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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 999)
Rosemead, California 91770
(Address of principal 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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes |X|
No |_|
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class Outstanding at November 10, 2003
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Common Stock, no par value 325,811,206
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EDISON INTERNATIONAL
INDEX
Page
No.
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Part I.Financial Information:
Item 1. Financial Statements:
Consolidated Statements of Income - Three and Nine Months
Ended September 30, 2003 and 2002 1
Consolidated Balance Sheets - September 30, 2003
and December 31, 2002 2
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2003 and 2002 4
Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2003 and 2002 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 27
Item 3. Quantitative and Qualitative Disclosures About Market Risk 91
Item 4. Controls and Procedures 91
Part II. Other Information:
Item 1. Legal Proceedings 92
Item 6. Exhibits and Reports on Form 8-K 94
Signatures
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions, except per-share amounts 2003 2002 2003 2002
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(Unaudited)
Electric utility $ 2,794 $ 2,713 $ 6,994 $ 6,754
Nonutility power generation 1,014 954 2,412 2,164
Financial services and other 25 39 73 102
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Total operating revenue 3,833 3,706 9,479 9,020
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Fuel 386 354 1,013 890
Purchased power 1,013 780 2,187 1,615
Provisions for regulatory adjustment clauses - net 332 738 1,141 1,052
Other operation and maintenance 842 759 2,450 2,298
Asset impairment -- 86 251 86
Depreciation, decommissioning and amortization 286 256 826 759
Property and other taxes 54 35 156 110
Net gain on sale of utility plant (5) (6) (5) (6)
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Total operating expenses 2,908 3,002 8,019 6,804
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Operating income 925 704 1,460 2,216
Interest and dividend income 21 48 114 226
Equity in income from partnerships and
unconsolidated subsidiaries - net 158 113 278 207
Other nonoperating income 19 8 73 32
Interest expense - net of amounts capitalized (315) (306) (904) (981)
Other nonoperating deductions (20) (19) (72) (52)
Dividends on preferred securities
subject to mandatory redemption -- (27) (56) (83)
Dividends on utility preferred stock
not subject to mandatory redemption (1) (1) (4) (4)
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Income from continuing operations before tax 787 520 889 1,561
Income tax 287 175 304 482
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Income from continuing operations 500 345 585 1,079
Income from discontinued operations - net of tax 44 7 48 22
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Income before accounting change 544 352 633 1,101
Cumulative effect of accounting change - net of tax -- -- (9) --
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Net income $ 544 $ 352 $ 624 $ 1,101
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Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings per share:
Continuing operations $ 1.53 $ 1.06 $ 1.80 $ 3.31
Discontinued operations 0.14 0.02 0.15 0.07
Cumulative effect of accounting change -- -- (0.03) --
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Total $ 1.67 $ 1.08 $ 1.92 $ 3.38
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Weighted-average shares, including
effect of dilutive securities 330 329 330 329
Diluted earnings per share:
Continuing operations $ 1.52 $ 1.05 $ 1.77 $ 3.28
Discontinued operations 0.13 0.02 0.15 0.07
Cumulative effect of accounting change -- -- (0.03) --
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Total $ 1.65 $ 1.07 $ 1.89 $ 3.35
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Dividends declared per common share -- -- -- --
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions 2003 2002
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(Unaudited)
ASSETS
Cash and equivalents $ 3,246 $ 2,468
Restricted cash 67 53
Receivables, less allowances of $34 and $49 for uncollectible
accounts at respective dates 1,270 1,111
Accrued unbilled revenue 547 437
Fuel inventory 95 124
Materials and supplies, at average cost 236 219
Accumulated deferred income taxes - net 140 270
Trading and price risk management assets 90 34
Regulatory assets - net -- 509
Prepayments and other current assets 216 227
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Total current assets 5,907 5,452
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Nonutility property - less accumulated provision for
depreciation of $1,159 and $911 at respective dates 7,165 6,873
Nuclear decommissioning trusts 2,369 2,210
Investments in partnerships and unconsolidated subsidiaries 2,042 2,011
Investments in leveraged leases 2,360 2,313
Other investments 308 235
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Total investments and other assets 14,244 13,642
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Utility plant, at original cost:
Transmission and distribution 14,602 14,202
Generation 1,362 1,348
Accumulated provision for depreciation and decommissioning (6,148) (7,990)
Construction work in progress 589 529
Nuclear fuel, at amortized cost 130 153
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Total utility plant 10,535 8,242
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Goodwill 788 661
Restricted cash 240 406
Regulatory assets - net 2,971 3,838
Other deferred charges 925 920
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Total deferred charges 4,924 5,825
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Assets of discontinued operations 12 123
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Total assets $ 35,622 $ 33,284
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The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions, except share amounts 2003 2002
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ -- $ 78
Long-term debt due within one year 2,347 2,761
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,044 866
Accrued taxes 998 855
Trading and price risk management liabilities 131 45
Regulatory liabilities - net 322 --
Other current liabilities 2,082 2,040
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Total current liabilities 6,933 6,654
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Long-term debt 11,370 11,557
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Accumulated deferred income taxes - net 5,759 5,842
Accumulated deferred investment tax credits 161 167
Customer advances and other deferred credits 1,323 1,841
Power-purchase contracts 230 309
Company-obligated mandatorily redeemable securities of subsidiaries
holding solely parent company debentures 951 --
Other preferred securities subject to mandatory redemption 289 --
Accumulated provision for pensions and benefits 501 461
Asset retirement obligations 2,098 --
Other long-term liabilities 172 161
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Total deferred credits and other liabilities 11,484 8,781
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Liabilities of discontinued operations 13 72
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Total liabilities 29,800 27,064
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Commitments and contingencies (Notes 2 and 4)
Minority interest 480 425
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Preferred stock of utility:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption -- 147
Company-obligated mandatorily redeemable securities of subsidiaries
holding solely parent company debentures -- 951
Other preferred securities -- 131
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Total preferred securities of subsidiaries 129 1,358
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Common stock (325,811,206 shares outstanding at each date) 1,982 1,973
Accumulated other comprehensive loss (104) (247)
Retained earnings 3,335 2,711
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Total common shareholders' equity 5,213 4,437
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Total liabilities and shareholders' equity $ 35,622 $ 33,284
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The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2003 2002 2003 2002
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(Unaudited)
Net income $ 544 $ 352 $ 624 $1,101
Other comprehensive income, net of tax:
Foreign currency translation adjustments - net 7 (8) 70 71
Unrealized gain (loss) on investments - net 4 (1) 2 (8)
Cumulative effect of change in accounting
for derivatives -- -- -- 6
Unrealized gain (loss) on cash flow hedges - net 53 (69) 76 (42)
Reclassification adjustment for gain (loss)
included in net income 1 2 (5) 5
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Comprehensive income $ 609 $ 276 $ 767 $1,133
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The accompanying notes are an integral part of these financial statements.
Page 4
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS Nine Months Ended
September 30,
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In millions 2003 2002
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 576 $ 1,079
Adjustments to reconcile to net cash provided
by operating activities:
Depreciation, decommissioning and amortization 826 759
Other amortization 81 83
Deferred income taxes and investment tax credits (11) 191
Equity in income from partnerships and unconsolidated subsidiaries (278) (207)
Income from leveraged leases (62) (83)
Regulatory assets - long-term - net 414 1,003
Gas options 62 12
Power contracts collateral (76) --
Asset impairment 251 --
Levelized rent expense (96) (95)
Other assets 74 143
Other liabilities (259) 156
Changes in working capital:
Receivables and accrued unbilled revenue (219) (285)
Regulatory assets - short-term - net 792 70
Fuel inventory, materials and supplies (5) (6)
Prepayments and other current assets (29) (112)
Accrued interest and taxes 219 769
Accounts payable and other current liabilities 318 (2,470)
Distributions and dividends from unconsolidated entities 315 262
Operating cash flows from discontinued operations (52) 83
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Net cash provided by operating activities 2,841 1,352
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Cash flows from financing activities:
Long-term debt issued 214 321
Long-term debt repaid (1,005) (1,522)
Bonds remarketed and funds held in trust -- 191
Redemption of preferred securities (6) (100)
Rate reduction notes repaid (176) (176)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net 5 (721)
Dividends to minority shareholders (10) --
Financing cash flows from discontinued operations -- (14)
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Net cash used by financing activities (978) (2,080)
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Cash flows from investing activities:
Additions to property and plant (924) (1,200)
Purchase of power sales agreement -- (80)
Purchase of common stock of acquired companies (275) --
Proceeds from sale of property 6 59
Net funding of nuclear decommissioning trusts (16) 1
Distributions from (investments in) partnerships and
unconsolidated subsidiaries (59) 81
Sales of investments in other assets 25 352
Investing cash flows from discontinued operations 152 2
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Net cash used by investing activities (1,091) (785)
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Effect of exchange rate changes on cash 7 10
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Net increase (decrease) in cash and equivalents 779 (1,503)
Cash and equivalents, beginning of period 2,468 4,055
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Cash and equivalents, end of period 3,247 2,552
Cash and equivalents, discontinued operations (1) (36)
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Cash and equivalents, continuing operations $ 3,246 $ 2,516
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The accompanying notes are an integral part of these financial statements.
Page 5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are 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. The results of operations for the period ended September 30,
2003 are not necessarily indicative of the operating results for the full year.
The quarterly report should be read in conjunction with Edison International's Annual Report on Form 10-K for the year ended December
31, 2002 filed with the Securities and Exchange Commission.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2002 Annual Report. Edison International follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the September 30, 2003 financial statement presentation.
Earnings (Loss) Per Share (EPS)
Basic EPS is computed by dividing net income (loss) by the weighted-average number of common shares outstanding. In arriving at net
income (loss), dividends on preferred securities and preferred stock have been deducted. For the diluted EPS calculation, dilutive
securities (employee stock options) are added to the weighted-average shares. Due to their antidilutive effect, dilutive securities
are excluded from the diluted EPS calculation if the numerator is negative.
New Accounting Principles
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) 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. However, rate-regulated entities may recognize regulatory assets or
liabilities as a result of timing differences between the recognition of costs in accordance with this standard and the recovery of
costs through the rate-making process. Regulatory assets and liabilities may also be recorded if it is probable that the ARO will be
recovered through the rate-making process.
Edison International's impact of adopting this standard was:
o Southern California Edison (SCE) adjusted its nuclear decommissioning obligation to reflect the fair value of
decommissioning its nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and $12 million to decommission
its share of a coal-fired generating plant, under accounting principles in effect at that time. Of these amounts, $298 million
to decommission its inactive nuclear facility was recorded in other long-term liabilities, and the remaining $2.0 billion was
recorded as a component of the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in
the 2002 Annual Report.
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning, recorded the fair value
of its AROs of approximately $2.0 billion in the deferred credits and other liabilities section of the balance sheet, and
increased its unamortized nuclear investment by $303 million. The cumulative effect of a change in accounting principle from
unrecognized accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date was a
$354 million after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory
liability, partially offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and depreciation expense
resulting from the application of the new standard is expected to be approximately $143 million in 2003. This cost will reduce
the regulatory liability, with no impact on earnings. As of September 30, 2003, SCE's ARO for its nuclear facilities totaled
approximately $2.1 billion and its nuclear decommissioning trust assets had a fair value of $2.4 billion. If the new standard
had been in place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $2.0 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in accumulated
depreciation and decommissioning.
o As of January 1, 2003, Edison Mission Energy's (EME) ARO was $17 million and EME recorded a cumulative effect adjustment
that decreased net income by approximately $9 million, net of tax. If the new standard had been applied retroactively in the
nine months ended September 30, 2002, it would not have had a material effect on EME's results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities (VIEs). The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. This interpretation applies to VIEs
created after January 31, 2003 and beginning July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it
acquired before February 1, 2003. Effective October 9, 2003, an additional interpretation was issued which delays the effective date
for applying the provisions of the original interpretation to VIEs that were acquired before February 1, 2003. For Edison
International, the new effective date is December 31, 2003.
Under the interpretation, if an enterprise absorbs the majority of the VIE's expected losses or receives a majority of the VIE's
expected residual returns, or both, it must consolidate the VIE. An enterprise that is required to consolidate the VIE is called the
primary beneficiary. Additional disclosure requirements are also applicable when an enterprise holds a significant variable interest
in a VIE, but is not the primary beneficiary. In addition, financial statements issued after January 31, 2003 must include certain
disclosures if it is reasonably possible that an enterprise will consolidate or disclose information about a VIE when this
interpretation is effective.
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International believes it is reasonably possible that certain partnership interests in energy projects are VIEs under this
interpretation, as discussed below:
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098 MW of power plants.
The maximum exposure to loss from EME's interest in these energy partnerships is $1.1 billion at September 30, 2003. Of this amount,
$573 million represents EME's investment in the 1,230 MW Paiton project and $306 million represents EME's investment in the 540 MW
EcoElectrica project.
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another affiliated project
under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of
the obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to this
affiliated project. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot
be determined.
Edison International is in the process of reviewing the entities discussed above that have a reasonable possibility of being VIEs to
determine if it is the primary beneficiary.
In addition, Edison International is in the process of reviewing Edison Capital's partnership interests in affordable housing
projects to determine if they have a reasonable possibility of being VIEs and also to determine if Edison Capital is the primary
beneficiary.
Although Edison International will continue to evaluate the impact of adoption of this interpretation, Edison International has
concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy Yard project and Edison Capital's
Storm Lake project, since it expects to absorb the majority of these projects' losses, if any, and expects to receive the majority of
these projects' residual returns, if any. Accordingly, Edison International will consolidate these projects effective October 1,
2003. These consolidations are expected to increase total assets by approximately $451 million and total liabilities by
approximately $533 million. In addition, Edison International expects to record a loss of approximately $82 million (of which
$76 million is related to Brooklyn Navy Yard) in the fourth quarter of 2003 as a cumulative accounting change as a result of
consolidating these VIEs.
Effective July 1, 2003, Edison International adopted a new accounting standard, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities. This statement amends and clarifies financial accounting and reporting for derivative instruments and for
hedging activities under derivative instrument accounting. The amendment reflects decisions made by accounting authorities in
connection with issues raised about the application of the derivative instrument accounting standard. Generally, the provisions of
this new standard apply prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The adoption of this standard had no impact on Edison International's consolidated financial
statements.
Effective July 1, 2003, Edison International adopted a new accounting standard, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, which required issuers to classify certain freestanding financial instruments as
liabilities. These freestanding liabilities include mandatorily redeemable financial instruments, obligations to repurchase the
issuer's equity shares by transferring assets and certain obligations to issue a variable number of shares. Effective July 1, 2003,
Edison International reclassified its company-obligated mandatorily redeemable securities, its other mandatorily redeemable preferred
securities and SCE's preferred stock subject to mandatory redemption
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to the liabilities section of its consolidated balance sheet. These items were previously classified between liabilities and
equity. In addition, effective July 1, 2003, dividend payments on these instruments are included in interest expense - net of
amounts capitalized on Edison International's consolidated statements of income. Prior period financial statements are not permitted
to be restated for these changes. Therefore, upon adoption there was no cumulative impact incurred due to this accounting change.
See disclosures regarding these preferred securities in Note 3.
In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Determining Whether an Arrangement Contains a Lease, which
provides guidance on how to determine whether an arrangement contains a lease that is within the scope of the standard, Accounting
for Leases. A lease is defined as an agreement conveying the right to use property, plant, or equipment (land and/or depreciable
assets) usually for a stated period of time. The guidance issued by the EITF could affect the classification of a power sales
agreement that meets specific criteria, such as a power sales agreement for substantially all of the output from a power plant to one
customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to the
lease accounting standard. The consensus is effective prospectively for arrangements entered into or modified after June 30, 2003.
The consensus had no impact on Edison International's consolidated financial statements.
In June 2003, clarifying guidance was issued related to derivative instruments and hedging activities. The guidance is related to
pricing adjustments in contracts that qualify under the normal purchases and normal sales exception under derivative instrument
accounting. This implementation guidance became effective on October 1, 2003. As a result of this clarifying guidance, certain
contracts that did not previously qualify for the normal purchases and sales exception may now qualify. EME and SCE are currently
evaluating the impact of this guidance on their contracts.
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:
September 30, December 31,
In millions 2003 2002
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Current:
PROACT - net $ -- $ 574
Regulatory balancing accounts and other - net (322) (65)
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(322) 509
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Long-term:
Flow-through taxes - net 1,279 1,336
Rate reduction notes - transition cost deferral 1,015 1,215
Unamortized nuclear investment - net 520 630
Unamortized coal plant investment - net 69 61
Unamortized loss on reacquired debt 227 237
Environmental remediation 66 70
Asset retirement obligation (312) --
Regulatory balancing accounts and other - net 107 289
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2,971 3,838
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Total $ 2,649 $ 4,347
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SCE fully recovered the procurement-related obligations account (PROACT) balance during July 2003 and on August 1, 2003,
transferred the PROACT overcollection to a new energy resource recovery account regulatory balancing account. The new
balancing account acts as a mechanism to recover SCE's fuel costs related to its generating stations, purchased-power costs
related to cogeneration and renewable contracts, existing interutility and bilateral contracts that were entered into prior
to January 17, 2001, and new procurement-related costs that SCE began incurring on January 1, 2003, the date on which the
California Public Utilities Commission (CPUC) transferred back to SCE the responsibility for procuring energy resources for
its customers.
Stock-Based Employee Compensation
Edison International has three stock-based employee compensation plans, which are described more fully in Note 7 of "Notes to
Consolidated Financial Statements" included in its 2002 Annual Report. Edison International accounts for these plans using the
intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income, as all options granted
under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following
table illustrates the effect on net income and earnings per share if Edison International had used the fair-value accounting method.
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions, except per-share amounts 2003 2002 2003 2002
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Net income, as reported $ 544 $ 352 $ 624 $ 1,101
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 2 2 5 5
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 3 1 7 3
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Pro forma net income $ 543 $ 353 $ 622 $ 1,103
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Basic earnings per share:
As reported $ 1.67 $ 1.08 $ 1.92 $ 3.38
Pro forma $ 1.67 $ 1.08 $ 1.91 $ 3.39
Diluted earnings per share:
As reported $ 1.65 $ 1.07 $ 1.89 $ 3.35
Pro forma $ 1.65 $ 1.07 $ 1.89 $ 3.35
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Supplemental Cash Flows Information
Nine Months Ended
September 30,
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In millions 2003 2002
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Non-cash investing and financing activities:
Details of assets acquired:
Fair value of assets acquired $ (333) $ --
Liabilities assumed 58 --
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Cash paid for acquisitions $ (275) $ --
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Details of senior secured credit facility transaction:
Retirement of credit facility $ -- $ (1,650)
Senior secured credit facility replacement -- 1,600
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Cash paid on retirement of credit facility $ -- $ (50)
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Details of long-term debt exchange offer:
Variable rate notes redeemed $ (966) $ --
First and refunding bonds issued 966 --
Obligation to fund investment in acquisition $ 8 $ --
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Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources (CDWR) power purchases
and revenue requirements, generation procurement and utility-retained generation, is described in Note 2 of "Notes to Consolidated
Financial Statements" included in Edison International's 2002 Annual Report.
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CPUC Litigation Settlement Agreement
In 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 procurement-related costs. A key element of the settlement agreement was the establishment of a $3.6
billion regulatory balancing account called the PROACT as of August 31, 2001. The Utility Reform Network (TURN), a consumer advocacy
group, and other parties appealed to the United States Court of Appeals for the Ninth Circuit seeking to overturn the stipulated
judgment of the federal district court that approved the settlement agreement. On September 23, 2002, the Ninth Circuit issued its
opinion affirming the federal district court on all claims, with the exception of the challenges founded upon California state law,
which the Ninth Circuit referred to the California Supreme Court.
On August 21, 2003, the California Supreme Court issued its decision on the certified questions, concluding that the settlement
agreement did not violate California law in any of the respects raised by the Ninth Circuit. Specifically, the California Supreme
Court concluded that: the commissioners of the CPUC had the authority to propose the stipulated judgment in light of the provisions
of California's restructuring statute; the procedures employed by the CPUC in entering the stipulated judgment did not violate
California's open meeting law for public agencies; and the stipulated judgment did not violate California's public utilities code by
allegedly altering rates without a public hearing and issuance of findings.
On September 8, 2003, TURN filed a petition for rehearing of the California Supreme Court's decision. On October 22, 2003, the
California Supreme Court denied TURN's petition. The matter will now return to the Ninth Circuit for final disposition, subject to
any efforts by TURN to pursue further federal appeals. In the meantime, the case is stayed in the federal appellate court. SCE
continues to believe it is probable that recovery of its past procurement costs through regulatory mechanisms, including the PROACT,
ultimately will be validated. However, SCE cannot predict with certainty the ultimate outcome of the pending legal proceedings.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground electric line
maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection and Safety Division (CPSD), which
alleged a pattern of noncompliance with the CPUC's general orders for the maintenance of electric lines over the period 1998-2000.
The order also alleged that noncompliant conditions were involved in 37 accidents resulting in death, serious injury or property
damage. The CPSD identified 4,817 alleged violations of the general orders during the three-year period; and the order put SCE on
notice that it could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief on
October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC administrative law judge (ALJ) issued a presiding officer's decision (POD) fining SCE $576,000 for alleged
violations involving death, injury or property damage, failure to identify unsafe conditions or exceeding required inspection
intervals. The POD imposes no fines for over 98% of the alleged violations and does not find that any of the alleged violations
compromised the integrity or safety of SCE's electric system or were excessive compared to other utilities. The POD orders SCE to
consult with the CPSD and refine SCE's maintenance priority system consistent with the discussion in the POD. On July 21, 2003, SCE
filed an appeal opposing the POD's interpretation that all general order non-conformances are violations subject to potential
penalty. The CPSD also filed an appeal,
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
challenging the fact that the POD did not, in fact, penalize SCE for 4,721 of the violations alleged by the CPSD in the OII. SCE,
Pacific Gas and Electric (PG&E), San Diego Gas & Electric (SDG&E) and the California Cable and Telecommunications Association filed
responses challenging the CPSD's appeal. The CPSD filed a response objecting to the intervention and appeals of PG&E, SDG&E and the
California Cable and Telecommunications Association.
Holding Company Proceeding
In April 2001, the CPUC issued an OII that reopened the past CPUC decisions authorizing utilities to form holding companies and
initiates an investigation into, among other things: whether the holding companies violated CPUC requirements to give first priority
to the capital needs of their respective utility subsidiaries; any additional suspected violations of laws or CPUC rules and
decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary. On January 9,
2002, the CPUC issued an interim decision on the first priority condition. The decision stated that, at least under certain
circumstances, the condition includes the requirement that holding companies infuse all types of capital into their respective
utility subsidiaries when necessary to fulfill the utility's obligation to serve. The decision did not determine if any of the
utility holding companies had violated this condition, reserving such a determination for a later phase of the proceedings. On
February 11, 2002, SCE and Edison International filed an application before the CPUC for rehearing of the decision. On July 17,
2002, the CPUC affirmed its earlier decision on the first priority condition and also denied Edison International's request for a
rehearing of the CPUC's determination that it had jurisdiction over Edison International in this proceeding. On August 21, 2002,
Edison International and SCE jointly filed a petition requesting a review of the CPUC's decisions with regard to first priority
considerations, and Edison International filed a petition for a review of the CPUC decision asserting jurisdiction over holding
companies, both in state court as required. PG&E and SDG&E and their respective holding companies filed similar challenges, and all
cases have been transferred to the First District Court of Appeals in San Francisco. The CPUC filed briefs in opposition to the writ
petitions. Edison International, SCE and the other petitioners filed reply briefs on March 6, 2003. No hearings have been
scheduled. The court may rule without holding hearings. Edison International cannot predict with certainty what effects this
investigation or any subsequent actions by the CPUC may have on Edison International or any of its subsidiaries.
