME received $255 million as repayment of the note
receivable held by EME. Accordingly, the net cash outlay required to exercise the purchase option was
$45 million. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated
useful life.
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 $32.5 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 six months of 2002.
During the second quarter of 2002, EME completed its evaluation of bids submitted by third parties to purchase
its interests in the EcoElectrica and Brooklyn Navy Yard projects. A number of independent power producers have
announced plans to sell assets which, together with general market conditions affecting independent power
producers during the past year, have adversely affected the market value of power plants. Based on EME's
assessment that the net present value of future cash flows from these projects were higher than purchase prices
offered, EME has decided to maintain its ownership interests and not sell these projects at this time. EME
continues to discuss the possible sale of its interest in the Gordonsville project, although there is no
assurance that EME will be able to do so.
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 are pursuing an appeal 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 the matter is now under
submission. A decision could be issued at any time. SCE cannot predict the outcome of the appeal or the impact
that any outcome would have upon the stipulated judgment. Possible outcomes could include affirmance, a return
to the district court, a referral of a controlling state law question to the California Supreme Court, or
reversal of the stipulated judgment. SCE cannot predict whether or how a ruling on the stipulated judgment could
also affect the settlement agreement.
In addition, 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. Other provisions of the settlement agreement are described in the CPUC Litigation Settlement Agreement
(pages 31 and 32) disclosure in the year-end 2001 MD&A.
Page 50
In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition for
writ of mandamus in the California Supreme Court against the CPUC. The FTCR's petition asserts that the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE, and that the CPUC further intends to exceed its authority and violate state law in proposing and consenting
to a bankruptcy reorganization plan for Pacific Gas and Electric Company (PG&E). The petition seeks 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 petition also seeks an injunction against the
CPUC's expenditure of taxpayer funds in proposing or consenting to a PG&E bankruptcy reorganization plan that
violates state law. The FTCR's petition expressly states that it does 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 does 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.
The CPUC filed its response to the petition on July 12, 2002, and the FTCR submitted its reply brief on July 19,
2002. The matter is currently pending before the California Supreme Court. SCE cannot predict the outcome of
this matter or whether the FTCR will attempt in this or other proceedings to prevent the CPUC from continuing to
perform its obligations under the settlement agreement.
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 $1.6 billion at June 30, 2002. The June 30, 2002, balance includes a second
quarter 2002 decrease of $256 million to reflect the implementation of the URG decision described below.
Currently, SCE projects that it will recover the remaining balance of the procurement-related obligations in the
PROACT by late 2003. Material factors that would change SCE's estimate of the timing of PROACT recovery are:
o level of output of SCE's generating plants and contract power delivers (for example, higher than
forecasted output accelerates PROACT recovery);
o authorized revenue changes for distribution, transmission, and SCE retained-generation costs (see
discussion in URG Decision, Generation Procurement Proceeding, PBR Decision and CPUC GRC Proceeding);
o SCE's share of the CDWR revenue requirement (see discussion in CDWR Revenue Requirement Proceeding);
o disposition of 1/2(cent) temporary surcharge (see discussion in Temporary Surcharge);
o level of retail sales (for example, higher than forecasted sales would accelerate PROACT recovery);
o level of direct access (see Direct Access discussions regarding the historical procurement charge and
exit fees 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); and
o potential energy supplier refunds (see discussion in Wholesale Electricity Markets).
Page 51
The following is an update on various regulatory proceedings impacting the timing of PROACT recovery:
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. 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. 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 amount is to be collected from direct access customers by reducing
the existing generation credit given by 2.7(cent)per kWh. This credit reduction will be utilized to reduce the new
regulatory asset balance until the CPUC issues 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 new regulatory asset balance will 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. SCE had requested that direct access customers be responsible for $540
million of its past power procurement costs and will request the CPUC to modify its interim decision
accordingly. Once the interim decision becomes permanent, SCE expects to reduce the PROACT balance and create a
new regulatory asset. The net effect of this action will accelerate the timing of PROACT recovery.
Direct Access - Exit Fees. The CPUC allocated the CDWR's costs of power purchases among the California utilities
and each utility's customers. However, the CPUC deferred a decision on the responsibility of direct access
customers to pay a portion of the CDWR's costs. On June 6, 2002, parties submitted proposals to the CPUC
regarding the appropriate charges to these customers and methods for assessing those charges. Rebuttal testimony
has been filed and evidentiary hearings have been held. One of the issues in this case is the level of cap
placed on total direct access surcharges (including the Historical Procurement Charge). If the CPUC maintains
that cap at the same 2.7(cent)per kWh, discussed above, total annual revenue is expected to increase by about $320
million. About $120 million of this amount will be contributed to the recovery of the new regulatory asset
(credited to the PROACT) and the remaining approximately $200 million will go toward paying direct access
customers' responsibility for the CDWR's costs. Amounts contributed by direct access customers to recover the
CDWR's costs will result in a reduction of the CDWR's revenue requirement to be paid by SCE's bundled service
customers, increasing the amount of revenue applied to the PROACT balance, thus expediting the recovery of the
PROACT balance.