Mohave Generating Station Proceeding
As discussed in Note 2 of "Notes to Consolidated Financial Statements" included in Edison International's 2002 Annual Report, on May
17, 2002, SCE filed with the CPUC an application to address certain issues (mainly coal and slurry-water supply issues) facing the
future extended operation of Mohave. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave
co-owners from starting to make approximately $1.1 billion (SCE's share is $605 million) of Mohave-related investments if Mohave's
operations are to be extended past 2005. The CPUC issued a ruling on January 7, 2003 requesting further written testimony on
specified issues related to Mohave and its coal and slurry-water supply issues to determine whether it is in the public interest to
extend Mohave operations past 2005. SCE submitted supplemental testimony on January 30, 2003 stating, among other things, that the
currently available information is not sufficient for the CPUC to make such a determination at this time.
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in the proceeding,
most recently on October 29, 2003. The Navajo Nation and Hopi Tribe and the coal mining company, Peabody Western Coal Company, have
taken the position that the CPUC should,
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
among other things, require SCE to fund a study of a possible alternative water supply, and require SCE to commence a CPUC proceeding
for authorization of the Mohave pollution controls and other plant investments. Certain other parties have taken the position that
SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. Negotiations have continued among the relevant parties
in an effort to resolve the coal and water supply issues, but no resolution has been reached. On October 8, 2003, the CPUC indicated
that when the CPUC is assured that resolution of the coal and water supply issues is progressing, hearings on the costs and timelines
for all alternatives would be scheduled.
Wholesale Electricity and Gas Markets
In a consolidated proceeding related to the justness and reasonableness of rates charged by sellers in the California Power Exchange
and Independent System Operator markets as described in Note 2 of "Notes to Consolidated Financial Statements" included in Edison
International's 2002 Annual Report, the Federal Energy Regulatory Commission (FERC) issued orders in March 2003 that initiated
procedures for determining additional refunds arising from market manipulation by energy suppliers. The FERC staff report issued on
March 26, 2003 found that there was pervasive gaming and market manipulation of the electric and gas markets in California and on the
West Coast and also described many of the techniques and effects of electric and gas market manipulation. In a March 26, 2003 order,
clarified on April 22, 2003, the FERC adopted a recommendation of the FERC staff's final report to modify a FERC ALJ's initial
decision of December 12, 2002 to reflect the fact that the gas indices used in the market manipulation formula overstated the cost of
gas used to generate electricity. SCE sought rehearing of the March 26, 2003 and April 22, 2003 orders. On October 16, 2003, the
FERC issued an order on SCE's rehearing request, upholding its March 26, 2003 order. On June 25, 2003, the FERC issued two sets of
enforcement orders. The first set ordered 54 entities, including SCE, to show cause concerning gaming or anomalous market behavior
during the period January 1, 2001 to June 20, 2001. SCE has provided information to the FERC staff demonstrating that it did not
engage in gaming or anomalous market behavior, filed its response to the show cause order on September 2, 2003, and worked with the
FERC staff to resolve the issue. On November 3, 2003, the FERC staff filed a motion to dismiss the charges against SCE. The second
set of enforcement orders ordered 25 entities to show cause concerning gaming and anomalous market behavior in concert with Enron and
other entities. Under both sets of orders, the remedy for tariff violations will be the disgorgement of unjust profits and possibly
other non-monetary remedies. On June 25, 2003, the FERC also opened a new investigation into anomalous bidding behavior during the
period May 1, 2000 to October 2, 2000, focused primarily on economic withholding by bidding above $250/MWh with disgorgement of
profits as the possible penalty. Since these orders, the FERC staff has filed numerous motions to dismiss against various
respondents in the proceeding and has entered into settlements with a number of respondents. SCE and other parties subject to the
order have filed dozens of opposition pleadings. SCE cannot, at this time, determine the timing or amount of any potential refunds.
Under the settlement agreement with the CPUC, 90% of any refunds actually realized by SCE will be refunded to ratepayers. On October
20, 2003, the CPUC issued a decision on the accounting and rate-making mechanisms related to the consideration received by regulated
gas and electric utilities under a settlement with El Paso Natural Gas Company and other parties. Based on this decision, SCE will
refund to ratepayers amounts (net of legal and consulting costs) through its energy resource recovery account as they are received
from El Paso under the terms of the settlement. In addition, amounts El Paso refunds to the CDWR will result in equivalent
reductions in the CDWR's revenue requirement from SCE's ratepayers. Refunds from El Paso will not be received until the proposed
settlement is approved by the California Superior Court in San Diego County. A hearing for approval of the proposed settlement is
scheduled for November 20, 2003.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Preferred Securities Subject to Mandatory Redemption
Company-Obligated Mandatorily Redeemable Securities of Subsidiary
In November 1994, EME issued, through a limited partnership, 3.5 million shares of 9.875% cumulative monthly income preferred
securities, at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due
2024. These securities are redeemable at the option of the partnership (EME is the sole general partner), in whole or in part, with
mandatory redemption in 2024 at a redemption price of $25 per security plus accrued and unpaid distributions. In August 1995, EME
also issued, through a limited partnership, 2.5 million shares of 8.5% cumulative monthly income preferred securities, at a price of
$25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025. These securities are
redeemable at the option of the partnership, in whole or in part, with mandatory redemption in 2025 at a redemption price of $25 per
security plus accrued and unpaid distributions. EME issued a guarantee in favor of its preferred securities holders, which ensures
the payments of distributions declared on the preferred securities, payments upon liquidation of the limited partnership and payments
on redemption for securities called for redemption by the limited partnership. No securities have been redeemed as of September 30,
2003.
EME has the right from time to time to extend the interest payment period on its junior subordinated deferrable interest debentures
to a period not exceeding 60 consecutive months, at the end of which all accrued and unpaid interest will be paid in full. If EME
does not make interest payments on its junior subordinated debentures, it is expected that this limited partnership will not declare
or pay distributions on its cumulative monthly income preferred securities. During an extension period, EME may not do any of the
following:
o declare or pay any dividend on, or purchase, acquire or make a distribution or liquidation payment with respect to, any of
its common or preferred stock;
o acquire for cash or other property any indebtedness of any affiliate of EME (other than affiliates of EME which meet
specified requirements) for money borrowed; or
o make any loan or advance to, or guarantee or become contingently liable in respect of indebtedness of, any affiliate of EME
(other than affiliates of EME which meet specified requirements).
Furthermore, as long as any preferred securities remain outstanding, EME will not be able to declare or pay dividends on, or
purchase, any of its common stock if at such time it is in default on its payment obligations under the guarantee or the subordinated
indenture unless EME has given notice of the extended interest payment period described above. No securities have been redeemed as
of September 30, 2003.
In 1999, Edison International (the parent company) issued, through affiliates, $500 million of 7.875% cumulative quarterly income
preferred securities and $325 million of 8.6% cumulative quarterly income preferred securities, at a price of $25 per security. The
7.875% securities have a stated maturity of July 2029, but are redeemable at the option of Edison International, in whole or in part,
beginning July 2004. The 8.6% securities have a stated maturity of October 2029, but are redeemable at the option of Edison
International, in whole or in part, beginning October 2004. Both of these securities are guaranteed by Edison International. In
order to reduce its cash requirements, in May 2001, the parent company deferred the interest payments in accordance with the terms of
its outstanding quarterly income debt securities issued to an affiliate. This caused a corresponding deferral of distributions on
quarterly income preferred securities issued by the affiliate. Interest payments may be deferred for up to 20 consecutive quarters.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the deferral period, the principal of the debt securities and each unpaid interest installment will continue to accrue
interest at the applicable coupon rate. All interest in arrears must be paid in full at the end of the deferral period. The parent
company cannot pay dividends on or purchase its common stock while interest is being deferred.
Other Preferred Securities Subject to Mandatory Redemption
SCE has 12 million authorized shares of preferred stocks subject to mandatory redemption. All cumulative preferred stocks are
redeemable. Mandatorily redeemable preferred stocks are subject to sinking-fund provisions. When preferred shares are redeemed, the
premiums paid are charged to common equity.
SCE's preferred stock redemption requirements for the five twelve-month periods following September 30, 2003 are: 2004 - $9 million;
2005 - $9 million; 2006 - $9 million; 2007 - $9 million; and 2008 - $59 million.
SCE's cumulative preferred stocks subject to mandatory redemption consisted of:
September 30, December 31,
Dollars in millions, except per share amounts 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
September 30, 2003
---------------------------
Shares Redemption
Outstanding Price
$100 par value:
6.05% Series 693,800 $ 100.00 $ 69 $ 75
7.23 807,000 100.00 81 81
Preferred stock to be redeemed within one year (9) (9)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total $ 141 $ 147
- ---------------------------------------------------------------------------------------------------------------------------------------
In second quarter 2002, SCE redeemed 1,000,000 shares of 6.45% Series preferred stock. There were no other redemptions, and no
issuances, of preferred stock subject to mandatory redemption for the periods presented.
The 7.23% Series preferred stock has mandatory sinking funds, requiring SCE to redeem at least 50,000 shares per year from 2002
through 2006, and 750,000 shares in 2007. However, SCE is allowed to credit previously repurchased shares against the mandatory
sinking fund provisions. Since SCE had previously repurchased 193,000 shares of this series, no shares were redeemed in 2002. At
December 31, 2002, SCE had 143,000 of previously repurchased, but not retired, shares available to credit against the mandatory
sinking fund provisions.
During 2001, a subsidiary of EME issued $104 million of redeemable preferred shares (250 million shares at a price of one New Zealand
dollar per share with a dividend rate of 6.03%). The shares are redeemable in July 2006 at issuance price. At September 30, 2003,
total accumulated dividends were approximately $2 million. Optional early redemption may occur if the holders pass an extraordinary
resolution to redeem the shares if certain EME subsidiaries cease to be subsidiaries of EME or in the case of certain defaults of the
security trust deed. The security trust deed secures a limited recourse guarantee by an EME subsidiary's payment obligations to
holders of the redeemable preferred shares.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings
before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International
believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has leased three aircraft to American Airlines. Due to adverse conditions facing American Airlines, its financial
position has deteriorated significantly. The independent auditors' opinion on the year-end 2002 financial statements of AMR
Corporation, parent company of American Airlines, contains an explanatory paragraph that indicates the consolidated financial
statements have been prepared on the basis that AMR Corporation will continue as a going concern. The opinion also states that AMR
Corporation's recent history of significant losses, negative cash flows from operations, uncertainty regarding AMR Corporation's
ability to reduce it's operating costs to offset the declines in its revenue, the potential failure of AMR Corporation to satisfy the
liquidity requirements in certain of its credit agreements, and its diminishing financial resources, raise substantial doubt about
AMR Corporation's ability to continue as a going concern. If American Airlines defaults in making its lease payments, the lenders
with a security interest in the aircraft or leases may exercise remedies that could lead to a loss of some or all of Edison Capital's
investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison Capital in 2004 is $46 million. A
restructure of the lease could also result in a loss of some or all of the investment. At September 30, 2003, American Airlines was
current in its lease payments to Edison Capital.
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International's recorded estimated minimum liability to remediate its 33 identified sites at SCE (30 sites) and EME (3 sites)
is $91 million, $89 million of which is related to SCE. In third quarter 2003, SCE sold certain oil storage and pipeline
facilities. This sale caused a reduction in Edison International's recorded estimated minimum environmental liability. 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 $242 million, $240 million of which is related to SCE. The
upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of
reasonably possible outcomes.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $31 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. SCE expects to
recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $66 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 $15 million to $30 million. Recorded costs for the twelve months ended September 30, 2003
were $15 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
In August 2002, Edison International received a notice from the Internal Revenue Service (IRS) asserting deficiencies in federal
corporate income taxes for its 1994 to 1996 tax years. The vast majority of the tax deficiencies are timing differences and,
therefore, amounts ultimately paid, if any, would benefit Edison International as future tax deductions. Edison International
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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Among the issues raised by the IRS in the 1994 to 1996 audit was Edison Capital's treatment of the EPZ and Dutch electric locomotive
leases. Written protests were filed against these deficiency notices, as well as other alleged deficiencies, asserting that the
IRS's position misstates material facts, misapplies the law and is incorrect. Edison Capital will contest the assessment through
administrative appeals and litigation, if necessary. Edison Capital believes it will ultimately prevail in an outcome that will not
have a material adverse financial impact.
The IRS is also currently examining the tax returns for Edison International, which includes Edison Capital, for years 1997 through
1999. Edison Capital expects the IRS to also challenge several of its other leveraged leases based on a recent Revenue Ruling
addressing a specific type of leveraged lease (termed a lease in/lease out or LILO transaction). Edison Capital believes that the
position described in the Revenue Ruling is incorrectly applied to Edison Capital's transactions and that its leveraged leases are
factually and legally distinguishable in material respects from that position. Edison Capital intends to defend, and litigate if
necessary, against any challenges based on that position.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to SCE's Mohave Generating Station. In June 1999,
the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against
Peabody and certain of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE. The complaint
asserts claims against the defendants for, among other things, violations of the federal RICO statute, interference with fiduciary
duties and contractual relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. The complaint
claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion, as
well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated.
In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation had breached a
settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.
The Navajo Nation had previously filed suit in the Court of Federal Claims against the United States Department of Interior, alleging
that the Government had breached its fiduciary duty concerning contract negotiations including the Navajo Nation and the defendants.
In February 2000, the Court of Federal Claims issued a decision in the Government's favor, finding that while there had been a
breach, there was no available redress from the Government. Following appeal of that decision by the Navajo Nation, an appellate
court ruled that the Court of Federal Claims did have jurisdiction to award damages and remanded the case to the Court of Federal
Claims for that purpose. On June 3, 2002, the Government's request for review of the case by the United States Supreme Court was
granted. On March 4, 2003, the Supreme Court reversed the appellate court and held that the Government is not liable to the Navajo
Nation as there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government.
Based on the Supreme Court's analysis, on April 28, 2003, SCE filed a motion to dismiss or, in the alternative, for summary judgment
in the D.C. District Court action. The motion remains pending.
On October 24, 2003, the Court of Appeals, on remand from the Supreme Court, issued a decision remanding the action brought against
the Government back to the Court of Federal Claims for further proceedings. The Court of Appeals, acting on a suggestion on remand
filed by the Navajo Nation, held in
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
its October 24, 2003 decision that the Supreme Court's 2003 decision was focused on a particular statute and therefore did not
address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties
on the United States during the time period in question. The Court of Appeals, however, further recognized the possibility that the
Navajo Nation may have waived the right to assert claims based on the network theory. The Court of Appeals accordingly directed in
its remand order that the Court of Federal Claims decide in the first instance whether such a waiver had occurred. If no waiver is
found, then the Court of Federal Claims is directed in the remand order to determine whether a network of other statutes and
regulations imposes an enforceable fiduciary obligation on the Government and, if so, whether such duties were breached under the
relevant facts. SCE is currently analyzing the extent to which the Court of Appeals' October 24, 2003 decision will have any impact
on the Navajo Nation's claims against SCE and Peabody.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact on this complaint or
the Supreme Court's decision on the outcome of the Navajo Nation's suit against the Government, or the impact of the complaint on the
operation of Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $10.9 billion as. SCE and other owners of the San Onofre and
Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available ($300 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear
incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site.
Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre
Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $101 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 $199 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 U.S. Congress has extended the expiration date of the applicable law until December 31, 2004.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde.
Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater
than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit
outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear
facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed
retrospective premium adjustments of up to $38 million per year. Insurance premiums are charged to operating expense.
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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 0.1(cent)per kWh of nuclear-generated electricity sold after
April 6, 1983.
SCE, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. The spent
nuclear fuel is stored in the San Onofre Units 1, 2 and 3 spent fuel pools. The Units 2 and 3 spent fuel pools currently contain
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 began moving the Unit 1 spent fuel to the dry cask interim spent fuel storage facility at
San Onofre during the third quarter of 2003. By late 2004, 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.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage
facility. Arizona Public Service Company plans to continually load casks on a schedule to maintain full core off-load capability for
all three units.
Storm Lake
As of September 30, 2003, Edison Capital had an investment of approximately $74 million in Storm Lake Power, a project developed by
Enron Wind, a subsidiary of Enron Corporation. As of September 30, 2003, Storm Lake had outstanding loans of approximately
$60 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 oppose any
attempt by the lenders to exercise remedies that could result in a loss of Edison Capital's investment.
Note 5. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), a nonutility power
generation segment (EME), and a financial services provider segment (Edison Capital).
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information for the three and nine months ended September 30, 2003 and 2002 was:
Three Months Ended Nine Months Ended
September 30, September 30,
- -----------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenue:
Electric utility $ 2,794 $ 2,713 $ 6,994 $ 6,754
Nonutility power generation 1,014 954 2,412 2,164
Financial services 21 35 65 81
Corporate and other 4 4 8 21
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 3,833 $ 3,706 $ 9,479 $ 9,020
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 374 $ 234 $ 700 $ 1,075
Nonutility power generation(2) 200 149 17 116
Financial services 14 27 41 58
Corporate and other (44) (58) (134) (148)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 544 $ 352 $ 624 $ 1,101
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock. Includes earnings from discontinued operations of $44 million and $50 million,
respectively, for the three and nine months ended September 30, 2003.
(2) Includes losses of $9 million from the cumulative effect of an accounting change for the nine months ended September 30,
2003. Also, includes a loss from discontinued operations of $2 million for the nine months ended September 30, 2003 and
earnings from discontinued operations of $6 million and $21 million, respectively, for the three and nine months ended
September 30, 2002.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment. The net loss of
$44 million and $134 million, respectively, reported for the three and nine months ended September 30, 2003 also includes Mission
Energy Holding Company's (MEHC) net loss of $25 million and $73 million, respectively, for the same periods. The net loss of $58
million and $148 million, respectively, reported for the three and nine months ended September 30, 2002 also includes MEHC's net loss
of $24 million and $70 million, respectively, for the same periods.
Total segment assets as of September 30, 2003 were: electric utility, $20 billion; nonutility power generation, $12 billion; and,
financial services, $4 billion.
Note 6. Acquisitions and Dispositions
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen, to acquire
Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands, California. This acquisition
requires regulatory approval from both the CPUC and the FERC. SCE has filed an application with the CPUC proposing a power-purchase
agreement between SCE and Mountainview Power Company LLC. If approved by the CPUC, SCE will seek FERC approval of the power-purchase
agreement. SCE does not expect to exercise the option without CPUC and FERC approvals. The option must be exercised prior to
February 29, 2004. If SCE exercises the option, SCE would recommence full construction of the project. Under the option
Page 22
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
agreement, Sequoia may elect to terminate the option agreement at any time prior to SCE's exercise of the option. In such event,
Sequoia must return all previously tendered option payments.
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki
combined cycle power station and related interests. Consideration for the Taranaki station consisted of a cash payment of
approximately $275 million, which was initially financed with bridge loan facilities. The bridge loan facilities were subsequently
repaid with proceeds from the issuance of long-term U.S. dollar denominated notes. The Taranaki station is a 357 MW combined cycle,
natural gas-fired plant located near Stratford, New Zealand.
In July 2003, EME agreed to sell its 50% interest in the Gordonsville project to a third party. Completion of the sale, currently
expected during the fourth quarter of 2003, is subject to closing conditions. Net proceeds from the sale, including distribution of
a debt service reserve fund, are expected to be approximately $32 million. EME recorded an impairment charge of $6 million during
the second quarter of 2003 related to the planned disposition of this investment.
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 2001, EME recorded asset
impairment charges of $32 million related to these projects based on the expected sales proceeds. No gain or loss was recorded from
the sale of EME's interests in these projects during the first quarter of 2002.
Note 7. Asset Impairment
During second quarter 2003, EME recorded an asset impairment charge resulting from a revised long-term outlook for capacity revenue
from its small peaking plants in Illinois due to a number of factors, including the effect of higher long-term natural gas prices on
the competitiveness of these units and the current oversupply of generation. Since capacity value represents a key revenue component
for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets from $286 million to
their estimated fair market value of $41 million. The estimated fair value was determined based on discounting estimated future cash
flows using a 17.5% discount rate. In addition, EME recorded an asset impairment charge associated with the planned disposition of
its investment in the Gordonsville project (see Note 6). These amounts are included in the asset impairment line item of the
September 30, 2003 consolidated statements of income.
During the third quarter of 2002, EME recorded an asset impairment charge of $86 million, consisting of $61 million related to the
write-off of capitalized costs associated with the termination of equipment purchase contracts with Siemens Westinghouse and
$25 million related to the write-off of capitalized costs associated with the suspension of the Powerton Station selective catalytic
reduction major capital environmental improvements project at the Illinois plants. These amounts are included in the asset
impairment line item of the September 30, 2002 consolidated statements of income.
Note 8. Discontinued Operations
On July 10, 2003, the CPUC approved SCE's sale of certain oil storage and pipeline facilities to Pacific Terminals LLC for $158
million. In third quarter 2003, SCE recorded a $44 million after-tax gain to shareholders. In accordance with an accounting
standard related to the impairment and disposal of long-lived assets, this oil storage and pipeline facilities unit's results have
been accounted for as a discontinued operation in the financial statements for both the three and nine months ended September 30,
Page 23
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2003. Due to immateriality, the results of this unit for prior periods have not been restated and are reflected as part of
continuing operations. In addition, the results of the Lakeland project, the Fiddler's Ferry and Ferrybridge coal stations and
Edison Enterprises subsidiaries sold during 2001 have been reflected as discontinued operations in the consolidated financial
statements for all periods presented in accordance with an accounting standard related to the impairment and disposal of long-lived
assets. The consolidated financial statements have been restated for the three and nine months ended September 30, 2002 to conform
to the discontinued operations presentation for the three and nine months ended September 30, 2003.
For the three and nine months ended September 30, 2003, revenue from discontinued operations was $3 million and $20 million,
respectively, and pre-tax income was $72 million and $81 million, respectively. For the three and nine months ended September 30,
2002, revenue from discontinued operations was $20 million and $58 million, respectively, and pre-tax income was $7 million and $21
million, respectively.
The carrying value of assets and liabilities of discontinued operations were:
September 30, December 31,
In millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Assets
Cash and equivalents $ -- $ --
Receivables - net -- 1
Other 2 9
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 2 10
- ------------------------------------------------------------------------------------------------------------------------------
Utility plant - net -- 5
Nonutility plant - net -- 51
Other noncurrent assets 10 57
- ------------------------------------------------------------------------------------------------------------------------------
Total assets $ 12 $ 123
- ------------------------------------------------------------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities $ 4 $ 23
Short-term debt and other -- --
- ------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 4 23
Noncurrent liabilities 9 49
- ------------------------------------------------------------------------------------------------------------------------------
Total liabilities $ 13 $ 72
- ------------------------------------------------------------------------------------------------------------------------------
Note 9. Subsequent Events
On October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard &
Poor's also lowered the credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan
facility to B from BB-) and Edison Mission Marketing & Trading (corporate credit rating to B from BB-). Standard & Poor's placed the
ratings of all these entities on CreditWatch with negative implications. These ratings actions did not trigger any defaults under
EME's credit facilities or those of the other affected entities.