CDWR Revenue Requirement Proceeding
- -----------------------------------
In accordance with an agreement SCE and the CDWR executed on February 28, 2002, SCE paid the CDWR for previously
delivered imbalance energy (plus interest) in three installments ($100 million on April 1, 2002; $150 million on
June 3, 2002; and the balance of $120 million on July 1, 2002). In a decision dated March 21, 2002, the CPUC
approved the February 28 agreement between SCE and the CDWR.
On June 14, 2002, the CDWR issued an updated revenue requirement of $5.5 billion for calendar year 2003, for its
bond costs and power procurement costs. Comments on the updated revenue requirement were submitted to the CDWR
on July 16, 2002. Based on some or all of those comments, the CDWR is expected to revise its updated revenue
requirement and file it with the CPUC in the third quarter of 2002. The CPUC will then determine how the updated
revenue requirement will be allocated among the customers of the California electric utilities. Based on the
2003 CDWR revenue requirement filing, SCE's
Page 52
share of the CDWR's revenue requirement for 2003 could increase by as much as $400 million, assuming the same
allocation percentage used by the CPUC in 2001 and 2002. On August 9, 2002, the CDWR issued a Notice of
Significant Additional Material Relied Upon in Proposed Determination of a Revenue Requirement. It appears from
the information referenced in this notice that the CDWR could adopt a revenue requirement as high as $5.8 billion
for calendar year 2003, in which case SCE's share would likely be higher then the $400 million discussed above.
The CDWR revenue requirement is likely to be adjusted for undercollections or overcollections in 2001-2002. At
this time, SCE is unable to predict what effect, if any, the 2003 CDWR revenue requirement will have on the
timing of PROACT recovery.
Temporary Surcharge
- -------------------
As discussed in Operating Revenue, the CPUC allowed the continuation of the 1/2(cent) 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 be reported as an increase to
revenue and cash by as much as $200 million for the remainder of 2002 and $350 million in 2003, but will have no
impact on earnings. SCE assumes this increased revenue will be used to offset the CDWR's higher revenue
requirement, and has incorporated that assumption in 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 through the end of 2002. Ratemaking for SCE's utility-retained
generation after 2002 will be determined through 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;
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 7.37% 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.
Page 53
Generation Procurement Proceeding
- ---------------------------------
In October 2001, the CPUC directed 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. In its responses to the order, SCE stated, among other things, that any CPUC-approved
procurement framework must include 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. SCE also emphasized the necessity of regaining an investment-grade credit rating before
it resumes purchasing power for customers. Without an investment-grade credit rating, SCE would experience
difficulty in obtaining financing and entering into long-term power contracts to mitigate commodity price risks.
SCE also asked the CPUC to approve an interim procedure for SCE to enter into contracts jointly with the CDWR
primarily for early procurement of capacity. By joining with the CDWR (which counterparties are willing to enter
into long-term contracts with), SCE could obtain long-term contracts before the CDWR's power contracting
authority expires on December 31, 2002, and in advance of SCE regaining an investment-grade credit rating.
CPUC also is addressing the issue of allocating among the three major California utilities the energy that will
be provided under contracts already entered into by the CDWR. This allocation will affect SCE's residual net
short (i.e., the amount of energy SCE must procure for its customers from sources other than its own generating
plants and power purchase contracts, as well as, energy allocated to SCE's customers from the CDWR contracts).
The allocation may impact the timing of the PROACT balance recovery or require a rate increase to ensure SCE is
fully recovering its procurement costs.
On July 3, 2002, the California Legislature unanimously passed as an urgency measure Assembly Bill (AB) 57, which
states an intent for SCE and the other California utilities to resume procuring power for their customers by
January 1, 2003. The bill, which has not yet been delivered to the Governor for his signature, provides that a
procurement plan approved for a utility by the CPUC shall, 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. The
bill states 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.