As a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit
in the cash flow recapture account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to
prepay that indebtedness with the
Page 24
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
amount of such prepayment applied ratably to the $911 million and $808 million tranches of Edison Mission Midwest Holdings'
indebtedness. Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million
tranche, and $116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to
$781 million and $692 million, respectively. In the future, so long as Edison Mission Midwest Holdings' ratings remain at the current
level or lower, amounts of excess cash flow deposited in the cash flow recapture account at the end of each calendar quarter will be
used upon deposit to prepay, pro rata, amounts then outstanding under these bank facilities. The Edison Mission Midwest Holdings
$781 million of debt maturing on December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings
does not have sufficient cash to repay this indebtedness when due.
On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup,
Credit Suisse First Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to
provide bridge financing to asset sales, including the sale of some or all of its international operations, depending upon, among
other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution
of approximately $550 million in Edison Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison
Mission Midwest Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds from this financing will be
used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Mission Energy Holdings
International owns substantially all of EME's international operations, through its subsidiary, MEC International B.V. The
commitment letter provides that collateral for this financing includes a pledge of:
o 65% of the stock of MEC International; and
o notes receivable totaling approximately $286 million at September 30, 2003 held by Mission Energy Holdings International and
EME UK International, LLC, a subsidiary of EME, from MEC International.
In addition to the pledges of collateral, the commitment letter provides for guarantees of the loan by a number of EME domestic
subsidiaries, including a guarantee by Edison Mission Finance Co., which will pledge its receivable from EME Homer City Generation
L.P. under a revolving loan agreement (under which $499 million was outstanding at September 30, 2003) as security for such
guarantee. The commitment letter also provides for:
o restrictions on the incurrence of additional indebtedness by Mission Energy Holdings International and its subsidiaries,
other than specified indebtedness, including certain indebtedness incurred in the ordinary course of business;
o prohibition of liens on property of Mission Energy Holdings International, subject to specific exceptions;
o restrictions on new investments by Mission Energy Holdings International other than, among other things, certain investments
in the ordinary course of business; and
o mandatory prepayments under specified conditions, including proceeds from the sales of assets as further described below.
Page 25
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The commitment letter provides that Mission Energy Holdings International will covenant to prepay the indebtedness in an amount equal
to the net after-tax proceeds from any international asset sales when such proceeds exceed $50 million, from certain issuances of
indebtedness and equity, and from specified domestic asset sales when such proceeds exceed $200 million. In certain circumstances,
prepayment of indebtedness will be required in an amount equal to 100% of net after-tax proceeds from the sale of certain of the
domestic subsidiary guarantors of such indebtedness.
In addition, the commitment letter provides for maintenance of a minimum twelve-month interest coverage ratio beginning March 2004.
Funding of this loan is subject to completion of definitive documentation and a number of closing conditions, including obtaining
certain consents and required corporate authorizations by MEHC and EME. Completion of this loan is subject to uncertainty and
accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.
A failure to repay, extend or refinance the Edison Mission Midwest Holdings $781 million obligation is likely to result in a default
under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME, or both, to file a petition
for reorganization under Chapter 11 of the United States Bankruptcy Code. The independent accountants' audit opinions on the
year-ended 2002 financial statements of MEHC and EME contain an explanatory paragraph that indicates the consolidated financial
statements have been prepared on the basis that these companies will continue as going concerns and that the uncertainty about Edison
Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about their ability to
continue as going concerns. Accordingly, Edison International's consolidated financial statements do not include any adjustments
that might result from the resolution of this uncertainty.
Page 26
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three- and nine-month
periods ended September 30, 2003 discusses material changes in the results of operations, financial condition and other developments
of Edison International since December 31, 2002, and as compared to the three- and nine-month periods ended September 30, 2002. This
discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2002 (the year-ended
2002 MD&A), which was included in Edison International's 2002 annual report to shareholders and incorporated by reference into Edison
International's Annual Report on Form 10-K for the year ended December 31, 2002.
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 MD&A. Important factors that could cause actual results to differ
include, but are not limited to, risks discussed below under "Financial Condition," "Market Risk Exposures" and "Forward-Looking
Information and Risk Factors." The following discussion provides updated information about material developments since the issuance
of the year-ended 2002 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, 2002.
This MD&A includes information about Edison International and its principal subsidiaries, Southern California Edison Company (SCE),
Edison Mission Energy (EME), Edison Capital, and Mission Energy Holding Company (MEHC). Edison International is a holding company.
SCE is a regulated public utility company providing electricity to retail customers in central, coastal, and southern California.
EME is an independent power producer engaged in owning or leasing and operating electric power generation facilities worldwide and in
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, EME, Edison Capital or MEHC mean each such company with its subsidiaries on a
consolidated basis. References to Edison International (parent) or parent company mean Edison International on a stand-alone basis,
not consolidated with its subsidiaries. References to SCE, EME, Edison Capital or MEHC followed by (stand alone) mean each such
company alone, not consolidated with its subsidiaries.
CURRENT DEVELOPMENTS
SCE Developments
As discussed in detail in "SCE's Regulatory Matters--CPUC Litigation Settlement Agreement," in October 2001, SCE entered into a
settlement agreement with the California Public Utilities Commission (CPUC) that allowed SCE to recover $3.6 billion in past
procurement-related costs. The Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the United
States Court of Appeals for the Ninth Circuit seeking to overturn the federal district court judgment that approved the settlement
agreement. In September 2002, the Ninth Circuit issued its opinion affirming the federal district court on all claims, with the
exception of challenges founded upon California state law, which the Ninth Circuit referred to the California Supreme Court. On
August 21, 2003, the California Supreme Court concluded that the settlement agreement did not violate California law in any of the
respects raised by the Ninth Circuit. On September 8, 2003, TURN filed a petition for rehearing of the California Supreme Court's
decision. On October 22, 2003, the California Supreme Court denied TURN's petition.
Page 27
The matter will now return to the Ninth Circuit for final disposition, subject to any efforts by TURN to pursue further federal
appeals.
As discussed in "SCE's Regulatory Matters--PROACT Regulatory Asset," "--Energy Resource Recovery Account Proceedings," "--Generation
Procurement Proceedings" and "--Customer Rate-Reduction Plan," SCE fully recovered the procurement-related obligations account
(PROACT) balance during July 2003. On October 14, 2003, the Energy Division of the CPUC completed its review of PROACT, approved the
accounting and rate-making issues related to PROACT, and eliminated the account effective August 14, 2003. SCE implemented a
CPUC-approved customer rate-reduction plan effective August 1, 2003. The customer rate-reduction plan reduces SCE's annual rates by
$1.2 billion (with no impact to earnings) and will reduce rates by 8% for residential customers, 18% for small businesses, 13% for
medium businesses and 19% for large businesses.
MEHC and EME Developments
A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of
major integrated energy companies that sell a sizable portion of their generation into the wholesale energy market (sometimes
referred to as merchant generators), including several of EME's subsidiaries. These developments included lower prices and greater
volatility in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of
most major market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the
energy markets due to growing concern about the ability of counterparties to perform their obligations. Since the beginning of 2003,
several merchant generators have reached agreements to extend existing bank credit facilities and at least three merchant generators
have filed for Chapter 11 protection under the United States Bankruptcy Code.
On October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard &
Poor's also lowered the credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan
facility to B from BB-) and Edison Mission Marketing & Trading (corporate credit rating to B from BB-). Standard & Poor's placed the
ratings of all these entities on CreditWatch with negative implications. These ratings actions did not trigger any defaults under
EME's credit facilities or those of the other affected entities.
As a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit
in the cash flow recapture account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to
prepay that indebtedness, with the amount of such prepayment applied ratably to the $911 million and $808 million tranches thereof.
Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million tranche, and
$116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and
$692 million, respectively. In the future, so long as Edison Mission Midwest Holdings' ratings remain at the current level or lower,
amounts of excess cash flow deposited in the cash flow recapture account at the end of each calendar quarter will be used upon
deposit to prepay, pro rata, amounts then outstanding under these bank facilities. The Edison Mission Midwest Holdings' $781 million
of debt maturing on December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings does not have
sufficient cash to repay this indebtedness when due.
On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup,
Credit Suisse First Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to
provide bridge financing to asset sales, including the sale of some or all of its international operations, depending upon, among
other
Page 28
things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution of
approximately $550 million in Edison Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission
Midwest Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds from this financing will be used to
repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Mission Energy Holdings International
owns substantially all of EME's international operations, through its subsidiary, MEC International B.V. The commitment letter
provides that collateral for this financing includes a pledge of:
o 65% of the stock of MEC International; and
o notes receivable totaling approximately $286 million at September 30, 2003 held by Mission Energy Holdings International and
EME UK International, LLC, a subsidiary of EME, from MEC International.
In addition to the pledges of collateral, the commitment letter provides for guarantees of the loan by a number of EME domestic
subsidiaries, including a guarantee by Edison Mission Finance Co., which will pledge its receivable from EME Homer City Generation
L.P. under a revolving loan agreement (under which $499 million was outstanding at September 30, 2003) as security for such
guarantee. The commitment letter also provides for:
o restrictions on the incurrence of additional indebtedness by Mission Energy Holdings International and its subsidiaries,
other than specified indebtedness, including certain indebtedness incurred in the ordinary course of business;
o prohibition of liens on property of Mission Energy Holdings International, subject to specific exceptions;
o restrictions on new investments by Mission Energy Holdings International other than, among other things, certain investments
in the ordinary course of business; and
o mandatory prepayments under specified conditions, including proceeds from the sales of assets as further described below.
The commitment letter provides that Mission Energy Holdings International will covenant to prepay the indebtedness in an amount equal
to the net after-tax proceeds from any international asset sales when such proceeds exceed $50 million, from certain issuances of
indebtedness and equity and from specified domestic asset sales when such proceeds exceed $200 million. In certain circumstances,
prepayment of indebtedness will be required in an amount equal to 100% of net after-tax proceeds from the sale of certain of the
domestic subsidiary guarantors of such indebtedness.
In addition, the commitment letter provides for maintenance of a minimum twelve-month interest coverage ratio beginning March 2004.
Funding of this loan is subject to completion of definitive documentation and a number of closing conditions, including obtaining
certain consents and required corporate authorizations by MEHC and EME. Completion of this loan is subject to uncertainty and
accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.
A failure to repay, extend or refinance the Edison Mission Midwest Holdings $781 million obligation is likely to result in a default
under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME, or both, to file a petition
for reorganization under Chapter 11 of the United States Bankruptcy Code. The independent accountants' audit opinions on the
year-ended
Page 29
2002 financial statements of MEHC, EME and Midwest Generation contain an explanatory paragraph that indicates the consolidated
financial statements have been prepared on the basis that these companies will continue as going concerns and that the uncertainty
about Edison Mission Midwest Holdings' ability to repay, extend, or refinance this obligation raises substantial doubt about their
ability to continue as going concerns. Accordingly, Edison International's consolidated financial statements do not include any
adjustments that might result from the resolution of this uncertainty.
Edison International's investment in MEHC, through a wholly owned subsidiary, as of September 30, 2003, was $898 million. MEHC's
investment in EME, as of September 30, 2003, was $1.9 billion. Edison International does not intend to make an additional capital
investment in MEHC or its subsidiaries, unless it concludes that such investment would be in the best interest of Edison
International's shareholders.
RESULTS OF OPERATIONS
Edison International recorded earnings of $544 million, or $1.67 per share, for the three-month period ended September 30, 2003,
compared to $352 million, or $1.08 per share, in the same period last year, and earnings of $624 million, or $1.92 per share, for the
nine-month period ended September 30, 2003, compared to $1.1 billion, or $3.38 per share in the same period last year. Edison
International's 2003 results reflect a gain from discontinued operations for SCE's fuel oil pipeline and storage business.
The table below presents Edison International's earnings per share and net income for the three- and nine-month periods ended
September 30, 2003 and 2002, and the relative contributions by its subsidiaries.
In millions, except per-share amounts Earnings (Loss) Per Share Earnings (Loss)
- ---------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings (Loss):
SCE $ 1.01 $ 0.72 $ 329 $ 234
EME 0.61 0.44 200 143
Edison Capital 0.04 0.08 14 27
Mission Energy Holding Company (stand alone) (0.07) (0.07) (25) (24)
Edison International (parent) and other (0.06) (0.11) (18) (35)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 1.53 1.06 500 345
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Earnings
from Discontinued Operations 0.14 0.02 44 7
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings $ 1.67 $ 1.08 $ 544 $ 352
- ---------------------------------------------------------------------------------------------------------------------------------------
Page 30
In millions, except per-share amounts Earnings (Loss) Per Share Earnings (Loss)
- ---------------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings (Loss):
SCE $ 2.00 $ 1.83 $ 650 $ 595
EME 0.08 0.29 28 95
Edison Capital 0.13 0.18 41 58
Mission Energy Holding Company (stand alone) (0.22) (0.22) (73) (70)
Edison International (parent) and other (0.19) (0.24) (61) (79)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Core Earnings 1.80 1.84 585 599
SCE Implementation of URG decision -- 1.47 -- 480
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 1.80 3.31 585 1,079
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Earnings
from Discontinued Operations 0.15 0.07 48 22
- ---------------------------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (0.03) -- (9) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings $ 1.92 $ 3.38 $ 624 $1,101
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
Edison International's three-month period ended September 30, 2003 earnings from continuing operations were $500 million, compared
with $345 million in the comparable period in 2002; year-to-date ended September 30, 2003 earnings from continuing operations were
$585 million, compared with $1.1 billion in the same period in 2002.
SCE earnings from continuing operations for the three- and nine-month periods ended September 30, 2003, were $329 million and $650
million, respectively, compared with $234 million and $1.1 billion for the same periods in 2002. Excluding the $480 million
adjustment related to SCE's utility retained generation (URG) decision from the CPUC in second quarter 2002, SCE's year-to-date ended
September 30, 2002 earnings were $595 million. SCE's earnings from continuing operations for the three-month period ended September
30, 2003 increased $95 million over the same period in 2002, which reflects the favorable resolution of certain regulatory cases
recorded in the three-month period ended September 30, 2003. The regulatory cases include the CPUC's decision on the allocation of
certain overhead costs between rates authorized by the CPUC and rates authorized by the Federal Energy Regulatory Commission (FERC),
the final disposition of the PROACT following the CPUC's review (both of which are discussed in "--Operating Expenses"), and the Palo
Verde Nuclear Generating Station (Palo Verde) incentive awards (discussed in "--Other Income and Deductions"). These favorable
results were partially offset by performance-based ratemaking (PBR) rewards received in 2002, higher net interest expense and
depreciation expense.
Excluding the $480 million gain in 2002 to implement the URG decision, SCE's earnings from continuing operations for the nine-month
period ended September 30, 2003, increased by $55 million compared to the same period last year. This increase primarily reflects
the favorable resolution of certain regulatory cases at SCE recorded in the three-month period ended September 30, 2003, as discussed
above. Earnings were also affected by higher operations and maintenance expenses and depreciation expenses, partially offset by
higher revenue.
EME's earnings from continuing operations were $200 million and $28 million, respectively, for the three- and nine-month periods
ended September 30, 2003, compared with earnings of $143 million and $95 million, respectively, for the same periods in 2002. EME's
2003 third quarter earnings from continuing operations were higher than the 2002 third quarter earnings from continuing operations by
$57 million, primarily due to the write-off of capitalized costs in 2002. Other items occurring in 2003 that contributed to the
increase were higher U.S. energy prices, the start of operations at Phase 2 of the
Page 31
Sunrise project in June 2003, and increased earnings from the Contact, ISAB and Paiton projects. These favorable results were
partially offset by lower capacity revenue from EME's Midwest Generation subsidiary due to certain units being released from power
purchase agreements in 2003 and lower state tax benefits than in 2002. EME's earnings are seasonal with higher earnings expected
during the summer months.
EME's earnings from continuing operations for the nine-month period ending September 30, 2003, decreased by $67 million compared to
the same period last year primarily due to the asset impairment charge of $150 million (after-tax) in second quarter 2003 for Midwest
Generation's peaking facilities, partially offset by the start of operations at Phase 2 of the Sunrise project in June 2003 and the
write-off of capitalized costs in 2002. EME's 2003 results were favorably impacted by higher U.S. energy prices and increased
earnings from the Contact and Paiton projects. These favorable items were partially offset by a reduction in revenue from the
Illinois power plants, which reflects the release of certain power and capacity in 2003 from power purchase agreements, lower
ancillary revenue and mark-to-market losses on forward contracts at the First Hydro project, and lower state tax benefits.
The impairment charge at EME during the second quarter of 2003 resulted from a revised long-term outlook for capacity revenue from
its small peaking plants in Illinois due to a number of factors, including the effect of higher long-term natural gas prices on the
competitiveness of these units and the current oversupply of generation. Since capacity value represents a key revenue component for
these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets from $286 million to their
estimated fair market value of $41 million. The small peaking power plants range in size from 64 megawatts (MW) to 163 MW, and total
899 MW.
Edison Capital's earnings for the three- and nine-month periods ended September 30, 2003 were $14 million and $41 million,
respectively, compared with $27 million and $58 million, respectively, in the comparable periods in 2002. The decreases were
primarily due to lower state tax benefits. In addition, the nine-month period decrease is also due to a maturing lease portfolio
which produces lower income, partially offset by lower interest expense.
Earnings for the three- and nine-month periods ended September 30, 2003, for MEHC (stand alone) were substantially unchanged from the
results for the same periods in 2002.
Losses for Edison International (parent) and other for the three- and nine-month periods ended September 30, 2003 were $18 million
and $61 million, respectively, compared with $35 million and $79 million, respectively, in the comparable periods in 2002. The
decreases in the loss reflect an insurance premium refund to EME from Edison International's insurance subsidiary in the third
quarter of 2002 and an impairment charge in the third quarter of 2002 at its nonutility subsidiary providing operation and
maintenance services.
Operating Revenue
SCE's retail sales represented approximately 93% of electric utility revenue for both the three- and nine-month periods ended
September 30, 2003, and approximately 96% of electric utility revenue for both the same periods in 2002. Retail rates are regulated
by the CPUC and wholesale rates are regulated by the FERC.
Due to warmer weather and higher electricity usage during the summer months, electric utility revenue during the third quarter of
each year is significantly higher than other quarters.
Electric utility revenue increased for the three- and nine-month periods ended September 30, 2003, compared to the same periods in
2002, primarily due to increased retail and wholesale revenue. Retail
Page 32
revenue increased in the three- and nine-month periods mainly due to the recognition of revenue from the amortization of the
temporary surcharge that was collected in 2002 and authorized by the CPUC to be used to recover costs incurred in 2003 (see "SCE's
Regulatory Matters--Surcharge Decisions" in the year-ended 2002 MD&A for further discussion), an increase in volume primarily due to
warmer weather in 2003, compared to 2002, and higher revenue resulting from a net 1(cent)per kilowatt-hour (kWh) decrease in credits
given to direct access customers. During the period January 1, 2002 through July 27, 2002, direct access customers were given an
average credit of 11(cent)per kWh. This average credit was reduced to 8.3(cent)per kWh on July 27, 2002, to collect a nonbypassable
historical procurement charge, causing SCE's revenue to increase by 2.7(cent)per kWh through the end of 2002. Beginning on January 1,
2003, SCE's share of the nonbypassable historical procurement charge was reduced to 1(cent)per kWh, with the remaining 1.7(cent)per kWh
allocated and remitted to the California Department of Water Resources (CDWR) for its costs associated with direct access customers
(see discussion below). The increases were partially offset by a decrease in revenue due to the implementation of a CPUC-approved
customer rate-reduction plan effective August 1, 2003, and an increase in amounts remitted to CDWR for energy purchases, including an
allocation adjustment during the nine-month period ended September 30, 2003, bond-related charges (beginning November 15, 2002) and
direct access exit fees (beginning January 1, 2003). Wholesale revenue increased due to the resale of SCE's excess energy, compared
to no excess energy sales in 2002. As a result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at
certain times and is resold in the energy markets.
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,
were invalid. Direct access arrangements entered into prior to September 20, 2001 remain valid. As part of the CPUC-approved
customer rate-reduction plan, effective August 1, 2003, direct access customers are no longer given a credit since these customers
are no longer billed for generation. Electric utility revenue for the period in which the credit was given is reported net of this
credit. See "SCE's Regulatory Matters--Direct Access Proceedings" discussion.
Amounts SCE bills and collects from its customers for electric power purchased and sold by CDWR to SCE's customers (beginning
January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003) are
remitted to CDWR and are not recognized as revenue by SCE. These amounts were $541 million and $1.4 billion for the three- and
nine-month periods ended September 30, 2003, respectively, compared to $326 million and $922 million for the three- and nine-month
periods ended September 30, 2002, respectively.
Nonutility power generation revenue increased for both the three- and nine-month periods ended September 30, 2003, compared to the
same periods in 2002, primarily due to increased electric revenue from EME's Homer City facilities and Contact Energy projects,
partially offset by lower revenue from power supply contracts with Exelon Generation. The increases at EME's Homer City facilities
were primarily due to increased generation and higher energy prices. The increases at EME's Contact Energy projects were primarily
due to higher wholesale energy prices, higher generation and an increase in the average exchange rate during the three- and
nine-month periods ended September 30, 2003, compared to the corresponding periods in 2002. Partially offsetting the 2003 increases
were lower revenue from power purchase agreements with Exelon Generation.
In accordance with power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power
purchase agreements at EME's Illinois plants. Of the generating capacity released by Exelon Generation, EME's subsidiary suspended
operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, EME's Illinois plants have had 3,133 MW of
uncontracted capacity available for sale in the merchant generation market. Exelon Generation is
Page 33
obligated, under the power purchase agreements, to make capacity payments for the Illinois plants under contract (4,739 MW during
2003) and energy payments for electricity produced by these plants. As a result of the decline in contracted generating capacity
under the power purchase agreements, EME's revenue from Exelon Generation was $313 million and $521 million for the third quarters of
2003 and 2002, respectively. EME's revenue from Exelon Generation was $606 million and $957 million for the nine-month periods ended
September 30, 2003 and 2002, respectively. This represents 31% and 55% of nonutility power generation revenue for the third quarters
of 2003 and 2002, respectively, and 25% and 44% for the nine-month periods ended September 30, 2003 and 2002, respectively. For more
information on the power purchase agreements see "Illinois Plants" in "Market Risk Exposures--EME's Market Risks--Commodity Price Risk."
Nonutility power generation revenue during the third quarter is materially higher than revenue related to other quarters of the year
because warmer weather during the summer months results in higher revenue being generated from EME's Homer City facilities and
Illinois plants. By contrast, EME's First Hydro plants have higher revenue during their winter months. During 2002 and the first
quarter of 2003, there was further downward pressure on wholesale prices in the England and Wales wholesale electricity market but
some recovery in the peak/off peak differentials for the upcoming winter period. This recovery in the market continued during the
summer of 2003 with higher-than-expected demand and with a further increase in forward prices for the winter of 2003 reflecting an
expected reduction in the excess of available physical generating capacity over expected electrical demand. Despite the difficult
market conditions, EME's First Hydro has continued to meet the interest coverage ratios specified in its bond financing documents,
and to meet its half yearly interest payments without recourse to the project's debt service reserve. EME believes that if market
and trading conditions experienced thus far in 2003 are sustained, EME's First Hydro will continue to be compliant with the
requirements of its bond financing documents. This compliance is, however, subject to market conditions for electric energy and
ancillary services, which are beyond EME's control.