The bill calls for the CPUC to make an allocation of electricity provided under the CDWR contracts among the
utilities, and for the utilities to submit a procurement plan within 60 days thereafter. After the CPUC approves
a procurement plan, the bill requires the CPUC to allow at least 90 days before the utilities resume
procurement. The bill permits bilateral contracting and other hedging activities. SCE believes that the bill,
if signed into law, would provide a framework under which SCE's credit rating can be restored and would set forth
the criteria for a fully functional procurement and ratemaking plan.
If SCE were required to resume power procurement before it has an investment-grade credit rating, the cash
requirements could have an adverse effect on SCE's liquidity. SCE is unable to predict what effect the
generation procurement proceeding or AB 57, if signed by the Governor and enacted into law, will have on the
currently projected timing of PROACT recovery.
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
Page 54
extend Mohave's operation beyond 2005. Since the passage of a legislative bill, which prevented completion of a
pending sale of SCE's share of Mohave, 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 negotiate to resolve the coal supply and slurry-water issues. If those issues are
satisfactorily resolved by the end of 2002, SCE's application states that 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 this 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 if the outstanding coal and
slurry-water issues are sufficiently resolved by year-end 2002; or b) authority for SCE to establish certain
balancing accounts and otherwise begin preparing to not extend Mohave's coal-fired operations at the end of 2005.
Several parties filed protests or responses to SCE's application on July 1, 2002. 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 outcome of SCE's application is not expected to impact Mohave's operation through 2005. Consequently, SCE
does not expect this matter to have a material impact on the PROACT balance or the timing its 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 under or overcollections resulting from changes in retail rates. A balancing
account will be established to record any under or overcollections. This is retroactively effective as
of June 14, 2001.
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 revenue requirement by the
change in the Consumer Price Index minus a productivity factor of 1.6%, and (c) annually increases SCE's
distribution 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 expects its earnings for 2002 to increase by approximately $145 million.
During the second quarter of 2002, SCE recorded credits to earnings of approximately $26 million for revenue
undercollections during the period June 14, 2001, through December 31, 2001, and $23 million and $32 million for
revenue undercollections for the first and second quarters of 2002, respectively. SCE projects additional
credits to earnings for revenue undercollections of approximately $64 million during the
Page 55
remaining six months 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 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. Hearings are now scheduled to begin in the fourth quarter of 2002. A final
decision is expected in mid-2003.
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 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 2002 and further hearings are scheduled in August 2002. SCE cannot
predict 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. The FERC did not set a specific expiration date for its new market mitigation
plan. SCE cannot predict 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
the 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. SCE and Edison
International intend to challenge the CPUC decision on the first priority condition (and Edison International
intends to challenge the CPUC decision on the jurisdictional matter) and are evaluating the timing and manner of
doing so. Edison International cannot predict what effects this investigation or any subsequent actions by the
CPUC may have on Edison International or any of its subsidiaries.
Page 56
OTHER MATTERS
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,
setting the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as
a monthly restructuring 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 is continuing 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 May 2002, as well as the restructure
settlement payments due for those months, 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 due 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 $514 million at June 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. The outcome of these negotiations is uncertain at the present time. However, EME believes that it
will ultimately recover its investment in the project.
Environmental Remediation
Edison International's projected environmental capital expenditures are $2.3 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
Page 57
December 31, 2001, to reflect the results from SCE's annual environmental cost study for 2001 completed in April
2002.
Changes in EME's projected environmental capital expenditures for its Illinois plants are further discussed in
the EME Subsidiary Financing Plans discussion in the Financial Condition section of this MD&A.
Long-Term Incentive Plans
For a detailed description of Edison International's long-term incentive plans, see the Long-Term Incentive Plans
disclosure in Note 9-Employee Compensation and Benefit Plans 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 six months ended June 30, 2002, would have been reduced by approximately $300,000 and earnings
for fiscal year 2002 would be reduced by approximately $2 million, based on a Black-Scholes option-pricing model.
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 penetrations was
conducted. The reactor vessel head nozzle penetrations have 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 Internal Revenue Service (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
Edison International is studying the impact of the new Asset Retirement Obligations standard to be implemented in
2003, and is unable to predict at this time the impact on its financial statements.