Financial services and other revenue decreased for both the three- and nine-month periods ended September 30, 2003, compared to the
same periods in 2002, primarily due to Edison Capital's maturing lease portfolio. The nine-month period decrease is also due to no
nonutility real estate sales in 2003, as compared to 2002, for another subsidiary.
Operating Expenses
Fuel expense increased for both the three- and nine-month periods ended September 30, 2003, compared to the same periods in 2002,
primarily due to coal-related costs incurred in 2003 at SCE, increased generation from EME's Homer City facilities and increased fuel
costs at EME's Contact Energy projects primarily due to higher gas prices and an increase in the value of the New Zealand dollar
compared to the U.S. dollar. The three-month period increase was partially offset by lower generation from EME's Collins Station and
coal plants in Illinois. The nine-month period increase was also due to increased generation at one of SCE's coal facilities, as
well as increased generation at EME's Homer City facilities primarily resulting from outages experienced during the first two
quarters of 2002, partially offset by lower nuclear fuel expenses at SCE.
Purchased-power expense increased for the three- and nine-month periods ended September 30, 2003, compared to the same periods in
2002, mainly due to higher expenses resulting from SCE's resumption of power procurement on January 1, 2003. The higher expenses
resulted from an increase in the number of bilateral contracts entered into during 2003 and an increase in imbalance energy purchased
in 2003. The nine-month period increase also includes higher expenses related to power purchased by SCE from qualifying facilities
(QFs), mainly due to higher spot natural gas prices in 2003, as compared to 2002.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments
to gas-fired cogeneration QFs are generally tied to spot
Page 34
natural gas prices. During 2003, spot natural gas prices were higher compared to the same periods in 2002. Effective May 2002,
energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)per kWh, compared with an average of 3.1(cent)per kWh
during the period between January and April 2002.
Provisions for regulatory adjustment clauses - net decreased during the three-month period ended September 30, 2003 and increased
during the nine-month period ended September 30, 2003, compared to the same periods in 2002. The three-month period decrease was
mainly due to lower overcollections used to recover SCE's PROACT balance, the implementation of the CPUC-authorized customer
rate-reduction plan, a net increase in energy procurement costs, an adjustment to a pension-related regulatory reserve and the
favorable resolution of certain regulatory cases recorded in the third quarter of 2003. The regulatory cases include the CPUC
decision on the allocation of certain overhead costs between rates authorized by the CPUC and the FERC (see "SCE's Regulatory
Matters--Transmission Rate Case") and the final disposition of the PROACT following the Energy Division of the CPUC's review (see
"SCE's Regulatory Matters--PROACT Regulatory Asset"). The nine-month period increase was mainly due to SCE's reestablishment of
regulatory assets related to its unamortized nuclear facilities, purchased power settlements and flow-through taxes recorded in
2002. The increase was almost entirely offset by a decrease in overcollections used to recover the PROACT balance, an allocation
adjustment for CDWR energy purchases, an adjustment to a pension-related regulatory reserve and the favorable resolution of certain
regulatory cases recorded in the third quarter of 2003 as discussed above.
Other operating and maintenance expense increased during both the three- and nine-month periods ended September 30, 2003. SCE's
other operating and maintenance expense increased for the three- and nine-month period ended September 30, 2003, mainly due to higher
health-care costs and higher spending on certain CPUC-authorized programs and higher transmission access charges. EME's operating
and maintenance expense increased for the three- and nine-month periods ended September 30, 2003. These increases were the result of
higher transmission costs primarily due to higher retail sales generated at EME's Contact Energy projects and an increase in the
value of the New Zealand dollar compared to the U.S. dollar, as well as an increase in administrative and general expenses due to
higher consulting fees in 2003 related to debt restructuring activities and additional long-term incentive compensation expense
related to deferred payments and annual vesting of benefits. The nine-month increase was partially offset by charges against 2002
earnings for severance and other related costs, which resulted from a series of actions undertaken to reduce administrative and
general operating costs at EME.
Asset impairment expense for the nine-month period ended September 30, 2003, consisted of $246 million related to the impairment of
eight small peaking plants owned by EME's wholly owned subsidiary, Midwest Generation, and $6 million related to EME's write-down of
its investment in the Gordonsville project due to its planned disposition (see "Acquisitions and Dispositions" for further
discussion). The impairment charge related to the peaking plants resulted from a revised long-term outlook for capacity revenue from
the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas
prices and the current generation overcapacity in the Mid-America Interconnected Network region market. See "Financial
Condition--EME's Liquidity Issues--EME's Recourse Debt to Recourse Capital Ratio." The book value of these assets was written down from
$286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting
estimated future pre-tax cash flows using a 17.5% discount rate. Asset impairment expense for the three- and nine-month periods
ended September 30, 2002 consisted of $61 million related to the write-off of capitalized costs associated with EME's termination of
equipment purchase contracts and $25 million related to the write-off of capitalized costs associated with EME's suspension of its
Powerton Station selective catalytic reduction major capital environmental improvements project at its Illinois plants.
Page 35
Depreciation, decommissioning and amortization expense increased during both the three- and nine months ended September 30, 2003,
mainly due to a change in the amortization period for SCE's nuclear facilities recorded in the third quarter of 2002 based on the
implementation of a CPUC decision, an increase in depreciation expense associated with SCE's additions to transmission and
distribution assets and higher depreciation expense at EME's Contact Energy projects associated with the Taranaki Station
acquisition. The nine-month increase also included additional depreciation expense resulting from the termination of EME's Midwest
Generation equipment lease in August 2002, and an increase in amortization expense at Edison Capital resulting from a change from the
cost method to the equity method of accounting for its fund investments in 2002.
Other Income and Deductions
Interest and dividend income decreased for both the three- and nine-month periods ended September 30, 2003, compared to the same
periods in 2002, mainly due to lower interest income on the PROACT balance at SCE. The nine-month period decrease also reflects
lower interest income from lower average cash balances at SCE, compared to the same period in 2002.
Equity in income from partnerships and unconsolidated subsidiaries - net increased in the three- and nine-month periods ended
September 30, 2003, compared to the same periods in 2002, primarily due to an increase in EME's share of income from its Big 4
projects, Four Star Oil & Gas and its Sunrise project, as well as an increase in earnings from Edison Capital's global infrastructure
fund investments. EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income
related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy
projects, located on the West Coast, have power sales contracts that provide for higher payments during the summer months.
Other nonoperating income increased for both the three- and nine-month periods ended September 30, 2003, compared to the same periods
in 2002. The three-month increase was mainly due to SCE's recognition of performance rewards, from 2000, related to Palo Verde and
approved by the CPUC during third quarter 2003. The nine-month increase also reflects performance rewards, from 2001, related to
Palo Verde and approved by the CPUC during the second quarter of 2003, as well as SCE's accrual of PBR revenue, for 2002, under the
PBR sharing mechanism filed with the CPUC during first quarter 2003.
Interest expense - net of amounts capitalized increased during the three-month period ended September 30, 2003 and decreased during
the nine-month period ended September 30, 2003, compared to the same periods in 2002. Effective July 1, 2003, dividend payments on
preferred securities subject to mandatory redemption are included as interest expense based on the adoption of a new accounting
standard. The new standard did not allow for prior period restatements, therefore dividends on preferred securities subject to
mandatory redemption for the first six months of 2003 are not included in interest expense - net of amounts capitalized in the
consolidated statements of income. In addition, the three-month period increase was due to higher interest costs at EME's Illinois
plants due to a downgrade of the credit rating of Edison Mission Midwest Holdings and higher levels of borrowings at EME's Contact
Energy projects (see "Liquidity--EME's Liquidity--Credit Ratings"). In addition, these increases were partially offset by lower
interest expense resulting from lower debt balances (both short- and long-term), as well as lower interest rates at Edison
International, SCE and Edison Capital. In addition, the nine-month period decrease reflects lower interest expense in 2003 at SCE
due to the accrual of interest in 2002 related to the 2001 and early 2002 suspension of payments for purchased power. These
suspended payments were paid in March 2002.
Other nonoperating deductions increased during the three- and nine-month periods ended September 30, 2003, compared to the same
periods in 2002, primarily due to lower accruals for regulatory matters at SCE in 2002, partially offset by a 2002 goodwill
impairment charge associated with EME's Citizens
Page 36
Power acquisition resulting from adoption of an accounting standard. The adoption of the standard was not material to Edison
International; therefore the impact was recorded in other nonoperating deductions, rather than as a cumulative effect of a change in
accounting principle.
Income Taxes
Income taxes increased for the three-month period ended September 30, 2003, and decreased for the nine-month period ended September
30, 2003, compared to the same periods in 2002. The three-month increase was primarily due to an increase in pre-tax income. The
nine-month period decrease was primarily due to a decrease in pre-tax income, partially offset by a reduction in SCE's tax expense in
2002 related to the income tax benefit associated with the reestablishment of generation-related regulatory assets upon
implementation of the URG decision.
Edison International's composite federal and state statutory rate was approximately 40.5% for both periods presented. The lower
effective tax rate of 37% and 34% realized for the three- and nine-month periods ended September 30, 2003 was primarily due to a
decrease in the California corporation franchise tax regulatory liability at SCE and low-income housing and production credits at
Edison Capital.
Earnings from Discontinued Operations
Edison International's discontinued operations for the three- and nine-month periods ended September 30, 2003 reflect a $44 million
(after-tax) gain on the sale of SCE's fuel oil pipeline and storage business. Edison International's discontinued operations for the
three- and nine-month periods ended September 30, 2002 reflect operating results from EME's Lakeland project and the recovery of an
insurance claim related to the operation of EME's Fiddler's Ferry and Ferrybridge project prior to its sale in 2001. On May 14,
2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for(pound)24 million. The
proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the
project.
Cumulative Effect of Accounting Change - Net
Edison International's results for the nine-month period ended September 30, 2003 include a $9 million charge at EME for the
cumulative effect of an accounting change related to the new accounting standard for recording asset retirement obligations adopted
by Edison International in January 2003. As SCE follows accounting principles for rate-regulated enterprises, implementation of this
new standard did not affect its earnings.
FINANCIAL CONDITION
The liquidity of Edison International is affected primarily by debt maturities, access to capital markets, external financings,
dividend payments, capital expenditures, lease obligations, asset purchases and sales, investments in partnerships and unconsolidated
subsidiaries, 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.
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. SCE's short-term debt is
normally used to finance procurement-related obligations, regulatory balancing accounts, and for general corporate purposes.
Long-term debt is used mainly to finance the utility's rate base. 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
Page 37
debt has been used for general corporate purposes, as well as investments. External financings are influenced by market conditions
and other factors.
The "Financial Condition" section of this MD&A discusses cash flows from operating, financing and investing activities, and liquidity
issues at Edison International (parent only), SCE, MEHC, EME and Edison Capital.
Cash Flows from Operating Activities
Net cash provided by operating activities:
In millions Nine Months Ended September 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ 2,893 $ 1,269
Discontinued operations (52) 83
- ------------------------------------------------------------------------------------------------------------------------------
$ 2,841 $ 1,352
- ------------------------------------------------------------------------------------------------------------------------------
The change in cash provided by operating activities from continuing operations was mainly due to SCE's March 2002 repayment of
past-due obligations. The change was also due to timing of cash receipts and disbursements related to working capital items at both
SCE and EME.
Cash Flows from Financing Activities
Net cash used by financing activities:
In millions Nine Months Ended September 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (978) $ (2,066)
Discontinued operations -- (14)
- ------------------------------------------------------------------------------------------------------------------------------
$ (978) $ (2,080)
- ------------------------------------------------------------------------------------------------------------------------------
Cash used by financing activities from continuing operations in 2002 mainly consisted of long- and short-term debt payments at SCE
and EME.
During the first quarter of 2003, Edison International (parent only) repurchased approximately $132 million of the outstanding $750
million of its 6-7/8% notes due September 2004. No repurchases were made during the second or third quarters of 2003. During the
nine-month period ended September 30, 2003, SCE repaid $300 million of a one-year term loan due March 3, 2003, and $300 million on
its revolving line of credit, both of which were part of the $1.6 billion financing that took place in the first quarter of 2002. In
addition, SCE repaid $125 million of its 6.25% bonds. EME's financing activity during the nine-month period ended September 30, 2003
included $275 million in borrowings by Contact Energy, EME's 51% owned subsidiary, used to finance Contact Energy's acquisition of
the Taranaki Combined Cycle power station (see "Acquisitions and Dispositions" for further discussion of the acquisition), debt
service payments of $76 million related to two of EME's subsidiaries, and a $31 million repayment of debt obligations due from EME's
acquisition of the Spanish Hydro project.
During the nine-month period ended September 30, 2002, SCE repaid $531 million of commercial paper, $400 million of its maturing
principal on its senior unsecured notes, and remarketed $196 million of the $550 million of pollution-control bonds repurchased
during December 2000 and early 2001. Also during the first quarter of 2002, SCE replaced the $1.65 billion credit facility with a
$1.6 billion secured credit facility and made a payment of $50 million to retire the remainder of the $1.65 billion credit facility.
EME's financing activity during the nine-month period ended September 30, 2002 consisted of a
Page 38
$100 million payment at maturity on senior notes, net payments of $80 million on EME's corporate credit facility, debt service
payments of $44 million, payments of $86 million on debt related to its Coal and Capex facility and $84 million in borrowings under a
note purchase agreement in January 2002 by a subsidiary of EME. EME also received $54 million from a swap agreement with a bank
related to lease payments for its Homer City facilities. Edison Capital financing activity during the nine-month period ended
September 30, 2002, included a $94 million pay-off of debt.
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Nine Months Ended September 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (1,243) $ (787)
Discontinued operations 152 2
- ------------------------------------------------------------------------------------------------------------------------------
$ (1,091) $ (785)
- ------------------------------------------------------------------------------------------------------------------------------
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.
Additions to SCE's property and plant for the nine-month period ended September 30, 2003, were approximately $820 million, primarily
for transmission and distribution assets. EME's capital additions for the nine-month period ended September 30, 2003 were $105
million primarily for new plant and equipment related to EME's Illinois plants, its Homer City facilities, and Contact Energy
projects. EME's year-to-date ended September 30, 2003 investing activity also included $275 million paid by Contact Energy for the
acquisition of the Taranaki Combined Cycle power station (see "Acquisitions and Dispositions" for further discussion of the
acquisition), and $60 million in equity contribution to EME's Sunrise and CBK projects.
Additions to SCE's property and plant for the nine-month period ended September 30, 2002, were approximately $694 million, primarily
for transmission and distribution assets. EME's capital additions in the nine-month period ended September 30, 2002 were $516
million primarily for new plant and equipment related to EME's Valley Power peaker project in Australia, Illinois plants, and the
Homer City facilities and payments related to three turbines. EME's investing activity for the nine-month period ended September 30,
2002, also included an $80 million payment for the purchase of a power sales agreement, payments totaling $147 million for three
turbines and the termination of its master turbine lease which reduced EME's restricted cash, a $300 million payment for the Illinois
peaker power units that were subject to a lease with $255 million received as a repayment of the note receivable held by EME, and $18
million paid in equity contributions for Phase 2 of EME's Sunrise project. EME received $44 million in proceeds from the sale of its
ownership interests in three energy projects and $78 million in distributions from EME's projects. Restricted cash totaling $53
million was used to meet EME's lease payment obligations.
Cash flows provided from investing activities from discontinued operations in 2003 represent net proceeds from the sale of SCE's fuel
oil pipeline and storage business.
Edison International's (parent only) Liquidity Issues
The parent company's liquidity and its ability to pay interest, debt principal, operating expenses and dividends to common
shareholders are affected by dividends from subsidiaries, tax-allocation payments under its tax-allocation agreement with its
subsidiaries, and access to capital markets or external financings.
Page 39
At September 30, 2003, Edison International (parent) had approximately $118 million of cash and cash equivalents on hand. On October
16, 2003, Edison International received cash dividends of $945 million from SCE and $225 million from Edison Capital. After receipt
of such dividends, Edison International had approximately $1.3 billion of cash and cash equivalents on hand.
Since May 2001, Edison International has 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 interest payment deferral 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. On November 30, 2003, Edison International expects to make aggregate payments of approximately $205 million,
which cover repayment of the deferred distributions, with interest, and payment of the distribution due on November 30, 2003. Edison
International then would resume quarterly distributions on the quarterly income debt securities, subject to its rights to begin
deferring distributions again in the future at its election. Edison International cannot declare and pay cash dividends on or
purchase its common stock as long as interest payments are being deferred.
During the first quarter of 2003, Edison International repurchased approximately $132 million of the outstanding $750 million of its
6-7/8% notes due September 2004. Edison International intends to use the dividend proceeds received in October 2003 to repay the
remaining principal amount of its notes due in September 2004.
The management of Edison International has stated that it has a goal to declare by year-end 2003 a dividend that would be paid to the
holders of its common stock in early 2004. The resumption of dividends from SCE and the payment of all deferred amounts on the
quarterly income preferred securities are necessary conditions for Edison International to be able to declare a common dividend to
its shareholders. For a dividend to be paid, it must be declared by the board of directors of Edison International. The ability of
the board of directors to declare a common stock dividend also depends on Edison International's financial condition and liquidity,
and the absence of material adverse developments. The board generally would declare a dividend at least 22 days before the payment
date to allow time for notices and processing.
The CPUC regulates SCE's capital structure by requiring that SCE maintain a prescribed percentage of common equity, preferred stock
and long-term debt in the utility's capital structure. SCE may not make any distributions to Edison International that would reduce
the common equity component of SCE's capital structure below the prescribed level. The CPUC also requires that SCE establish its
dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the
utility as necessary to meet its obligation to serve its customers. SCE's settlement agreement with the CPUC precluded SCE from
declaring or paying 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, with
certain exceptions. SCE fully recovered the PROACT balance during July 2003, and paid a $945 million dividend to Edison
International in October 2003 (see further discussion in "--SCE's Liquidity Issues"). Other factors at SCE that affect the amount and
timing of dividend payments to Edison International include, among other things, SCE's access to capital markets and actions by the
CPUC.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At September 30, 2003, its interest
coverage ratio was 1.31 to 1. See "--MEHC's Liquidity Issues--MEHC's Interest Coverage Ratio." MEHC did not declare or pay a dividend
in the first nine months of 2003. MEHC's ability to pay dividends is dependent on EME's ability to pay dividends to MEHC.
EME and its subsidiaries have certain dividend restrictions as discussed in "--EME's Liquidity Issues" section below. EME did not pay
or declare a dividend during the first nine months of 2003.
Page 40
Edison International's investment in MEHC, through a wholly owned subsidiary, as of September 30, 2003, was $898 million. MEHC's
investment in EME, as of September 30, 2003, was $1.9 billion. The independent accountants' audit opinions on the year-end 2002
financial statements of MEHC, EME and Midwest Generation contain an explanatory paragraph that indicates the consolidated financial
statements have been prepared on the basis that these companies will continue as going concerns and that the uncertainty about Edison
Mission Midwest Holdings' ability to repay, extend, or refinance this obligation raises substantial doubt about their ability to
continue as going concerns. Accordingly, the consolidated financial statements do not include any adjustments that might result from
the resolution of this uncertainty. On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a
commitment letter from Citigroup, Credit Suisse First Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year,
$700 million secured loan intended to provide bridge financing to asset sales, including the sale of some or all of its international
operations, depending upon, among other things, market prices. For an expanded discussion, see "Current Developments--MEHC and EME
Developments."
Edison Capital's ability to make dividend payments is restricted by debt covenants, which require Edison Capital to maintain a
specified minimum net worth. In October 2003, Edison Capital paid a $225 million cash dividend to Edison International. Edison
Capital currently meets the minimum net worth covenant.
SCE's Liquidity Issues
SCE expects to meet its continuing obligations from cash and equivalents on hand and operating cash flows.
SCE entered into a litigation settlement agreement with the CPUC in October 2001. The settlement agreement allowed SCE to recover
$3.6 billion of past procurement-related costs through a regulatory balancing account known as the PROACT, but also prohibited SCE
from paying any dividends to its parent, Edison International, during the period that the costs were being recovered. The recovery
of the past procurement-related costs was completed by July 31, 2003. On October 14, 2003, the CPUC completed its final review of
PROACT accounting and eliminated the PROACT account effective August 14, 2003. Also, as a result of recovering the PROACT balance,
SCE implemented a CPUC-approved customer rate-reduction plan effective August 1, 2003. The customer rate-reduction plan reduces
SCE's annual rates by $1.2 billion, but has no impact on earnings. See "SCE's Regulatory Matters--Other Regulatory Matters--Customer
Rate-Reduction Plan" for further details.
As of September 30, 2003, SCE had $1.7 billion in cash and equivalents and its common equity to total capitalization ratio, for
rate-making purposes, was approximately 54%. The CPUC-authorized level is 48%. Therefore, on October 16, 2003, SCE transferred
through a dividend to Edison International $945 million of equity that exceeded the CPUC-authorized level. The purpose of the
transfer was to begin to rebalance SCE's capital structure in accordance with CPUC requirements. Following the transfer, the ratio,
as of October 31, 2003, was approximately 49%.
In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE. Based on the rights to recover its past
procurement-related costs, SCE repaid its undisputed past-due obligations and near-term debt maturities in March 2002, using cash on
hand resulting from the proceeds of the $1.6 billion credit facilities and the remarketing of $196 million in pollution-control
bonds. The $1.6 billion credit facilities included a $600 million, one-year term loan due on March 3, 2003. SCE prepaid $300
million of this loan on August 14, 2002 and the remaining $300 million on February 11, 2003. The $1.6 billion credit facilities also
included a $300 million revolving line of credit with a March 2004 maturity and a $700 million term loan with a March 2005 final
maturity. On April 16, 2003, SCE fully repaid the $300 million drawn under its revolving line of credit. Under the term loan, net
cash
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proceeds from the issuance of capital stock or certain new indebtedness must be used to reduce the term loan, subject to certain
exceptions.
On February 24, 2003, SCE completed an exchange offer for its 8.95% variable rate notes due November 2003. A total of $966 million
of these notes was exchanged for $966 million of a new series of first and refunding mortgage bonds due February 2007. As a result
of the exchange offer, SCE's remaining debt maturity in 2003 is $34 million of the 8.95% variable rate notes due November 2003 that
were not exchanged. In addition, approximately $70 million of rate reduction notes are due in the fourth quarter of 2003 (a total of
$247 million is due in the twelve-month period ended September 30, 2004). These notes have a separate cost recovery mechanism
approved by state legislation and CPUC decisions. In addition, $125 million of 5.875% bonds are due in September 2004.
SCE resumed procurement of its residual net short (the amount of energy needed to serve SCE's customers from sources other than its
own generating plants, power purchase contracts and CDWR contracts) on January 1, 2003 and as of September 30, 2003, had
approximately $198 million posted as collateral to secure its obligations under power purchase contracts and to transact through the
Independent System Operator (ISO) for imbalance energy.
SCE's liquidity may be affected by, among other things, matters described in "SCE's Regulatory Matters--CPUC Litigation Settlement
Agreement," "--CDWR Power Purchases and Revenue Requirement Proceedings," and "--Generation Procurement Proceedings" sections.
MEHC's Liquidity Issues
At September 30, 2003, MEHC and its subsidiaries had cash and cash equivalents of $955 million and EME had available a total of
$107 million of borrowing capacity under its $212 million corporate credit facility. MEHC's consolidated debt at September 30, 2003
was $7.5 billion, including debt maturing on December 11, 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest
Holdings. In addition, EME's subsidiaries have approximately $7 billion of long-term lease obligations that are due over periods
ranging up to 32 years.