Edison International implemented the new Goodwill and Other Intangibles standard on January 1, 2002. Pursuant to
this standard, no goodwill amortization expense was recorded during 2002. Goodwill amortization expense, net of
tax, for the three and six months ended June 30, 2001, was $2 million and $4 million, respectively. The standard
requires that goodwill should be tested for impairment using a two-step approach. The first step used to
identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including
goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the
impairment test is performed to measure the amount of the impairment loss. The second step of the impairment
test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal
to the excess carrying amount of the goodwill over the implied fair value. The majority of Edison
International's goodwill is recorded at EME. EME's recorded goodwill at December 31, 2001 was $632 million,
comprised of $360 million related to its Contact Energy acquisitions, $247 million related to its First Hydro
acquisition and $25 million related to its Citizens Power LLC acquisition. EME completed the first step
described above for each of the components of its goodwill. The fair value of the reporting units for the Contact
Energy and First Hydro operations were in excess of related book value at January 1, 2002. Accordingly, no
impairment of the goodwill related to
Page 58
these reporting units will be recorded upon adoption of this standard. EME concluded that fair value of the
reporting unit related to the Citizens Power acquisition was less than its book value and, accordingly, the
goodwill related to this reporting unit is impaired at January 1, 2002. EME is in the process of completing the
second step of the impairment test described above, which will be completed by December 31, 2002.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates,
believes, and other similar expressions are intended to identify forward-looking information that involves risks
and uncertainties. Actual results or outcomes could differ materially 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 or ballot initiatives, 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 and natural gas cause in operating costs,
which could affect the timing of SCE's 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 and Edison Capital to regain,
and EME and its subsidiaries to retain, 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;
o the effects of increased competition in energy-related businesses, including the market entrants and the
effects of new technologies that may be developed in the future;
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;
Page 59
o new or increased environmental liabilities; and
o weather conditions, natural disasters, and other unforeseen events.
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, on pages 38 through 49 incorporated herein by reference to General
Instruction D (1).
Page 60
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), 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 of 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. The CPUC and CEOB have not yet indicated whether they intend to appeal the
dismissal.
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
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), 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.
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. On August 2, 2002, the court ordered that discovery be completed by
mid-August 2002 and that the parties file dispositive motions on or before September 20, 2002. After ruling on
the dispositive motions, the court plans to set a trial date.
Page 61
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
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 to appeal this decision. Paiton Energy intends to contest the appeal.
BHP Fuel Supply Agreement Arbitration
PT Batu Hitam Perkasa (BHP), one of EME's partners in Paiton Energy, has informed Paiton Energy that it intends
to reactivate a pending arbitration to resolve disputes under the fuel supply agreement between BHP and Paiton
Energy. The arbitration has 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 has not specified the
amount of damages, or other relief, it seeks to recover. Paiton Energy intends to contest the arbitration.
Southern California Edison Company
San Onofre Personal Injury 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, SCE was actively involved in four lawsuits claiming personal injuries
allegedly resulting from exposure to radiation at San Onofre. In addition, SCE was previously involved, along
with other defendants, in two earlier cases raising similar allegations. Plaintiffs in five of the cases had
reached an agreement with SCE to stay all proceedings in those matters, including trial, pending the results of
the November 17, 1995, case that was then before the Ninth Circuit Court of Appeals. The parties agreed that if
the plaintiffs in the November 17, 1995, lawsuit did not receive a favorable determination on their appeal, then
the five other lawsuits would be dismissed. If, however, the plaintiffs in the November 17, 1995, lawsuit
received a favorable determination on appeal, the other matters would proceed.
On May 20, 2002, the United States Supreme Court denied plaintiffs' petition for a writ of certiorari in the
November 17, 1995, lawsuit. Plaintiffs' time to seek rehearing of that denial expired on June 14, 2002. Because
the plaintiffs in the November 1995 lawsuit did not receive a favorable determination, the remaining five cases
have been dismissed with prejudice.
Navajo Nation Litigation
As previously reported in Part I, Item 3 of Edison International's 2001 Form 10-K, 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
Page 62
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.
On February 21, 2002, Peabody filed a demand to arbitrate in United States District Court in Arizona (Arizona
District Court) pursuant to a provision of their agreement with the Navajo Nation. At the same time, Peabody and
SCE filed cross claims against the Navajo Nation in the D.C. District Court action, alleging that the Navajo
Nation had breached a prior settlement agreement and award between Peabody and the Navajo Nation by filing their
lawsuit. Additionally, Peabody and SCE filed a motion to transfer the action to the Arizona District Court or to
stay the D.C. District Court action pending the outcome of arbitration-related proceedings. This motion was made
in conjunction with Peabody's seeking the order in the Arizona District Court for arbitration. The D.C. District
Court denied Peabody's and SCE's motion to transfer the action to Arizona, or to stay the action pending the
outcome of the Arizona District Court arbitration-related proceedings. Peabody and SCE have appealed this
ruling.
Peabody has filed a motion for summary judgment in the Arizona District Court proceeding, seeking an order that
some of the claims asserted by the Navajo Nation in the D.C. District Court action over royalty rates on coal
leases were resolved in a prior settlement and award between Peabody and the Navajo Nation. Alternatively,
Peabody seeks an order requiring the Navajo Nation to arbitrate the claims that are the subject of the D.C.
District Court action in Arizona. The Navajo Nation has moved to dismiss the Arizona District Court action or,
alternatively, to have the matter transferred and consolidated with the D.C. District Court action.
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, 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
(Payment Suspension Period). 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 Inland Paperboard and Packaging, Inc. (Inland): SCE opposes Inland's claims. SCE has filed a motion
for summary judgment addressing several of Inland's claims. A hearing on this motion took place on August
6, 2002. The motion was not resolved at that time and a further hearing has been set for August 20, 2002.
Trial had been set for August 6, 2002, although the trial date has been vacated due to the filing of the
foregoing summary judgment motion.
o Cabazon Power Partners: Although previously stayed, the matter has been reactivated. Trial was
originally set to occur on October 2, 2002, but that trial date has been vacated and a new date is expected
to be set by the court.
o Watson Cogeneration Co., Midway-Sunset Cogeneration Company, U.S. Borax, Inc. (Borax), NP Cogen, Inc.
(NP Cogen), and Black Hills Ontario, LLC: The CPUC approved the application for
Page 63
approval of the settlement agreement in the N.P. Cogen action and the lawsuit has been dismissed. In the
Borax case, in exchange for payments received, plaintiff has agreed to release its nonpayment-related claims
against SCE after receiving a March 1 payment from SCE. The Borax lawsuit has also been dismissed. SCE has
sought Commission approval of various aspects of the Watson, Midway-Sunset and Black Hills agreements. The
Commission has not yet ruled on SCE's application.
o Salton Sea Power Generation, LP, IMC Chemicals, Inc. and Luz Solar Partners, Ltd. III: These QFs have
been paid amounts owing under their settlement agreements with SCE. The remaining outstanding issues have
now been resolved and these parties have filed requests for dismissal of their lawsuits.
Page 64
Item 4. Submission of Matters to a Vote of Security Holders
At Edison International's Annual Meeting of Shareholders on May 14, 2002, shareholders elected eleven nominees to
the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for
and withheld from each Director-nominee were as follows:
Number of Votes
-----------------------------------
Name For Withheld
-----------------------------------
John E. Bryson 272,793,544 7,317,051
Bradford M. Freeman 273,675,885 6,434,710
Joan C. Hanley 273,498,212 6,612,383
Bruce Karatz 273,591,712 6,518,883
Luis G. Nogales 273,547,668 6,562,927
Ronald L. Olson 270,696,260 9,414,335
James M. Rosser 273,546,815 6,563,780
Richard T. Schlosberg, III 273,585,825 6,524,770
Robert H. Smith 272,205,561 7,905,034
Thomas C. Sutton 272,335,829 7,774,766
Daniel M. Tellep 273,455,646 6,654,949
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 7, 1998
(File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior participating Cumulative Preferred Stock of
Edison International dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on January 1, 2002
(File No. 1-9936, Form 10-K for year ended December 31, 2001)*
10.1 Director Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan
10.2 Director Deferred Compensation Plan as amended May 14, 2002
10.3 Executive Grantor Trust Agreement Amendment 2002-1
10.4 Director Grantor Trust Agreement Amendment 2002-1
11 Computation of Primary and Fully Diluted Earnings per Share
99.1 Edison Mission Energy Distribution Summary for the years ended December 31, 2001 and 2000 (File
No. 1-13434, filed as Exhibit 99.1 to the Edison Mission Energy Form 10-Q for the quarter ended
June 30, 2002)*
99.2 Homer City Facilities Funds Flow From Operations for the twelve months ended June 30, 2002
(File No. 1-13434, filed as Exhibit 99.2 to the Edison Mission Energy Form 10-Q for the quarter
ended June 30, 2002)*
Page 65
99.3 Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2001
(File No. 1-13434, filed as Exhibit 99.3 to the Edison Mission Energy Form 10-Q for the quarter
ended June 30, 2002)*
99.4 Illinois Plants Funds Flow From Operations for the twelve months ended June 30, 2002 (File No.
1-13434, filed as Exhibit 99.4 to the Edison Mission Energy Form 10-Q for the quarter ended
June 30, 2002)*
99.5 Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2001 (File
No. 1-13434, filed as Exhibit 99.5 to the Edison Mission Energy Form 10-Q for the quarter ended
June 30, 2002)*
99.6 Statement Pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 8, 2002 May 10, 2002 4 and 7
- ----------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 66
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
August 14, 2002
Page 67