The remainder of this section discusses MEHC's liquidity issues on a stand alone basis. See "--EME's Liquidity Issues" for further
discussion of EME related items that may impact MEHC on a consolidated basis.
MEHC's ability to honor its obligations under the senior secured notes and the term loan after the two year interest reserve period
(which expired July 2, 2003 for the term loan and July 15, 2003 for the senior secured notes) and to pay overhead is substantially
dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and
ultimately Edison International. 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 and funds received pursuant to MEHC's tax-allocation
arrangements (see--Intercompany Tax-Allocation Payments) with MEHC's affiliates, 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 are limited based on its earnings and cash
flow, terms of restrictions contained in EME's contractual obligations (including its corporate credit facility), EME's charter
documents, business and tax considerations, and restrictions imposed by applicable law. MEHC did not receive any distributions from
EME during the first nine months of 2003.
At September 30, 2003, MEHC (stand alone) had cash and cash equivalents of $140 million. The lenders under MEHC's $385 million term
loan due in 2006 have the right to require MEHC to repurchase up to
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$100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). In order for MEHC to have
sufficient cash in the event of an exercise of a significant portion, or all, of the Term Loan Put-Option, MEHC would require
additional cash from dividends from EME, or would need to either extend the effective date of the Term Loan Put-Option or extend or
refinance the term loan. The timing and amount of dividends from EME and its subsidiaries may be affected by many factors beyond
MEHC's control. Dividends from EME are currently limited as described in "--EME's Liquidity--Ability of EME to Pay Dividends."
MEHC's Interest Coverage Ratio
The following details of MEHC's interest coverage ratio are provided as an aid to understanding the components of the computations
that are set forth in the indenture governing MEHC's senior secured notes. This information is not intended to measure the financial
performance of MEHC and, accordingly, should not be used in lieu of the financial information set forth in the consolidated financial
statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture and are
not the same as would be determined in accordance with generally accepted accounting principles.
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 Liquidity Issues--EME's Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage
ratio:
Twelve Months Ended Year Ended
In millions September 30, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Funds Flow From Operations:
EME $ 591 $ 692
Operating cash flow from
unrestricted subsidiaries -- (17)
Outflows of funds from
operations of projects sold (14) 2
MEHC 2 7
- -----------------------------------------------------------------------------------------------------------------------------------
$ 579 $ 684
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Expense:
EME $ 281 $ 293
EME - affiliate debt 1 2
MEHC interest expense 160 159
- -----------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 442 $ 454
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 1.31 1.51
- -----------------------------------------------------------------------------------------------------------------------------------
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's
senior secured notes and the credit agreement governing the term loan. The interest coverage ratio prohibits MEHC, EME and its
subsidiaries from incurring additional indebtedness, except as specified in the indenture and the financing documents, unless MEHC's
interest coverage ratio exceeds 1.75 to 1 for the immediately preceding four fiscal quarters prior to September 30, 2003 and 2.0 to 1
for periods thereafter.
MEHC's Intercompany Tax-Allocation Payments
MEHC is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to
participate in tax-allocation payments with other subsidiaries of Edison
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International. These arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the
voting power of the stock of MEHC and at least 80% of the value of such stock. The arrangements are subject to the terms of tax
allocation and payment agreements among Edison International, MEHC, EME and other Edison International subsidiaries. The agreements
to which MEHC is a party may be terminated by the immediate parent company of MEHC at any time, by notice given before the first day
of the first tax year with respect to which the termination is to be effective. However, termination does not relieve any party of
any obligations with respect to any tax year beginning prior to the notice. MEHC became a party to the tax-allocation agreement with
a wholly owned subsidiary of Edison International on July 2, 2001, when it became part of the Edison International consolidated
filing group. MEHC has historically received tax-allocation payments related to domestic net operating losses incurred by MEHC. The
right of MEHC to receive and the amount and timing of tax-allocation payments are dependent on the inclusion of MEHC in the
consolidated income tax returns of Edison International and its subsidiaries, the amount of net operating losses and other tax items
of MEHC, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state
taxes. MEHC receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group
generates sufficient taxable income in order to be able to utilize MEHC's tax losses in the consolidated income tax returns for
Edison International and its subsidiaries. During the nine-month period ended September 30, 2003, MEHC received $41 million in
tax-allocation payments from Edison International. In the future, based on the application of the factors cited above, MEHC may be
obligated during periods it generates taxable income to make payments under the tax-allocation agreements.
EME's Liquidity Issues
At September 30, 2003, EME and its subsidiaries had cash and cash equivalents of $816 million and EME had available a total of $107
million of borrowing capacity under its $212 million corporate credit facility. EME's consolidated debt at September 30, 2003 was
$6.4 billion, including debt maturing on December 11, 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest
Holdings. In addition, EME's subsidiaries have approximately $7 billion of long-term lease obligations that are due over periods
ranging up to 32 years.
On September 15, 2003, Sunrise Power Company, LLC completed a non-recourse project financing of $345 million. EME received a
distribution of approximately $151 million from the proceeds of this financing. As a result of the successful completion of the
Sunrise project financing, EME repaid the $275 million component of EME's corporate credit facility and retired Tranche A upon its
expiration on September 16, 2003. Tranche B expires on September 17, 2004.
The discussions below include the following matters that affect EME's liquidity: financing plan for $781 million debt maturity,
EME's credit ratings, EME's corporate liquidity, historical distributions received by EME, the ability of EME to pay dividends, EME's
interest coverage and recourse debt to recourse capital ratios, EME's subsidiary financing plans, and EME's intercompany tax-allocation
payments.
Financing Plan for $781 Million Debt Maturity
On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup,
Credit Suisse First Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to
provide bridge financing to asset sales, including the sale of some or all of its international operations, depending upon, among
other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution
of approximately $550 million in Edison Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison
Mission Midwest Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds from this financing will be
used to
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repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Funding of this loan is subject to
completion of definitive documentation and a number of closing conditions, including obtaining certain consents and required
corporate authorizations by MEHC and EME. Completion of this loan is subject to uncertainty and accordingly, there is
no assurance that definitive documentation will be completed and the closing conditions will be fulfilled. For additional discussion
see "--Current Developments--MEHC and EME Developments."
EME's Credit Ratings
Credit ratings for EME and its subsidiaries, Edison Mission Midwest Holdings and Edison Mission Marketing & Trading, are as follows:
Moody's
Rating S&P Rating
- ------------------------------------------------------------------------------------------------------------------------------
EME B2 B
Edison Mission Midwest Holdings Ba3 B
Edison Mission Marketing & Trading Not Rated B
- ------------------------------------------------------------------------------------------------------------------------------
On October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard &
Poor's also lowered the credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan
facility to B from BB-) and Edison Mission Marketing & Trading (corporate credit rating to B from BB-). Standard & Poor's placed the
ratings of all these entities on CreditWatch with negative implications. In addition, Moody's Investors Service has assigned a
negative rating outlook for EME and Edison Mission Midwest Holdings.
These ratings actions did not trigger any defaults under EME's credit facilities or those of the other affected entities. See
"--Credit Rating of Edison Mission Midwest Holdings" for a discussion of the impact of the ratings action on Edison Mission Midwest
Holdings.
The credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and
letters of credit for the benefit of counterparties for its price risk management and domestic trading activities related to accounts
payable and unrealized losses ($40 million as of October 31, 2003). EME has also provided collateral for a portion of its United
Kingdom trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash
collateralized credit facility, under which letters of credit totaling(pound)19 million have been issued as of October 31, 2003.
EME anticipates that sales of power from its Illinois plants, Homer City facilities and First Hydro plants in the United Kingdom may
require additional credit support, depending upon market conditions and the strategies adopted for the sale of this power. Changes
in forward market prices and margining requirements could further increase the need for credit support for the price risk management
and trading activities related to these projects. EME currently projects the potential working capital required to support its price
risk management and trading activity to be between $100 million and $200 million from time to time.
EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any
given period of time or that one or more of these ratings will not be lowered further. EME notes that these credit ratings are not
recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
Page 45
Credit Rating of Edison Mission Midwest Holdings
As a result of Edison Mission Midwest Holdings' credit rating being below investment grade since October 2002, provisions in the
agreements binding on Edison Mission Midwest Holdings and Midwest Generation have restricted the ability of Edison Mission Midwest
Holdings to make distributions to its parent company, thereby eliminating distributions to EME. The provisions in the agreements
binding on Edison Mission Midwest Holdings required it to deposit, on a quarterly basis, 100% of its excess cash flow as defined in
the agreements into a cash flow recapture account held and maintained by the collateral agent. In accordance with these provisions,
Edison Mission Midwest Holdings deposited $78 million into the cash flow recapture account as of September 30, 2003. In October 2003,
Edison Mission Midwest Holdings deposited an additional $168 million based on the calculation of excess cash flow for the three-month
period ended September 30, 2003. The funds in the cash flow recapture account were to be used only to meet debt service obligations
of Edison Mission Midwest Holdings if funds were not otherwise available from working capital.
As a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit
in the cash flow recapture account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to
prepay that indebtedness, with the amount of such prepayment applied ratably to the $911 million and $808 million tranches thereof.
Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million tranche, and $116
million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and $692
million, respectively. In the future, so long as Edison Mission Midwest Holdings' ratings remain at the current level or lower,
amounts of excess cash flow deposited in the cash flow recapture account at the end of each calendar quarter will be used upon
deposit to prepay, pro rata, amounts then outstanding under these bank facilities. There was no change to the cost of borrowings for
Edison Mission Midwest Holdings as a result of the downgrade.
As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.4 billion) to EME
in exchange for promissory notes in the same aggregate amount. Debt service payments by EME on the promissory notes may be used by
Midwest Generation to meet its payment obligations under these leases in whole or part. 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 corporate obligations of EME and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See
"--Restricted Assets of EME's Subsidiaries--Edison Mission Midwest Holdings (Illinois Plants)" for a discussion of implications for the
Powerton and Joliet leases.
Credit Rating of Edison Mission Marketing & Trading
Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading
restricts the ability of EME Homer City Generation L.P. (EME Homer City) to enter into permitted trading activities, as defined in
the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities. These documents
include a requirement that the counterparty to such transactions, and EME Homer City, 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, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue
to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner
participant to permit EME Homer City 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 requirements of the sale-leaseback documents.
EME has obtained consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under
specified conditions, through December 31, 2004. EME Homer City continues to be in
Page 46
compliance with the terms of the consent, although as a result of the recent downgrade of Edison Mission Marketing & Trading's
corporate credit rating to B from BB-, the consent is now revocable. The owner participant has not indicated that it intends to
revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not
affect trades between Edison Mission Marketing & Trading and EME Homer City that had been entered into while the consent was still in
effect. EME is permitted to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool (PJM)
market at any time on a spot-market basis. See "Market Risk Exposures--EME's Market Risks--Homer City Facilities."
EME Corporate Liquidity
EME has a $212 million corporate credit facility that expires on September 17, 2004. At September 30, 2003, EME had borrowing
capacity of $107 million and corporate cash and cash equivalents of $158 million.
Cash distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused
capacity under its corporate credit facility represent EME's major sources of liquidity to meet its cash requirements. EME expects
its cash requirements during the next twelve months to be primarily comprised of:
o $188 million in principal payments due under the Coal and Capex facility,
o interest payments on its indebtedness, including interest payments to Midwest Generation related to intercompany loans,
o collateral requirements in the form of letters of credit or cash margining in support of forward contracts for the sale of
power from its merchant energy operations, and
o general administrative expenses.
The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "--Historical
Distributions Received by EME--Restricted Assets of EME's Subsidiaries." In addition, the right of EME to receive tax-allocation
payments, and the timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See
"--EME's Intercompany Tax-Allocation Payments." If EME's corporate credit facility is not refinanced or additional financing is not
obtained on or before September 17, 2004, EME's ability to provide credit support for bilateral contracts for power and fuel related
to its merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the
number of counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely
on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining
requirements if forward prices for power increase significantly. Failure to meet a margining requirement would permit the
counterparty to terminate the related bilateral contract early and demand immediate payment of damages incurred by reason of such
termination.
EME's corporate credit facility provides credit available in the form of cash advances or letters of credit. At September 30, 2003,
$105 million of letters of credit were outstanding under Tranche B. In addition to the interest payments, EME pays a facility fee
determined by its long-term credit ratings (1.00% at September 30, 2003) on the entire credit facility independent of the level of
borrowings.
Under the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash
received by EME, including tax-allocation payments, cash disbursements and
Page 47
interest paid. At September 30, 2003, EME met this interest coverage ratio. The interest coverage ratio in the ring-fencing
provisions of EME's certificate of incorporation and bylaws remains relevant for determining EME's ability to make distributions.
See "--EME's Interest Coverage Ratio."
EME has entered into sale agreements with third parties for its interests in the Gordonsville project and a development project in
Thailand, which are expected to be completed prior to December 31, 2003. EME is considering the sale of additional investments,
including its interests in the EcoElectrica and Brooklyn Navy Yard projects and in Four Star Oil & Gas, and plans to consider the
sale of some or all of its international operations depending on, among other things, market prices. EME's management has not
committed to the sale of any specific project other than the Gordonsville project and the development project in Thailand. There is
no assurance that EME will complete the sale of the assets mentioned above, or any other assets, and no assurance that any sales
completed will be on terms that recover EME's investment in these projects.
Historical Distributions Received by EME
The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies which
depend on distributions from subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse
debt. Distributions for the first nine months of each year are not necessarily indicative of annual distributions due to the
seasonal fluctuations in EME's business.
In millions Nine Months Ended September 30, 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) (1) $ 102 $ --
Holding companies of other consolidated operating projects 87 21
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 projects)(2) 74 112
Four Star Oil & Gas Company 15 21
Holding companies of other unconsolidated operating projects(3) 112 66
- -----------------------------------------------------------------------------------------------------------------------------------
Total Distributions $ 390 $ 220
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Excludes $48 million distributed by EME Homer City from additional cash on hand due to accelerated payments received
from its marketing affiliate, Edison Mission Marketing & Trading.
(2) Distributions do not include either capital contributions made during the California energy crisis or the subsequent
return of such capital. Distributions reflect the amount received by EME after debt service payments by Edison Mission
Energy Funding Corp.
(3) Includes $59 million of the $151 million proceeds from the Sunrise project financing. The remaining $92 million EME has
classified as a return of capital.
Total distributions to EME increased due to:
o Distributions from Homer City due to increased generation and higher energy prices. The project did not make any
distributions in the first three quarters of 2002 because of outages in the first half of 2002;
o Distribution of $18 million from the First Hydro project in May 2003. The project did not make any distributions in the
first three quarters of 2002 due to restrictions under its bond indenture;
o Distribution of $18 million from the Doga project in July 2003. The project did not make any distributions until the fourth
quarter of 2002;
o Increased shareholder dividends from Contact Energy;
Page 48
o Distributions of $21 million from the Loy Yang B project in 2003. Restrictions on distribution from the
Loy Yang B project were removed following completion of the refinancing of the Valley Power Peaker project
construction loan in 2002; and
o Initial distributions from the Sunrise project upon completion of project financing.
Partially offset by:
o Lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due
accounts receivable that accrued during the California energy crisis); and
o Lower Four Star dividends due to the repayment of project level debt.
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 EME's 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 its subsidiary holding companies.
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 Co. (Illinois Plants)
Edison Mission Midwest Holdings Co. 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, a wholly owned subsidiary of Edison
Mission Midwest Holdings, owns or leases and operates the Illinois plants. As part of the original acquisition,
Midwest Generation entered into a sale-leaseback transaction for the Collins Station, which Edison Mission
Midwest Holdings guarantees, and then subsequently entered into sale-leaseback transactions for the Powerton
Station and the Joliet Station in August 2000. In order for Edison Mission Midwest Holdings to make a
distribution, Edison Mission Midwest Holdings and Midwest Generation must be in compliance with the covenants
specified in these agreements, including maintaining a minimum credit rating. Because Edison Mission Midwest
Holdings' credit rating is below investment grade, no distributions can currently be made by Edison Mission
Midwest Holdings to its parent company, and ultimately to EME, at this time. See "--EME's Credit Ratings."
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 Exelon Generation represent 50% or
more of Edison Mission Midwest Holdings' and its subsidiaries' revenue. If the power purchase agreements with
Exelon Generation represent less than 50% of Edison Mission Midwest Holdings' and its subsidiaries' revenue, it
must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that revenue for 2003 from Exelon
Generation will represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenue. In
addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater than 0.60 to 1.
Failure to meet the historical debt service coverage ratio and the debt-to-capital ratio are events of default
under the credit agreement and Collins lease agreements, which, upon a vote by a majority of the lenders, could
cause an acceleration of the due date of the obligations of Edison Mission Midwest Holdings and those associated
with the Collins lease. Such acceleration would result in an event of default under the Powerton and
Page 49
Joliet leases. During the 12 months ended September 30, 2003, the historical debt service coverage ratio was
2.31 to 1 and the debt-to-capital ratio was 0.52 to 1.
There are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany
loans from its affiliate Edison Mission Overseas Co. (which is also a subsidiary of Edison Mission Midwest
Holdings) or to make distributions directly to Edison Mission Midwest Holdings.
EME Homer City Generation L.P. (Homer City facilities)
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 requirement measured on the date of distribution:
o At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period
(taken as a whole) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all
income and receipts of EME Homer City less amounts paid for operating expenses, required capital
expenditures, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus
fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of
credit.
At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The
senior rent service coverage ratio (discussed in the bullet point above) projected for each of the prospective
two twelve-month periods must be greater than 1.7 to 1. 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.
During the 12 months ended September 30, 2003, the senior rent service coverage ratio was 4.53 to 1.
First Hydro Holdings
A subsidiary of First Hydro Holdings, First Hydro Finance plc, has issued(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 an interest coverage ratio. When measured for the twelve-month period
ended December 31, 2002, First Hydro Holdings met the interest coverage ratio and made a distribution of
$18 million on May 7, 2003. When measured for the twelve-month period ended June 30, 2003, First Hydro Holdings'
interest coverage ratio was 1.49 to 1.
On March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds,
requesting that First Hydro Finance engage in a process to determine whether an early redemption option in favor
of the bondholders has been triggered under the terms of the First Hydro bonds. This letter states that, given
requests made of the trustee by a group of First Hydro bondholders, the trustee needs to satisfy itself whether
the termination of the pool system in the United Kingdom (replaced with the new electricity trading arrangements,
referred to as NETA), was materially prejudicial to the interests of the bondholders. If this were the case, it
could provide the First Hydro bondholders with an early redemption option. In this regard, on August 29, 2000,
First Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the
foundation for NETA, would result, after its implementation, in a so-called restructuring event under the terms
of the First Hydro bonds. However, First Hydro Finance did not believe then, nor does it believe now, that this
event was materially prejudicial to the First Hydro bondholders. Since NETA implementation, First Hydro Finance
has continued to meet all of its debt service obligations and financial covenants under the bond documentation,
including the required interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First
Hydro Finance had not received a response from the trustee to its August 29, 2000
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notice. First Hydro Finance will dispute any attempt to have the early redemption option deemed applicable due
to NETA implementation.
Neither the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee
constitutes an event of default under the terms of the First Hydro bonds, and there is no recourse to EME for the
obligations of First Hydro Finance in respect of the First Hydro bonds. However, if the bondholders were
entitled to an early redemption option, First Hydro Finance would be obligated to purchase all First Hydro bonds
put to it by bondholders at par plus an early redemption premium. If all bondholders opted for the early
redemption option, it is unlikely that First Hydro Finance would have sufficient financial resources to so
purchase the bonds. There is no assurance that First Hydro Finance would be able to obtain additional financing
to fund the purchase of the First Hydro bonds. Therefore, an exercise of the early redemption option by the
bondholders could lead to administration proceedings as to First Hydro Finance in the United Kingdom, which are
similar to Chapter 11 bankruptcy proceedings in the United States. If these events were to occur, they would
have a material adverse effect upon First Hydro Finance and could have a material adverse effect upon EME.
Edison Mission Energy Funding Corp. (Big 4 Projects)
EME's subsidiaries, which EME refers to in this context as the guarantors, that hold EME's 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 cash proceeds from
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 trust accounts 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 the
guarantors and Edison Mission Energy Funding are in compliance with the terms of the covenants in their financing
documents, including the following requirements measured on the date of distribution:
o The debt service coverage ratio for the preceding four fiscal quarters is at least 1.25 to 1.
o The debt service coverage ratio projected for the succeeding four fiscal quarters is at least 1.25 to 1.
The debt service coverage ratio is determined primarily based upon 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. During the
12 months ended September 30, 2003, the debt service coverage ratio was 2.55 to 1. Although the credit ratings of
Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the ability of
the guarantors to make distributions to EME.
CBK Project
EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year
build-rehabilitate-operate-transfer agreement with National Power Corporation for the 756 MW
Caliraya-Botocan-Kalayaan hydro electric complex, located in the Republic of the Philippines, which EME refers to
as the CBK project. On April 23, 2003, the President of the Republic of the Philippines signed into law the 2003
General Appropriations Act, which included a provision that stopped payments for two of the Kalayaan units by
agencies of the Philippine government to CBK Power until specific conditions were met. On May 22, 2003, CBK
Power and National Power Corporation, with the concurrence of Power Sector Assets and Liabilities Management
Corporation (PSALM), entered into a settlement agreement. PSALM is a Philippine government-owned entity with
responsibility for the electric power sector. The settlement agreement provides for specific concessions to
National Power Corporation which have been deemed by the parties to satisfy the conditions included in the
General Appropriations Act.
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The Secretary of Management and Budget confirmed to National Power Corporation that payments could be made to CBK
Power using funds provided by the 2003 General Appropriations Act based on National Power Corporation's
determination that the requirements of those provisions have been met. National Power Corporation has cleared
all arrears owing to CBK Power and has made all payments since the signing of the settlement agreement in a
timely manner. CBK Power has obtained its lender's consent to the modification to the
build-rehabilitate-operate-transfer agreement.
Ability of EME to Pay Dividends
EME's organizational documents contain restrictions on its ability to declare or pay dividends or distributions.
These restrictions require the unanimous approval of its board of directors, including at least one independent
director, before it can declare or pay dividends or distributions, unless either of the following is true:
o EME then has investment grade ratings with respect to its senior unsecured long-term debt and receives
rating agency confirmation that the dividend or distribution will not result in a downgrade; or
o such dividends and distributions do not exceed $32.5 million in any fiscal quarter and EME then meets an
interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters.
EME's interest coverage ratio for the twelve months ended September 30, 2003 was 2.10 to 1. See further details
of EME's interest coverage ratio below. Accordingly, EME is not permitted to pay dividends in the fourth quarter
of 2003 under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws without unanimous
board approval. EME did not pay or declare any dividends to MEHC during the first nine months of 2003.
EME's Interest Coverage Ratio
The following details of EME's interest coverage ratio are provided as an aid to understanding the components of
the computations that are set forth in EME's organizational documents. This information is not intended to
measure the financial performance of EME and, accordingly, should not be used in lieu of the financial
information set forth in Edison International's consolidated financial statements. The terms Funds Flow from
Operations, Operating Cash Flow and Interest Expense are as defined in EME's organizational documents and are not
the same as would be determined in accordance with generally accepted accounting principles.
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The following table sets forth the major components of the interest coverage ratio:
Twelve Months Ended Year Ended
September 30, December 31,
In millions 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants(3) $ 170 $ 294
Homer City 142 51
First Hydro (30) 47
Other consolidated operating projects 170 158
Price risk management and energy trading 13 16
Distributions from unconsolidated Big 4 projects 100 137
Distributions from other unconsolidated operating projects 159 120
Interest income 6 8
Operating expenses (139) (139)
- -------------------------------------------------------------------------------------------------------------------
Total funds flow from operations $ 591 $ 692
- -------------------------------------------------------------------------------------------------------------------
Interest Expense:
From obligations to unrelated third parties $ 168 $ 178
From notes payable to Midwest Generation 113 115
- -------------------------------------------------------------------------------------------------------------------
Total interest expense $ 281 $ 293
- -------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 2.10 2.36
- -------------------------------------------------------------------------------------------------------------------
(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 the 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 the consolidated financial statements. Unconsolidated
operating projects are entities of which EME owns 50% or less and which EME accounts for on the equity
method.
(3) Distribution to EME of funds flow from operations of the Illinois plants is currently restricted.
See "--EME's Credit Ratings--Credit Rating of Edison Mission Midwest Holdings."
The major factors affecting funds flow from operations during the twelve months ended September 30, 2003,
compared to the year ended December 31, 2002, were:
o lower earnings at the Illinois plants primarily due to lower capacity revenue from the reduction in MW
contracted under the power purchase agreements;
o repayment of $29 million debt service reserve loan and loss on price risk management activities at First
Hydro;
o lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due
accounts receivable that accrued during the California energy crisis);
o higher revenue at Homer City due to increased generation and higher energy prices; and
o distributions from the Sunrise project upon completion of project financing.
EME's interest expense decreased by $12 million for the twelve months ended September 30, 2003, compared to the
year ended December 31, 2002 due to a lower average debt balance.
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The above interest coverage ratio is not determined in accordance with generally accepted accounting principles
as reflected in the consolidated statements of cash flows. Accordingly, this ratio should not be considered in
isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in
the consolidated statement of cash flows. This ratio does not measure the liquidity or ability of EME's
subsidiaries to meet their debt service obligations. Furthermore, this ratio is not necessarily comparable to
other similarly titled captions of other companies due to differences in methods of calculations.
EME's Recourse Debt to Recourse Capital Ratio
Under the credit agreement governing its credit facility, EME has agreed to maintain a recourse debt to recourse
capital ratio as shown in the table below.
Actual at
Financial Ratio Covenant September 30, 2003 Description
- ----------------------------------------------------------------------------------------------------------------
Recourse Debt to Less than or 61.6% Ratio of (a) senior recourse debt to (b)sum
Recourse Capital equal to of (i) shareholder's equity per EME's
Ratio 67.5% balance sheet adjusted by comprehensive
income after December 31, 1999, plus (ii)
senior recourse debt
- ----------------------------------------------------------------------------------------------------------------
Discussion of Recourse Debt to Recourse Capital Ratio
The recourse debt to recourse capital ratio of EME at September 30, 2003 and December 31, 2002 was calculated as
follows:
September 30, December 31,
In millions 2003 2002
- ----------------------------------------------------------------------------------------------------------
Recourse Debt(1)
Corporate Credit Facilities $ 108 $ 140
Senior Notes 1,600 1,600
Guarantee of termination value of Powerton/Joliet
operating leases 1,441 1,452
Coal and Capex Facility 188 182
Other -- 30
- ----------------------------------------------------------------------------------------------------------
Total Recourse Debt to EME $ 3,337 $ 3,404
- ----------------------------------------------------------------------------------------------------------
Adjusted Shareholder's Equity(2) $ 2,084 $ 2,066
- ----------------------------------------------------------------------------------------------------------
Recourse Capital(3) $ 5,421 $ 5,470
- ----------------------------------------------------------------------------------------------------------
Recourse Debt to Recourse Capital Ratio 61.6% 62.2%
- ----------------------------------------------------------------------------------------------------------
(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.
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During the nine months ended September 30, 2003, the recourse debt to recourse capital ratio decreased due to:
o reduction in letters of credit outstanding under the corporate line of credit;
o repayment of the Compagnie Generale Des Eaux loan associated with the Spanish Hydro project; and
o an increase in adjusted shareholder's equity as a result of $17 million net income for the nine months
ended September 30, 2003.
EME's indirect subsidiary, Midwest Generation, reported in its second quarter of 2003 an asset impairment charge
of $475 million, after tax, related to the 2,698 MW gas-fired Collins Station. The impairment charge resulted
from a write-down of the book value of capitalized assets related to the Collins Station from $858 million to an
estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the
operating results of EME because the lease related to the Collins Station is treated in EME's financial
statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting
purposes. EME is evaluating a number of debt restructuring alternatives, some of which could result in the
consolidation of the Collins Station and recognition of a loss in the consolidated accounts of EME. A
restructuring alternative that results in the consolidation of the Collins Station would require EME to obtain
modifications to net worth covenants contained in its credit facilities and the guarantee it provides to the
owner participants in the Powerton and Joliet sale-leaseback.
EME's Subsidiary Financing Plans
The estimated capital and construction expenditures of EME's subsidiaries for the fourth quarter of 2003 are
$21 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 to complete the
Homer City environmental improvement project. EME expects to contribute $24 million in 2003 to fund the
completion of this project, of which $21 million was contributed during the first nine months of 2003.
Edison Mission Midwest Holdings
As a result of the downgrade of the credit rating of Edison Mission Midwest Holdings by Standard & Poor's (see
"--EME's Credit Ratings--Credit Rating of Edison Mission Midwest Holdings"), Edison Mission Midwest Holdings repaid
$246 million on October 29, 2003 under its credit agreements with commercial lenders from funds deposited in the
cash flow recapture account. The following table summarizes Edison Mission Midwest Holdings' debt maturities:
Paid From
September 30, Cash Flow Balance After
In millions 2003 Recapture Account Payment Due Date
- --------------------------------------------------------------------------------------------------------------
$ 911 $ (130) $ 781 December 11, 2003
808 (116) 692 December 15, 2004
- --------------------------------------------------------------------------------------------------------------
$ 1,719 $ (246) $ 1,473
- --------------------------------------------------------------------------------------------------------------
In addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused) which is
scheduled to expire on December 15, 2004. Edison Mission Midwest Holdings has $781 million of debt maturing on
December 11, 2003, which will need to be repaid, extended or
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refinanced. Edison Mission Midwest Holdings does not have sufficient cash to repay this indebtedness when due.
On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from
Citigroup, Credit Suisse First Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700
million secured loan intended to provide bridge financing to asset sales, including the sale of some or all of
its international operations, depending upon, among other things, market prices. Subject to completion, the net
proceeds from this financing will be used to make an equity contribution of approximately $550 million in Edison
Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission Midwest
Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds from this financing will
be used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME.
Funding of this loan is subject to completion of definitive documentation and a number of closing conditions,
including obtaining certain consents and required corporate authorizations by MEHC and EME.
Completion of this loan is subject to uncertainty and accordingly, there is no assurance that definitive
documentation will be completed and the closing conditions will be fulfilled. For additional discussion see
"--Current Developments--MEHC and EME Developments."
Loy Yang B
On October 31, 2003, an affiliate of EME entered into an A$65 million subordinated amortizing facility consisting
of a six-year A$50 million letter of credit facility and a six-year A$15 million amortizing cash facility. The
letter of credit issued under the letter of credit facility replaces an A$50 million letter of credit outstanding
under EME's corporate credit facility at September 30, 2003, which was due to expire in September 2004, thereby
increasing EME's borrowing capacity under its corporate credit facility. Drawings under the amortizing cash
facility will be used to prepay indebtedness of EME coming due in 2004.
EME's Intercompany Tax-Allocation Payments
EME is included in the consolidated federal and combined state income tax returns of Edison International and is
eligible to participate in tax-allocation payments with other subsidiaries of Edison International. These
arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the voting
power of the stock of EME and at least 80% of the value of such stock. A foreclosure by MEHC's financing parties
on EME's stock would make EME ineligible to participate in the tax-allocation payments. The arrangements are
subject to the terms of tax-allocation and payment agreements among Edison International, MEHC, EME and other
Edison International subsidiaries. The agreements to which EME is a party may be terminated by the immediate
parent company of MEHC at any time, by notice given before the first day of the first tax year with respect to
which the termination is to be effective. However, termination does not relieve any party of any obligations
with respect to any tax year beginning prior to the notice. EME has historically received tax-allocation
payments related to domestic net operating losses incurred by EME. The right of EME to receive and the amount
and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax
returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income
of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its
subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of
state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated
Edison International group generates sufficient taxable income in order to be able to utilize EME's tax losses in
the consolidated income tax returns for Edison International and its subsidiaries. During the nine-month period
ended September 30, 2003, EME received $89 million in tax-allocation payments from Edison International. In the
future, based on the application of the factors cited above, EME may be obligated during periods it generates
taxable income to make payments under the tax-allocation agreements.
Page 56
Edison Capital's Liquidity Issues
Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation payments from the
parent company and expected cash flow from operating activities. As of September 30, 2003, Edison Capital had
cash and cash equivalents of $488 million and current liabilities of approximately $114 million. In October
2003, Edison Capital paid a $225 million cash dividend to Edison International. To the extent that specific
funding conditions are satisfied, Edison Capital has unfunded current and long-term commitments of $93 million
for both affordable housing projects, and energy and infrastructure investments. Under the tax-allocation
agreement, Edison Capital received $43 million in tax-allocation payments from Edison International during the
nine-month period ended September 30, 2003 and an additional $32 million in October 2003. The amount received is
net of payments made to Edison International, as Edison International amended its 2001 federal income tax return,
which deferred realization of certain tax credits to future periods. See "Financial Condition--Edison Capital's
Intercompany Tax-Allocation Payments" section in the year-ended 2002 MD&A for further discussion of the
tax-allocation agreement. At September 30, 2003, Edison Capital's long-term debt had credit ratings of B2 and B-
from Moody's and Standard & Poor's, respectively.
COMMITMENTS
The following is an update to Edison International's estimated commitments. See the "Commitments" section in the
year-ended 2002 MD&A for a more detailed discussion of commitments.
Edison International's long-term debt maturities and sinking-fund requirements for the five twelve-month periods
following September 30, 2003 are: 2004-- $2.3 billion; 2005-- $2.3 billion; 2006-- $977 million; 2007-- $1.7
billion; and 2008-- $1.3 billion. These amounts have been updated to reflect SCE's $966 million exchange offer
that took place on February 24, 2003.
SCE has entered into six transition-capacity contracts during 2003, which contain capacity payment provisions.
SCE's commitments under these contracts for the five twelve-month periods following September 30, 2003 are: 2004
- --$69 million; 2005-- $69 million; 2006-- $69 million; 2007-- $70 million; and 2008-- $17 million.
Midwest Generation has entered into additional fuel purchase agreements with several third-party suppliers during
the first nine months of 2003. Midwest Generation's aggregate fuel purchase commitments under these agreements
are estimated to be: 2003-- $39 million; 2004-- $199 million; 2005-- $195 million; 2006-- $89 million; and 2007
- --$91 million.
MARKET RISK EXPOSURES
Edison International's primary market risks include commodity price, interest rate and foreign currency
exchange. Commodity price risk arises from fluctuations in the market price of electricity, natural gas, coal,
and emission and transmission rights. Interest rate risk arises from fluctuations in interest rates. 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's Market Risks
SCE's primary market risks include interest rate, generating fuel commodity price and volume and counterparty
credit.
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Interest Rate Risk
SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as to finance capital expenditures. The nature
and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors. In addition, SCE's authorized return on common equity is set
based on forecasts of interest rates and other factors.
Commodity Price and Volume Risk
SCE recovers its reasonable power procurement costs through regulatory mechanisms established by the CPUC.
Assembly Bill (AB) 57 provides that the CPUC shall adjust rates, or order refunds, to amortize undercollections
or overcollections of power procurement costs. Until January 1, 2006, the CPUC must adjust rates if the
undercollection or overcollection exceeds 5% of SCE's prior year's procurement costs, excluding revenue collected
for CDWR. As a result of these regulatory mechanisms, changes in energy prices may impact SCE's cash flows but
are not expected to have an impact on earnings.
On January 1, 2003, SCE resumed procurement of its residual net short. SCE forecasts that its average 2003
residual net short, on an energy basis, will be approximately 5% of the total energy needed to serve SCE's
customers, with most of the short position occurring during off-peak hours and on weekends. During 2004, SCE's
expects its residual net short to decline and its residual net long position to increase. SCE's growing residual
net long position arises from an expected increase in deliveries under CDWR contracts allocated to SCE's
customers. In its 2004 procurement plan, currently under review by the CPUC, SCE has incorporated a price and
volume forecast from expected sales of residual net long power. If actual prices or volumes vary from forecast,
SCE's cash flow would be impacted. However, sales of residual power would not affect SCE's earnings. Factors
that could cause SCE's 2003 and 2004 residual net short to be larger than expected include: direct access
customers returning to utility service from their energy service provider; lower utility generation; lower
deliveries from QFs, CDWR or interutility contracts; and higher load requirements.
To reduce SCE's residual net short exposure, SCE entered into six transition capacity contracts with terms of up
to five years. Through fuel tolling arrangements, SCE is responsible for providing natural gas when the
underlying contract facilities are called upon to provide energy. SCE anticipates it will need to purchase
additional capacity and/or ancillary services to hedge its peak-energy requirements in 2003 and 2004.
Pursuant to CPUC decisions, SCE, as CDWR's limited agent, arranges for natural gas and related services for CDWR
contracts allocated by the CPUC to SCE. Financial and legal responsibility for the allocated contracts remains
with CDWR. CDWR, through the coordination of SCE, has hedged a portion of its expected natural gas requirements
for certain contracts allocated to SCE. To the extent the price of natural gas were to increase above the levels
assumed for cost recovery purposes, state law permits CDWR to recover its actual costs through rates established
by the CPUC.
SCE purchases power from QFs under CPUC state-mandated contracts. Contract energy prices for most non-renewable
QFs are tied to the southern California border price of natural gas established on a monthly basis. During 2003,
SCE substantially hedged the risk of increasing natural gas prices. In its 2004 procurement plan, SCE has
requested CPUC authority to hedge its QF natural gas price risk. In October 2003, the CPUC issued a decision
that granted SCE interim authorization to hedge its first and second quarter 2004 natural gas price risks for its
existing QF contracts. Authority for any hedging beyond second quarter 2004, is being considered with SCE's
short-term resource plan described in "SCE's Regulatory Matters--Generation Procurement Proceedings."
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Credit Risks
Credit risk arises primarily due to the chance that a counterparty under various purchase and sale contracts will
not perform as agreed or pay SCE for energy products delivered. SCE uses a variety of techniques to mitigate its
exposure to credit risk. These include restricting unsecured exposures to highly rated entities and securing
collateral from all others whenever possible. Such collateral may take many forms including cash from the
counterparty itself, payment guarantees or letters of credit from highly rated entities, and making purchases
from the counterparty which act to offset sales. SCE has established a risk management committee which regularly
reviews procurement credit exposure and approves credit limits for transacting with counterparties. Despite
these efforts, there can be no assurance that SCE's actions to mitigate credit risk will be wholly successful or
that collateral pledged will be adequate. SCE follows the credit limits established in its CPUC-approved
procurement plan, and, as such, believes that any losses which may occur, despite prudent credit management
practices, should be fully recoverable from ratepayers.
MEHC's (stand alone) Market Risks
Changes in interest rates can have an impact on MEHC's results of operations. MEHC is exposed to changes in
interest rates primarily as a result of its borrowing activities.
Interest Rate Risk
MEHC has mitigated the risk of interest rate fluctuations associated with the $385 million term loan due 2006 by
arranging for variable rate financing with interest rate swaps. Swaps covering interest accrued from January 2,
2002 to January 2, 2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that cover interest
accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to July 2, 2004.
The fair market value of MEHC's (stand alone) total long-term obligations was $1.0 billion at September 30, 2003,
compared to the carrying value of $1.2 billion.
EME's Market Risks
This subsection discusses commodity price risk at each of EME's market areas, as well as its risks associated
with credit, interest rates, foreign exchange rates and derivative financial instruments.
EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel
for its uncontracted generating plants. These risks arise from fluctuations in electricity and fuel prices,
emission allowances, transmission rights, interest rates and foreign currency exchange rates. EME manages these
risks in part by using derivative financial instruments in accordance with established policies and procedures.
See "Current Developments--MEHC and EME Developments" and "Financial Condition--EME's Liquidity Issues--EME's Credit
Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its
counterparties.
Commodity Price Risk
EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price
risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place,
which define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of
all commitments and positions with regular reviews by a risk management committee. 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
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fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There
is no assurance that contracts to hedge changes in market prices will be effective.
EME's revenue and results of operations 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
o the rate of electricity usage as a result of factors such as regional economic conditions and the
implementation of conservation programs.
A discussion of each market area is set forth below.
EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market
risk exposure in respect of its Illinois plants, its Homer City facilities, its Four Star investment, and its
proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare
risk on a consistent basis and identify the risk factors. Value at risk measures the possible 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 for key risk factors, as well as stop loss limits and counterparty
credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified,
measured and/or mitigated.
Electric power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with
utilities and power marketers under short-term transactions with terms of two years or less or, in the case of
the Homer City facilities, to the PJM and/or the New York Independent System Operator (NYISO) as well as
utilities and power marketers. As discussed further below, beginning in 2003, EME has been selling a significant
portion of the power generated from its Illinois Plants into wholesale energy markets.
Illinois Plants
Electric power generated at the Illinois plants has historically been sold under three power purchase agreements
between EME's wholly owned subsidiary, Midwest Generation, and Exelon Generation Company, under which Exelon
Generation purchases capacity and has the right to purchase energy
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generated by the Illinois plants. The agreements, which began on December 15, 1999 and expire in December 2004,
provide for capacity and energy payments. Exelon Generation 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 Exelon
Generation. The capacity payments provide the revenue for fixed charges, and the energy payments compensate the
Illinois plants for all, or a portion of, variable costs of production.
Under each of the power purchase agreements, Exelon Generation, upon notice by given dates, had the option to
terminate each agreement with respect to all or a portion of the units subject to it. As a result of notices
given in 2002, effective January 1, 2003, Exelon Generation released 4,548 MW of Midwest Generation's generating
capacity from the power purchase agreements, thus increasing Midwest Generation's reliance on sales into the
wholesale markets. As a result, 4,739 MW of capacity remain subject to power purchase agreements with Exelon
Generation in 2003.
Exelon Generation notified Midwest Generation on June 25, 2003 of the exercise of its option to contract 687 MW
of capacity and the associated energy output (out of a possible total of 1,265 MW subject to the option) during
2004 from Midwest Generation's coal-fired units in accordance with the terms of the existing power purchase
agreement related to Midwest Generation's coal-fired generation units. As a result, 578 MW of the capacity of
these units will no longer be subject to the power purchase agreement beginning January 1, 2004. The
notification received from Exelon Generation has no effect on its commitments to purchase capacity from these
generating units for the balance of 2003. For 2004, Exelon Generation will have 2,383 MW of capacity related to
its coal-fired generation units under contract with Midwest Generation.
On October 1, 2003, Exelon Generation notified Midwest Generation of the exercise of its option to retain under a
power purchase agreement for calendar year 2004 the 1,084 MW of capacity and energy from Midwest Generation's
Collins Station currently under contract for calendar year 2003. Exelon Generation also exercised its option to
release from a related power purchase agreement 302 MW of capacity and energy (out of a possible total of 694 MW
subject to the option) from Midwest Generation's natural gas and oil-fired peaking units, thereby retaining under
that contract 392 MW of the capacity and energy of such units for calendar year 2004. The notification received
from Exelon Generation has no effect on its commitments to purchase capacity from these peaking units for the
balance of 2003.
As a result of notices given in 2003, as described above, effective January 1, 2004, Exelon Generation released
an additional 880 MW of generating capacity leaving 3,859 MW of capacity to remaining subject to the power
purchase agreements with Exelon Generation in 2004.
The energy and capacity from any units which are not subject to one of the power purchase agreements with Exelon
Generation 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. These arrangements generally
have a term of two years or less. Thus, EME is subject to market risks related to the price of energy and
capacity described above. EME expects that capacity prices for merchant energy sales will, in the near term, be
negligible in comparison to those Midwest Generation currently receives under its existing agreements with Exelon
Generation (the possibility of minimal revenue is due to the current oversupply conditions in this marketplace).
EME further expects that the lower revenue resulting from this difference will be offset in part by energy
prices, which EME believes will, in the near term, be higher for merchant energy sales than those Midwest
Generation currently receives under its existing agreements, as indicated below in the table of forward-looking
prices. EME intends to manage this price risk, in part, by accessing both the wholesale customer and
over-the-counter markets described below as well as using derivative financial instruments in accordance with
established policies and procedures.
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During 2003 and 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from
the Illinois plants are expected to be "wholesale customer" and "over-the-counter." The most liquid
over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into
Cinergy," and, to a lesser extent, sales into the control area of Commonwealth Edison, referred to as "Into
ComEd" (due to geographic proximity, "Into ComEd" has been the primary market for Midwest Generation). "Into
Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future
delivery. Performance of transactions in these markets is subject to contracts that generally provide for
liquidated damages supported by a variety of credit requirements, which may include independent credit
assessment, parent company guarantees, letters of credit, and cash margining arrangements.
The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and
"Into Cinergy" for the first nine months of 2003:
Into ComEd* Into Cinergy*
----------------------------------- -------------------------------------
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- ----------------------------------------------------------------------------------------------------------------
January $ 42.62 $ 20.77 $ 30.81 $ 44.38 $ 21.46 $ 32.00
February 54.43 23.13 37.81 58.09 24.00 39.99
March 47.96 22.35 33.92 51.68 24.34 36.69
April 39.12 15.05 26.67 41.12 15.96 28.11
May 29.59 10.80 19.57 28.89 10.68 19.18
June 30.27 8.17 19.22 28.41 8.31 18.36
July 41.63 12.81 27.07 39.15 11.72 25.29
August 48.75 13.84 29.61 48.80 13.53 29.46
September 27.44 9.85 17.67 28.07 10.36 18.23
- ----------------------------------------------------------------------------------------------------------------
Nine Month Average $ 40.20 $ 15.20 $ 26.93 $ 40.95 $ 15.60 $ 27.48
- ----------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through
Friday, excluding North American Electric Reliability Council (NERC) holidays. All other
hours of the week are referred to as off-peak.
* Source: Energy prices were determined by obtaining broker quotes and other public price
sources, for both "Into ComEd" and "Into Cinergy" delivery points.
Page 62
The following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into
ComEd" and "Into Cinergy" at September 30, 2003. 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.
Into ComEd* Into Cinergy*
----------------------------------- -------------------------------------
Forward Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- ----------------------------------------------------------------------------------------------------------------
2003
----
October $ 24.00 $ 13.50 $ 20.67 $ 25.10 $ 14.50 $ 21.98
November 27.30 16.50 21.06 29.87 17.00 22.43
December 31.10 17.50 23.94 33.77 18.00 25.46
2004 Calendar "strip"(2) 33.64 15.95 24.24 35.95 18.10 26.46
- ----------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through
Friday, excluding NERC holidays. All other hours of the week are referred to as off-peak.
(2) Market price for energy purchases for the entire calendar year, as quoted for sales "Into
ComEd" and "Into Cinergy."
* Source: Energy prices were determined by obtaining broker quotes and other public price
sources, for both "Into ComEd" and "Into Cinergy" delivery points.
Midwest Generation intends to hedge a portion of its merchant portfolio risk through its marketing affiliate. To
the extent it does not do so, the unhedged portion will be subject to the risks and benefits of spot market price
movements. The extent to which Midwest Generation will hedge its market price risk through forward
over-the-counter sales depends on several factors. First, Midwest Generation will evaluate over-the-counter
market prices to determine whether sales at forward market prices are sufficiently attractive compared to
assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging
transactions will depend upon its and its marketing affiliate's credit capacity and upon the over-the-counter
forward sales markets having sufficient liquidity to enable Midwest Generation to identify counterparties who are
able and willing to enter into hedging transactions with it. Due to factors beyond Midwest Generation's control,
market liquidity has decreased significantly since the beginning of 2002 and a number of formerly significant
trading parties have completely withdrawn from the market or substantially reduced their trading activities. See
"--Credit Risks" below.
In addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of
electricity from the released units will be affected by the cost of production, including costs incurred to
comply with environmental regulations. The costs of production of the released units vary and, accordingly,
depending on market conditions, the amount of generation that will be sold from the released units is expected to
vary from unit to unit. In this regard, Midwest Generation suspended operations of Will County Units 1 and 2 and
Collins Station Units 4 and 5 at the end of 2002 pending improvement in market conditions. If market conditions
were to be depressed for an extended period of time, Midwest Generation would need to consider decommissioning
Will County Units 1 and 2, which would result in a charge against income. Collins Station Units 4 and 5 are
subject to a long-term lease which requires that for the term of the lease, these units be maintained in
condition for return to service, should market conditions improve. Thus, in the absence of an agreement with the
lessor under the lease, Midwest Generation cannot decommission these units.
In addition to the price risks described previously, Midwest Generation's ability to transmit energy to
counterparty delivery points to consummate spot sales and hedging transactions may also be affected by
transmission service limitations and constraints and new standard market design proposals proposed by and
currently pending before the FERC. Although the FERC and the relevant industry participants are
Page 63
working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues
will be resolved. Currently, transmission must be obtained from Commonwealth Edison under its open-access tariff
filed with the FERC. Such transmission procurement is expected to continue throughout 2003. There is
considerable uncertainty about Commonwealth Edison's integration in PJM. In 2002, Commonwealth Edison applied to
the FERC for approval to join PJM in conjunction with American Electric Power, thereby creating an enlarged,
contiguous regional transmission organization encompassing a broad regional market. Approval of this application
was granted by the FERC on April 1, 2003. Concurrently, the ability of American Electric Power to join PJM has
been brought into question by the enactment of legislation in Virginia requiring the approval of Virginia state
authorities for any transfer of control from American Electric Power to PJM of American Electric Power
transmission assets located in Virginia. On April 16, 2003, Commonwealth Edison and PJM issued a joint press
release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of
American Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth Edison
between its service territory and the existing PJM. In response to this announcement, EME and other affected
parties filed with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested
the appropriateness of Commonwealth Edison joining PJM on an "islanded" basis. The FERC clarified that a series
of pre-conditions imposed by an order issued on July 31, 2002, tentatively approving the stated decisions of
Commonwealth Edison and American Electric Power to join PJM together, continue to be applicable to the separate
application of Commonwealth Edison to join PJM standing alone. Those conditions include (a) the elimination of
multiple transmission rates between PJM and the Midwest Independent System Operator (Midwest ISO), which controls
the transmission markets surrounding the service territory of Commonwealth Edison, and (b) an agreement between
PJM and the Midwest ISO regarding the management of operations across their "seams," which are required to be
done in such a manner as to hold harmless utility customers of the Midwest ISO in Wisconsin and Michigan from the
adverse effects of congestion and loop flows caused by the membership of Commonwealth Edison in PJM. On August 1,
2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order and the June 4, 2003 order on
rehearing with the U.S. Court of Appeals for the D.C. Circuit.
On August 20, 2003, PJM issued a press release announcing the delay of Commonwealth Edison's integration in PJM
which was previously planned for November 1, 2003. PJM intends to review the events surrounding the August 14,
2003 blackout to ensure that the Joint Operating Agreement and associated reliability plan with the Midwest ISO
will enhance the reliability performance. As the investigation proceeds, PJM will determine a revised schedule
for Commonwealth Edison's market integration in PJM. Such integration is not expected to take place during 2003.
On July 23, 2003, the FERC issued an order finding that the regional through and out rates (RTORs) of the Midwest
ISO and PJM are unjust and unreasonable when applied to transactions sinking within the proposed Midwest ISO/PJM
footprint and directed Midwest ISO and PJM to make a compliance filing within thirty days eliminating the RTORs.
The FERC also initiated an investigation and hearing to determine whether the through and out rate under the
tariffs of individual former Alliance Companies are unjust, unreasonable or unduly discriminatory or preferential
for transactions sinking in the proposed Midwest ISO/PJM footprint. On October 14, 2003, the FERC issued an
order extending the effective date for the elimination of Midwest ISO and PJM RTORs. The new deadline for the
elimination of such rates will be set in the order on rehearing, which the FERC intends to issue in the near
future.
On September 29 and 30, 2003, the FERC held a hearing and inquiry into regional transmission organization issues
related to the Midwest ISO and PJM. The purpose of the inquiry was to gather sufficient information to move
forward in resolving the commitment made by several entities, including Commonwealth Edison, to establish a joint
and common market in the Midwest and PJM region. The inquiry explored the impediments to the former Alliance
Companies' participation in either the Midwest ISO or PJM.
Page 64
EME is unable to predict the outcome of these efforts or the effect of any final integration configuration on the
markets into which Midwest Generation sells its power.
Homer City Facilities
Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic
utilities and power marketers pursuant to transactions 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 following table depicts the average market prices per megawatt-hour in PJM during the first nine months of
2003 and 2002:
24-Hour PJM
Historical Energy Prices*
- -------------------------------------------------------------------------
2003 2002
- -------------------------------------------------------------------------
January $ 36.56 $ 20.52
February 46.13 20.62
March 46.85 24.27
April 35.35 25.68
May 32.29 21.98
June 27.26 24.98
July 36.55 30.01
August 39.27 30.40
September 28.71 29.00
- -------------------------------------------------------------------------
Nine Month Average $ 36.55 $ 25.27
- -------------------------------------------------------------------------
* Energy prices were calculated at the Homer City busbar (delivery
point) using historical hourly prices provided on the PJM-ISO web-site.
As shown on the above table, the average historical market prices at the Homer City busbar (delivery point)
during the first nine months of 2003 was higher than the average historical market prices during the first nine
months of 2002, although in September of each year the power prices were similar. Forward market prices in PJM
fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in
market rules, electricity demand which is affected by weather and 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.
Sales made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In
order to mitigate price risk from changes in spot prices at the Homer City busbar, EME may enter into forward
contracts with counterparties for forecasted generation in future periods. Currently, there is not a liquid
market for entering into forward contracts at the Homer City busbar. A liquid market does exist for delivery to
a collection of delivery points known as PJM West Hub, which EME's price risk management activities use to enter
into forward contracts. EME's revenue with respect to such forward contracts include:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot
prices at the Homer City busbar, plus or minus,
Page 65
o sales to third parties under such forward contracts at designated delivery points (generally the PJM West Hub)
less the cost of purchasing power at spot prices at the same designated delivery points to fulfill
obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of raising
prices at those delivery points affected by transmission congestion. During the past 12 months, an increase in
transmission congestion at delivery points east of the Homer City facilities has resulted in prices at the PJM
West Hub (which includes delivery points east of the Homer City facilities) being higher than those at the Homer
City busbar. Thus, while forward prices at PJM West Hub have historically been higher than the prices at the
Homer City busbar by less than 5%, increased congestion during the last 12 months at delivery points east of the
Homer City facilities has resulted in prices at PJM West Hub being on average 8% higher than those at the Homer
City busbar.
By entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk,"
which occurs when forward contracts are executed on a different basis (in this case PJM West Hub) than the actual
point of delivery (Homer City busbar). In order to mitigate basis risk resulting from forward contracts using
PJM West Hub as the delivery point, EME has participated in purchasing firm transmission rights in PJM, and may
continue to do so in the future. A firm transmission right provides the holder with a financial instrument to
receive actual spot prices at one point of delivery and pay spot prices at another point of delivery.
Accordingly, EME's price risk management activities include using firm transmission rights alone or in
combination with forward contracts to manage the risks associated with changes in prices within the PJM market.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into
the PJM West Hub at September 30, 2003:
24-Hour PJM West
Forward Energy Prices*
- -----------------------------------------------------------------------
2003
----
October 2003 $ 30.82
November 2003 28.82
December 2003 32.27
2004 Calendar "strip"(1) 32.84
- -----------------------------------------------------------------------
(1) Market price for energy purchases for the entire calendar year,
as quoted for sales into the PJM West Hub.
* Energy prices were determined by obtaining broker quotes and
other public sources for the PJM West Hub delivery point.
Forward prices at PJM West are generally higher than the prices
at the Homer City busbar.
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 under "Off-Balance Sheet Transactions--EME's Off-Balance Sheet
Transactions--Sale-Leaseback Transactions," in the year-ended 2002 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.
New Zealand
Contact Energy generates about 30% of New Zealand's electricity and is the largest retailer of natural gas and
electricity in New Zealand. A substantial portion of Contact Energy's generation output is matched with the
demand of its retail electricity customers or sold through forward contracts with other wholesale electricity
counterparties. The forward contracts and/or option contracts have varying terms that expire
Page 66
on various dates through June 30, 2010, although the majority of the forward contracts are short term (less than
two years).
The New Zealand government released a government policy statement in December 2001, which called for the industry
to rationalize the three existing industry codes, form a single governance structure and address transmission
investment and pricing issues. The industry was unable to agree on new rules to facilitate the government policy
statement.
Subsequently, in May 2003, the New Zealand government announced that it would establish a new governance body to
be known as the Electricity Commission along with a set of rules to govern the market. The industry was given
the opportunity to comment on the new governance arrangements, with final submissions due in September 2003. The
final decision on these arrangements is pending.
During the winter of 2003, wholesale electricity prices increased significantly in response to lower hydro
inflows, higher demand and anticipated restrictions on the availability of thermal fuel. The New Zealand
government responded by calling for nationwide energy savings in the order of 10%. Recent rains and anticipated
snowmelt have largely improved the earlier conditions with wholesale electricity prices returning to more normal
levels. The national energy savings program ended in July 2003.
However, there are ongoing concerns that new investment in generation has not been forthcoming and that there is
a significant risk that similar events may arise in subsequent years. As a consequence the New Zealand
government announced that it will take the following steps:
o the Electricity Commission will be given responsibility for managing dry year reserve, expected to be
through the procurement of reserve capacity; and
o the Electricity Commission will be given additional reserve powers ranging from information disclosure
to imposing hedge obligations on major users and generators.
Submissions have been made in respect of the policy, which are currently being considered by the New Zealand
government. Final details of the policy were released in September 2003, and it is expected that legislation will
be passed by early next year.
The New Zealand government announced in July 2003 that it would purchase a new 155 MW power plant before winter
2004 to increase electricity security. The plant is to be situated at Whirinaki, Hawkes Bay. The Electricity
Commission will be required to include this plant in its portfolio of reserve energy. The Whirinaki plant will
be located on a site leased to the government from Contact Energy and will also be operated under contract by
Contact Energy.
Credit Risks
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities,
energy companies and financial institutions. Due to factors beyond EME's control, market liquidity has decreased
significantly since the beginning of 2002, and a number of formerly significant trading parties have completely
withdrawn from the market or substantially reduced their trading activities. The reduction in the credit quality
of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may
require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also
increase EME's credit risk. While various industry groups and regulatory agencies have taken steps to address
market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such
efforts will restore market confidence. 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
Page 67
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.
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 uses 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 using published ratings of counterparties and other publicly disclosed
information, such as financial statements, regulatory filings and press releases, to guide it in the process of
setting credit levels, risk limits and contractual arrangements including master netting agreements. The credit
quality of EME's counterparties is reviewed regularly by EME's risk management committee. In addition to
continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or
lower credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be
wholly successful or that collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of:
(i) generally 60 days of accounts receivable, (ii) current fair value of open positions, and (iii) a credit value
at risk. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk
management and trading activities which typically provide for a right of setoff in the event of bankruptcy or
default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net
exposure under these agreements. The credit ratings supporting the credit risk exposure from counterparties of
merchant energy activities were as follows:
In millions September 30, 2003
- ---------------------------------------------------------------------------------
S&P Credit Rating:
A or higher $ 85
A- 23
BBB+ 87
BBB 38
BBB- 9
Below investment grade(1) 12
- ---------------------------------------------------------------------------------
Total $ 254
- ---------------------------------------------------------------------------------
(1) This primarily relates to one counterparty that has provided a $10
million letter of credit to support EME's credit risk exposure.
Exelon Generation accounted for 25% and 44% of EME's consolidated operating revenue for the first nine months of
2003 and 2002, respectively. The percentage is less in 2003 because a smaller number of plants are subject to
contracts with Exelon Generation. See "--Commodity Price Risk--Illinois Plants." Any failure of Exelon Generation
to make payments to Midwest Generation under the power purchase agreements could result in a shortfall of cash
available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its
obligations could in turn have a material adverse effect on EME.
EME's contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest
sell power under long-term power purchase agreements. Generally, each plant sells its output to one
counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a
default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power
plant.
Page 68
Interest Rate Risk
Interest rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the
Collins Station lease. EME has mitigated the risk of interest rate fluctuations by arranging for fixed rate
financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms
for a number of its project financings. EME's interest expense included $37 million and $27 million of
additional interest expense for the nine months ended September 30, 2003 and 2002, respectively, as a result of
interest rate hedging mechanisms. EME has entered into several interest rate swap agreements under which the
maturity date of the swaps occurs prior to the final maturity of the underlying debt.
The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair
market value of EME's total long-term obligations (including current portion) was $6.1 billion at September 30,
2003, compared to the carrying value of $6.4 billion.
Foreign Exchange Rate Risk
Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of
EME's equity contributions to, and distributions from, 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. EME cannot provide assurances, however, that fluctuations in exchange rates will be fully offset by
hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a
manner that is consistent with historical or forecasted relationships.
The First Hydro plant in the U.K. and the plants in Australia have been financed in their local currencies,
pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition costs
against foreign exchange fluctuations. Furthermore, EME has evaluated the return on the remaining equity portion
of these investments with regard to the likelihood of various foreign exchange scenarios. These analyses use
market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to
predict ranges of expected returns.
During the first nine months of 2003, foreign currencies in Australia, New Zealand and the U.K. increased in
value compared to the U.S. dollar by 20%, 12% and 3%, respectively (determined by the change in the exchange
rates from December 31, 2002 to September 30, 2003). The increase in value of these currencies was the primary
reason for the foreign currency translation gain of $69 million during the first nine months of 2003.
Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency
commitments associated with transactions in the ordinary course of business. The contracts are primarily in
Australian and U.S. dollars with varying maturities through February 2006. At September 30, 2003, the
outstanding notional amount of the contracts totaled $18 million and the fair value of the contracts totaled
$(300) thousand.
In addition, Contact Energy enters into cross-currency interest rate swap contracts in the ordinary course of
business. These cross-currency swap contracts involve swapping fixed and floating-rate U.S. and Australian
dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018.
Page 69
EME will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of
hedging strategies in the future.
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used for purposes
other than trading by risk category and instrument type:
September 30, December 31,
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------
Derivatives:
Interest rate:
Interest rate swap/cap agreements $ (45) $ (48)
Interest rate options (1) (2)
Commodity price:
Electricity (29) (100)
Cross-currency interest rate swaps (49) (2)
- ---------------------------------------------------------------------------------------------------------
In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods
and assumptions based on the market conditions and associated risks existing at each balance sheet date. The
fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility
of the underlying commodities and other factors. The following table summarizes the maturities, the valuation
method and the related fair value of EME's commodity price risk management assets and liabilities (as of
September 30, 2003):
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
- -------------------------------------------------------------------------------------------------------------------
Prices actively quoted $ 51 $ 30 $ 21 $ -- $ --
Prices based on models and
other valuation methods (80) 12 6 (14) (84)
- -------------------------------------------------------------------------------------------------------------------
Total $ (29) $ 42 $ 27 $ (14) $ (84)
- -------------------------------------------------------------------------------------------------------------------
The fair value of the electricity rate swap agreements (included under commodity price-electricity) entered into
by the Loy Yang B plant and the First Hydro 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
EME's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading.
As a result of a number of industry and credit-related factors, Edison Mission Marketing & Trading has minimized
its price risk management and trading activities not related to EME's power plants or investments in energy
projects. To the extent Edison Mission Marketing & Trading engages in trading activities, Edison Mission
Marketing & Trading seeks to manage price risk and to create stability of future income by selling electricity in
the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by
buying and selling these commodities in wholesale markets. EME generally balances forward sales and purchase
contracts and manages its exposure through a value at risk analysis as described under "--Commodity Price Risk."
Page 70
The fair value of the commodity financial instruments related to energy trading activities as of September 30,
2003 and December 31, 2002, are set forth below:
September 30, 2003 December 31, 2002
In millions Assets Liabilities Assets Liabilities
- ---------------------------------------------------------------------------------------------------------
Electricity $ 131 $ 35 $ 109 $ 15
Other -- -- -- 2
- ---------------------------------------------------------------------------------------------------------
Total $ 131 $ 35 $ 109 $ 17
- ---------------------------------------------------------------------------------------------------------
The change in the fair value of trading contracts for the quarter ended September 30, 2003, was as follows:
In millions
- ---------------------------------------------------------------------------------------------------------
Fair value of trading contracts at December 31, 2002 $ 92
Net gains from energy trading activities 37
Amount realized from energy trading activities (33)
- ---------------------------------------------------------------------------------------------------------
Fair value of trading contracts at September 30, 2003 $ 96
- ---------------------------------------------------------------------------------------------------------
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's subsidiary
purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's
subsidiary 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 energy trading assets and liabilities (as of September 30, 2003):
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
- -------------------------------------------------------------------------------------------------------------------
Prices actively quoted $ 3 $ 3 $ -- $ -- $ --
Prices based on models and
other valuation methods 93 (3) 5 9 82
- -------------------------------------------------------------------------------------------------------------------
Total $ 96 $ -- $ 5 $ 9 $ 82
- -------------------------------------------------------------------------------------------------------------------
Edison Capital's Market Risks
Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance
risk that could adversely affect its results of operations or financial position.
Credit and Performance Risk
Edison Capital has leased three aircraft to American Airlines. Due to adverse conditions facing American
Airlines, its financial position has deteriorated significantly. The independent auditors' opinion on the
year-end 2002 financial statements of AMR Corporation, parent company of American Airlines, contains an
explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that
AMR Corporation will continue as a going concern. The opinion also states that AMR Corporation's recent history
of significant losses, negative cash flows from operations,
Page 71
uncertainty regarding AMR Corporation's ability to reduce it's operating costs to offset the declines in its
revenues, the potential failure of AMR Corporation to satisfy the liquidity requirements in certain of its credit
agreements, and its diminishing financial resources, raise substantial doubt about AMR Corporation's ability to
continue as a going concern. If American Airlines defaults in making its lease payments, the lenders with a
security interest in the aircraft or leases may exercise remedies that could lead to a loss of some or all of
Edison Capital's investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison
Capital in 2004 is $46 million. A restructure of the lease could also result in a loss of some or all of the
investment. At September 30, 2003, American Airlines was current in its lease payments to Edison Capital.
SCE'S REGULATORY MATTERS
This section presents updates to SCE's regulatory matters using three main subsections: generation and power
procurement, transmission and distribution, and other 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 procurement-related costs incurred during the energy
crisis in accordance with the tariffs filed with the FERC. A key element of the settlement agreement was the
establishment of a $3.6 billion regulatory balancing account called the PROACT as of August 31, 2001. Other
provisions of the settlement agreement are described in the "--CPUC Litigation Settlement Agreement" disclosure in
the year-ended 2002 MD&A. TURN and other parties appealed to the United States Court of Appeals for the Ninth
Circuit seeking to overturn the stipulated judgment of the federal district court that approved the settlement
agreement. On September 23, 2002, the Ninth Circuit issued its opinion affirming the federal district court on
all claims, with the exception of the challenges founded upon California state law, which the Ninth Circuit
referred to the California Supreme Court.
On August 21, 2003, the California Supreme Court issued its decision on the certified questions, concluding that
the settlement agreement did not violate California law in any of the respects raised by the Ninth Circuit.
Specifically, the California Supreme Court concluded that: the commissioners of the CPUC had the authority to
propose the stipulated judgment in light of the provisions of California's restructuring statute, AB 1890; the
procedures employed by the CPUC in entering the stipulated judgment did not violate California's open meeting law
for public agencies; and the stipulated judgment did not violate California's public utilities code by allegedly
altering rates without a public hearing and issuance of findings.
On September 8, 2003, TURN filed a petition for rehearing of the California Supreme Court's decision. On October
22, 2003, the California Supreme Court denied TURN's petition. The matter will now return to the Ninth Circuit
for final disposition, subject to any efforts by TURN to pursue further federal appeals. In the meantime, the
case is stayed in the federal appellate court. SCE continues to believe it is probable that recovery of its past
procurement costs through regulatory mechanisms, including the PROACT, ultimately will be validated. However,
SCE cannot predict with certainty the ultimate outcome of the pending legal proceedings.
PROACT Regulatory Asset
In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, in the fourth
quarter of 2001, SCE established the PROACT regulatory balancing account, with an initial balance of
approximately $3.6 billion reflecting the net amount of past procurement-related liabilities to
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be recovered by SCE. Each month, SCE applied to the PROACT the positive or negative difference between SCE's
revenue from retail electric rates (including surcharges) and the costs that SCE was authorized by the CPUC to
recover in retail electric rates.
Under a settlement described in "--Customer Rate-Reduction Plan," on July 15, 2003, SCE filed an advice letter
with the CPUC to inform it of the forecast recovery of the PROACT balance in July 2003, to implement post-PROACT
rate levels and rate-making mechanisms effective August 1, 2003, and to transfer the PROACT overcollection to a
new energy resource recovery account (ERRA) regulatory balancing account on August 1, 2003. At July 31, 2003,
the PROACT regulatory balancing account was overcollected by $148 million. On October 14, 2003, the Energy
Division of the CPUC completed its review of the PROACT, approved the accounting and rate-making issues related
to the PROACT, and eliminated the account effective August 14, 2003. As a result of the favorable resolution of
these issues, SCE recorded a credit of approximately $84 million to provisions for regulatory adjustment clauses
- - net on the consolidated statements of income in the third quarter of 2003 (see "Results of Operations--Operating
Expenses").
Energy Resource Recovery Account Proceedings
In an October 24, 2002 decision, the CPUC established the ERRA as the rate-making mechanism to recover SCE's fuel
costs related to its generating stations, purchased-power costs related to cogeneration and renewable contracts,
existing interutility and bilateral contracts that were entered into prior to January 17, 2001, and new
procurement-related costs that SCE began incurring on January 1, 2003, the date on which the CPUC transferred
back to SCE the responsibility for procuring energy resources for its customers. Under this decision, SCE files
semiannual ERRA applications at the beginning of April and October of each year. SCE submitted its ERRA
applications in April and October 2003. The CPUC has not yet issued a decision on these applications. See
"--Generation Procurement Proceedings" for further information.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order signed by the Governor of California, CDWR began making emergency power
purchases for SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its customers for
electric power purchased and sold by CDWR are remitted directly to CDWR and are not recognized as revenue by
SCE. In February 2001, California Assembly Bill 1X (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized CDWR to enter into contracts to purchase electric power and sell power at cost directly to SCE's
retail customers, and authorized CDWR to issue bonds to finance electricity purchases. In addition, the CPUC is
responsible for allocating CDWR's revenue requirement among the customers of SCE, Pacific Gas and Electric (PG&E)
and San Diego Gas & Electric (SDG&E).
As discussed in the "--CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2002
MD&A, the CPUC allocated to SCE's customers: $3.5 billion of CDWR's total statewide power procurement revenue
requirement of $9 billion for 2001 and 2002; $331 million of CDWR's 2003 bond charge revenue requirement of $745
million; and approximately $1.9 billion of CDWR's total statewide 2003 power procurement revenue requirement of
$4.3 billion. On July 1, 2003, CDWR submitted the supplemental determination of its 2003 power procurement
revenue requirement to the CPUC, reducing that revenue requirement by $1 billion, to $3.3 billion. SCE's
customers' share of this reduction is approximately $420 million. In September 2003, the CPUC issued a decision
ordering that this amount be returned by CDWR to SCE's customers via a one-time bill credit. The CDWR bill
credit had no impact on SCE's earnings.
In September 2003, CDWR released its revenue requirement determination for 2004 establishing a total power
procurement revenue requirement of $5.39 billion statewide, which includes a power charge of
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$4.517 billion and a bond charge of $873 million. On an interim basis, the CPUC will allocate the revenue
requirement among SCE, PG&E and SDG&E using the methodology adopted to allocate CDWR's 2003 revenue requirement.
Parties will provide testimony on the ultimate allocation methodology in December 2003 and the CPUC will convene
evidentiary hearings on the matter in January 2004. Any increase or decrease in CDWR's bond and power charges
will be directly passed through to SCE's customers.
In September 2003, CDWR also issued the data necessary to true-up its 2001-2002 revenue requirement allocation.
The true-up is to be based on the methodology adopted by the CPUC in the first quarter of 2002 and would result
in SCE's customers owing an additional $41 million to the CDWR. In the proceeding implementing the true-up, PG&E
recommended that the CPUC adopt an allocation method that would result in SCE's customers owing an additional
$289 million of CDWR's costs, while SCE recommended an allocation method that would result in SCE's customers
being owed $532 million. Alternatively, SCE proposed that the customers of each investor-owned utility pay a
bond charge that is proportionate to the bond proceeds allocated to them. This would result in a $50 million to
$60 million per year decrease in the bond charge revenue requirement allocated to SCE's customers over the
20-year life of CDWR's bonds. SCE customers would, however, still owe the additional $41 million associated with
CDWR's 2001-2002 revenue requirement allocation true-up referenced above. Hearings were held on the matter in
October 2003 and a draft decision is expected in December. Any adjustment resulting from this true-up will be
reflected in SCE's customers' share of CDWR's 2004 revenue requirement and will have no impact on earnings.
Direct Access Proceedings
Direct Access - Historical Procurement Charge
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider other than SCE (thus becoming direct access customers) or continue to purchase power from
SCE (customers who purchase power from SCE are referred to as bundled service customers). On March 21, 2002, in
accordance with existing legislation directing the CPUC to select a date for the suspension of the right of
customers to purchase power from other energy service providers, the CPUC issued a final decision affirming that
new direct access arrangements entered into by SCE's customers after September 20, 2001 are invalid. This
decision did not affect direct access arrangements in place before that date. Direct access customers received a
credit for the generation costs SCE saved by not serving them. Electric utility revenue was 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. In a recent decision, the CPUC approved a petition for modification of the
interim decision filed by SCE raising direct access customers' responsibility for SCE's past power procurement
costs to $473 million. Several parties filed petitions for review of the interim decision with the California
Supreme Court. SCE has filed responses to the petitions, but cannot predict with certainty the outcome of the
petitions before the California Supreme Court.
The historical procurement charge was initially set at 2.7(cent)per kWh, effective July 27, 2002. Subsequently, the
CPUC implemented an order establishing a surcharge for direct access customers' share of CDWR's costs, as
discussed in the paragraph below. Once that surcharge was implemented on January 1, 2003, the contribution by
direct access customers to the historical procurement charge was reduced from 2.7(cent)per kWh to 1(cent)per kWh for the
collection of the $391 million, with the remainder of the 2.7(cent)per kWh utilized for CDWR's costs associated with
direct access customers. Historical procurement charges recovered from direct access customers are used to
reduce SCE's generation rates to bundled service customers and have no impact on SCE's earnings.
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Direct Access - Exit Fees
On November 7, 2002, the CPUC issued a decision assigning responsibility for four categories of energy crisis
related costs to direct access customers. The first category consists of CDWR's power procurement costs incurred
between January 17, 2001 and September 30, 2001. CDWR sold approximately $11 billion in bonds in fourth quarter
2002 to finance a portion of the costs incurred during the California energy crisis. The CPUC decision stated
that all direct access customers were responsible for paying a portion of CDWR's bond charge to recover the
principal and financing costs associated with these bonds, except customers who were continuously on direct
access and never used any CDWR power (less than 1% of SCE's load). The second category relates to CDWR's power
procurement costs for the fourth quarter of 2001 and the year 2002. The CPUC stated that all direct access
customers who took bundled service at any time after February 1, 2001, must pay a share of these costs to make
bundled service customers indifferent to suspension by the CPUC of the direct access program on September 20,
2001. The third category includes CDWR long-term contract costs for 2003 and beyond. The CPUC decision stated
that a portion of these costs must be paid by direct access customers who took bundled service at any time after
February 1, 2001, to keep bundled service customers indifferent to the later suspension of direct access on the
premise that CDWR signed some of its long-term contracts with the expectation of serving the load that switched
to direct access after July 1, 2001. Finally, the last category relates to the above-market costs of SCE's
utility retained generation (e.g., QFs contract costs) that in accordance with AB 1890 are to be recovered from
all customers on an ongoing basis, including continuous direct access customers.
On July 10, 2003, the CPUC issued a decision establishing a 2.7(cent)per kWh cap on the amount of exit fees to be
paid by direct access customers. The exact amount of exit fees to be paid by direct access customers will be
determined on an annual basis after CDWR submits its requested revenue requirement to the CPUC. On July 10,
2003, the CPUC ordered the imposition of exit fees (the Cost Responsibility Surcharges, or CRS) on customers who
depart investor-owned utility service in favor of taking service from a publicly-owned utility. That decision
states that customers switching to municipal service after February 1, 2001, as well as customers of newly
established municipal utilities, will be responsible for paying CRS fees. The exact amount of the CRS obligation
to be paid by customers of these publicly owned utilities is to be determined in a future phase of the proceeding
and has not yet been scheduled. The CPUC affirmed the decision, with modifications, on rehearing and will
consider whether some portion of the "load" served by newly established publicly owned utilities should be exempt
from CRS. Several parties have filed petitions with the California Supreme Court challenging the decision; SCE
filed its response opposing the petitions. See "--CDWR Power Purchases and Revenue Requirement Proceedings" for
further discussion.
On April 3, 2003, in a separate decision, the CPUC adopted similar exit fees for customers who install onsite
generation facilities or arrange to purchase power from another entity that installs generation facilities on or
adjacent to their property. In its decision, the CPUC established three categories of customer generation. Each
category has varying exit fee responsibilities ranging from full exemption from the exit fees to full obligation
for all exit fees provided that the amount of customer generation installed statewide does not exceed CDWR's
forecast of customer generation it used when negotiating its long-term power contracts. The CPUC set an absolute
cap of 3,000 MW on eligible customer generation departing load through the life of CDWR's long-term contracts.
On April 17, 2003, SCE filed proposed tariff changes necessary to comply with the April 3, 2003 decision. The
CPUC has not yet approved the utilities' tariffs implementing the customer generation departing load exit fees.
Direct Access - Switching Exemptions
On May 8, 2003, the CPUC issued a decision establishing an exception to its March 21, 2002 decision (as discussed
in "--Historical Procurement Charge" section above) prohibiting new direct access
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arrangements after September 20, 2001. This exception, referred to as the switching exemptions, permits direct
access customers with a pre-September 20, 2001 contract with an energy service provider to switch back and forth
between bundled service and direct access. In its May 8, 2003 decision, the CPUC adopted three specific
exemptions:
o A grandfathering exemption that permits customers with pre-September 20, 2001 direct access contracts
who have already returned to bundled utility service subsequent to September 20, 2001 to return to direct
access during a 45-day transition period;
o A safe harbor exemption, under which direct access customers may return to bundled service on a
transitional basis while switching energy service providers. While in the safe harbor, these customers must
pay all incremental short-term power costs incurred on their behalf and the applicable direct access exit
fees; and
o A third exemption allows direct access customers who have returned to bundled service for a minimum
three-year period to thereafter depart again to acquire direct access service.
Direct access customers returning to bundled service for other than transition purposes must provide a six-month
advance notice and remain on bundled service for a minimum term of three years. Similarly, if a customer intends
to return to direct access after satisfying its three-year minimum stay on bundled service, it must provide
six-months advance notice. Direct access customers returning to bundled service remain responsible for their
share of direct access exit fees.
On June 23, 2003, SCE filed proposed tariff changes necessary to comply with the May 8, 2003 decision. Direct
access customers will continue to operate under current direct access provisions until the CPUC approves the
tariff changes, which is anticipated to occur in November 2003.
On July 9, 2003, SCE filed a petition with the California Supreme Court contending that the CPUC's May 8, 2003
decision is inconsistent with the state law which suspended the right of retail customers to acquire direct
access after the CPUC-determined date for suspension (September 20, 2001). TURN also filed a petition with the
California Supreme Court raising similar arguments. On October 22, 2003, the California Supreme Court denied
both SCE's and TURN's petition.
Temporary Surcharge
As discussed in the "--Surcharge Decisions" disclosure in the year-ended 2002 MD&A, the CPUC allowed a
continuation of a 0.6(cent)-per-kWh temporary surcharge that was scheduled to terminate in June 2002 and required SCE
to track the associated revenue in a balancing account for rate-making purposes, until the CPUC determined the
use of the surcharge. A December 17, 2002 CPUC decision authorized SCE to use the revenue associated with the
surcharge to partially offset the higher 2003 CDWR revenue requirement allocated to its customers and its own
higher procurement costs. For financial reporting purposes, $187 million of surcharge revenue billed in the last
six months of 2002 was credited to a regulatory liability account until it could be used to offset SCE's higher
2003 procurement revenue requirement. This account was partially amortized into revenue through July 31, 2003,
with the remaining balance of $37 million transferred to the ERRA balancing account as of August 1, 2003.
Hedging Cost Recovery Proceedings
Pursuant to authority granted in SCE's 2001 litigation settlement agreement with the CPUC, SCE purchased
$209 million in hedging instruments (gas call options) in late 2001 to hedge a majority of its natural gas price
exposure associated with QF contracts for 2002 and 2003. A February 13, 2003 CPUC decision allowed SCE to
transfer the entire $209 million into the PROACT regulatory asset during first
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quarter 2003. On October 16, 2003, the CPUC issued a decision that granted SCE interim authorization to hedge
its first and second quarter 2004 natural gas price risks for its existing QF contracts. Authority for any
hedging beyond second quarter 2004 is being considered with SCE's short-term resource plan described in
"--Generation Procurement Proceedings."
Generation Procurement Proceedings
California law and CPUC decisions provide for SCE to recover its reasonably incurred power procurement costs in
customer rates. A California statute adopted in 2002, allows SCE to recover reasonable procurement costs
incurred in compliance with an approved procurement plan.
The CPUC issued an order instituting rulemaking in October 2001 that establishes the policies and mechanisms
necessary for SCE and the other major California electric utilities to resume power procurement as of January 1,
2003. In 2002, the CPUC issued four significant decisions: (1) on August 22, 2002, regarding transitional
procurement contracts; (2) on September 19, 2002, regarding the allocation of contracts previously entered into
by CDWR among the three major California utilities; (3) on October 24, 2002, for the resumption of power
procurement activities by these utilities on January 1, 2003, and adoption of a regulatory framework for such
activities which includes establishment of the ERRA regulatory balancing account to track fuel and purchased
power authorized revenue requirements against actual costs; and (4) on December 19, 2002, concerning SCE's
short-term procurement plan for 2003. The CPUC also adopted an operating order described below in "--CDWR
Contracts." See the "--Generation Procurement Proceedings" in the year-ended 2002 MD&A for detailed discussion of
these matters. The CPUC issued five decisions on numerous applications for rehearing and petitions for
modifications filed on those decisions. The five decisions clarify some of the guidelines for procuring power
and provide mechanisms for a more objective determination of the reasonableness of procurement costs for
transactions outside an approved procurement plan. The CPUC determined that SCE's maximum disallowance risk
exposure for contract administration, including administration of allocated CDWR contracts, and least cost
dispatch is $37 million. Power purchases and sales not in compliance with the approved procurement plan are
subject to an expedited reasonableness review, and are not included in the disallowance cap of $37 million.
On December 24, 2002 and January 14, 2003, SCE filed advice letters seeking CPUC approval of six renewable
contracts provisionally entered into by SCE pursuant to the August 22, 2002 decision on transitional procurement
contracts. The CPUC approved five of the six contracts. The sixth contract will automatically terminate on
December 31, 2003 unless it is approved by that time or the deadline is extended.
In accordance with a ruling by a CPUC administrative law judge (ALJ), SCE filed its long-term resource plan on
April 15, 2003. SCE's long-term resource plan included both a preferred plan and an interim plan. The preferred
plan contains long-term commitments that will encourage investment in new generation and transmission
infrastructure, increase long-term reliability and decrease price volatility. These commitments include:
o a significant increase in cost-effective energy efficiency and demand-response investments;
o renewable contracts that will meet or exceed the requirements of the Renewable Portfolio Standard (RPS),
(see below);
o a substantial increment of new utility and third-party owned generation resources; and
o at least two new major transmission projects that will provide the state of California access to a
diverse set of generating resources and help facilitate a more competitive wholesale market.
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The interim plan, by contrast, relies exclusively on new short- and medium-term contracts with no long-term
resource commitments (except for new renewable contracts). In its CPUC filing, SCE maintained that
implementation of its preferred plan requires resolution of various issues including: (1) stabilizing SCE's
customer base; (2) restoring SCE's investment-grade creditworthiness; (3) restructuring regulations regarding
energy efficiency and demand-response programs; (4) removing barriers to transmission development; (5) modifying
prior decisions, which impede long-term procurement; and (6) adopting a commercially realistic cost-recovery
framework that will enable utilities to obtain financing and enable contracting for new generation.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its short-term resource plan on May 15, 2003.
The purpose of the short-term resource plan is to set defined boundaries for per se reasonable transactions. It
incorporates elements required by recent California legislation and CPUC decisions. The short-term plan is
designed so that the following types of transactions are deemed reasonable:
o procurement of electrical energy to meet a residual net short requirement;
o sales of surplus electrical energy to eliminate any residual net long position;
o procurement of additional electrical capacity to meet the combination of SCE's peak-bundled load plus
the ISO's requirement for ancillary services;
o gas procurement for non-QFs generating resources under contract to SCE (including gas procurement for
new tolling contracts that are needed, but have yet to be obtained);
o transactions to hedge the risk of energy payments to QFs which are tied to the price of natural gas (see
"--Hedging Cost Recovery Proceedings" for SCE's authority to hedge its natural gas price exposure for the
first six months of 2004);
o procurement of services, such as electric transmission, gas transportation, and gas-storage services,
which are required to support the foregoing transactions; and
o any other energy sales transactions that become necessary when surplus conditions arise.
Hearings on the short-term plan and certain key issues in the long-term plan were completed in August 2003. A
decision is expected in December 2003.
Procurement of Renewable Resources
As described in the year-ended 2002 MD&A, Senate Bill (SB) 1078 was signed into law in September 2002, and
provides for SCE and other California utilities to increase their procurement of renewable resources. Pursuant
to a ruling of the CPUC's ALJ, issues related to implementation of RPS issues in SB 1078 are being determined on
a separate, expedited schedule. Testimony on the implementation of SB 1078 was filed and hearings were held in
April 2003. On June 23, 2003, the CPUC issued its preliminary decision on RPS issues. The decision addressed
implementation of various facets of SB 1078, including preliminary rules for adopting a market price of
electricity, against which bids in solicitations for renewable power are to be judged; preliminary criteria for
the rank ordering and selection of "least-cost" and "best-fit" renewable resources; preliminary rules for
"flexible compliance" with RPS procurement targets, and the adoption of standard terms and conditions for
contracts to be entered into as part of the RPS process. With respect to compliance with procurement targets,
the CPUC preliminarily determined that up-front, automatic penalties in the amount of 5(cent)per kWh for every kWh
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that falls below each utility's annual targets (subject to exceptions set forth in the decision), with an annual
penalty cap of $25 million, would be assessed against utilities that fail to comply with procurement targets.
The decision provides that noncreditworthy utilities are exempt from procurement, but that procurement targets
for such entities will nevertheless accrue during periods of noncreditworthiness and must be achieved, subject to
the flexible compliance rules, if and when the utility becomes creditworthy. With respect to standard contract
terms for RPS contracts, the CPUC has requested briefings concerning the terms that should be standardized. The
decision contemplates additional proceedings in which the preliminary RPS implementation rules will be further
developed. On July 23, 2003, SCE applied for rehearing of the CPUC's June 23, 2003 decision, on the grounds,
among others, that the imposition of up-front, automatic penalties is contrary to legislative intent and deprives
SCE of due process, that the CPUC violated the RPS statute and federal law in establishing a capacity price for
non-firm products and that the CPUC proposed methodology for determining the market price of electricity
effectively excludes broker quotes and other recognized sources of market price information. Because the CPUC
failed to act on the application within 60 days of its filing, it is presumed denied and SCE can seek review of
the underlying decision in the California Court of Appeal. SCE is considering whether to seek appellate review.
On August 29, 2003, SCE initiated a further solicitation for renewable resources with the objective of entering
into additional power purchase agreements to the extent it receives responses which, in its judgment, provide
sufficient ratepayer benefit. On October 3, 2003, SCE received bids in response to the solicitation, which it is
presently evaluating.
CDWR Contracts
On December 19, 2002, the CPUC adopted an operating order under which SCE, PG&E and SDG&E perform the
operational, dispatch, and administrative functions for CDWR's long-term power purchase contracts, beginning
January 1, 2003. The operating order sets forth the terms and conditions under which the three utility companies
administer CDWR contracts and requires the utility companies to dispatch all the generating assets within their
portfolios on a least-cost basis for the benefit of their ratepayers. PG&E and SDG&E filed an emergency motion
in which they sought to substitute their negotiated operating agreements with CDWR for the CPUC's operating
order. In March 2003, the CPUC issued a decision which approved the negotiated operating agreements with CDWR
submitted by PG&E and SDG&E, subject to certain modifications. The decision also required SCE, PG&E and SDG&E to
file gas supply plans for the purchase of natural gas for the CDWR contracts allocated to the respective
utilities by April 17, 2003, and to file subsequent plans every six months thereafter for the term of the
operating order. SCE filed its initial gas supply plan on April 18, 2003, which was approved with minor
modifications by the CPUC on August 26, 2003. SCE filed its second gas supply plan on August 22, 2003.
The CPUC also approved amendments to the servicing agreements between the utilities and CDWR relating to
transmission, distribution, billing, and collection services for CDWR's purchased power. The servicing order
issued by the CPUC identifies the formulas and mechanisms to be used by SCE to remit to CDWR the revenue
collected from SCE's customers for their use of energy from CDWR contracts that have been allocated to SCE.
Mohave Generating Station Proceeding
As discussed in the "--Mohave Generating Station Proceeding" disclosure in the year-ended 2002 MD&A, on May 17,
2002, SCE filed with the CPUC an application to address certain issues (mainly coal and slurry-water supply
issues) facing the future extended operation of the Mohave Generating Station (Mohave). The uncertainty over a
post-2005 coal and water supply has prevented SCE and other Mohave co-owners from starting to make approximately
$1.1 billion (SCE's share is $605 million) of Mohave-related investments if Mohave's operations are to be
extended past 2005. The CPUC issued a ruling on
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January 7, 2003, requesting further written testimony on specified issues related to Mohave and its coal and
slurry-water supply issues to determine whether it is in the public interest to extend Mohave operations past
2005. SCE submitted supplemental testimony on January 30, 2003, stating, among other things, that the currently
available information is not sufficient for the CPUC to make such a determination at this time.
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in
the proceeding, most recently on October 29, 2003. The Navajo Nation and Hopi Tribe and the coal mining company,
Peabody Western Coal Company, have taken the position that the CPUC should, among other things, require SCE to
fund a study of a possible alternative water supply, and require SCE to commence a CPUC proceeding for
authorization of the Mohave pollution controls and other plant investments. Certain other parties have taken the
position that SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. Negotiations have
continued among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. On October 8, 2003, the CPUC indicated that when the CPUC is assured that resolution of the
coal and water supply issues is progressing, hearings on the costs and timelines for all alternatives would be
scheduled.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its formal application for the 2003 General Rate Case (GRC), requesting an increase of
$286 million over currently authorized revenue. The requested revenue increase is primarily related to capital
additions, updated depreciation costs and projected increases in pension and benefit expenses. In October 2002,
the CPUC's Office of Ratepayer Advocates issued its testimony and recommended a $172 million decrease in SCE's
current base rates, some $458 million below SCE's GRC request. Several other intervenors have also proposed
further reductions to SCE's request or have made other substantive proposals regarding SCE's operations.
Evidentiary hearings were concluded in March 2003, and opening briefs and reply briefs have been filed. During
the course of this GRC, SCE has agreed to a series of revisions to its request that would reduce its GRC increase
to $251 million, if authorized by the CPUC. SCE's 2004 request is an increase of $137 million over the 2003 GRC
request; however, it results in an overall non-fuel revenue reduction of $54 million, primarily due to the
expiration of the eight-year San Onofre Nuclear Generating Station (San Onofre) incremental cost incentive
pricing mechanism and the return of its incremental costs to conventional cost-of-service rate-making on
January 1, 2004. The expiration of the incremental cost incentive pricing mechanism on December 31, 2003, is
expected to decrease SCE's 2004 earnings by approximately $100 million. SCE's GRC filing also requests an $85
million increase in revenue in 2005. A final decision on Phase 1 issues is expected in the fourth quarter of
2003 or the first quarter of 2004.
On May 22, 2003, the CPUC approved SCE's request to establish a memorandum account tracking SCE's requested
revenue requirement during the period between May 22, 2003 (the date a final decision would have been rendered
under the CPUC's rate case plan) and the date a final decision is adopted; accordingly the final revenue
requirement approved in the final decision will be effective May 22, 2003. However, amounts to be recorded are
subject to review by the CPUC before recovery will be authorized. The amounts to be tracked in the memorandum
account will be subject to recovery or refund depending on the final outcome of the proceeding.
Phase 2 of the GRC proceeding will address revenue allocation and rate design issues. Hearings on this phase are
scheduled to begin in March 2004. Due to the CPUC's adoption in July 2003 of the customer rate-reduction plan
settlement (see "--Customer Rate-Reduction Plan" below), rate design changes in Phase 2 of the GRC will not be
effective until August 2004 at the earliest.
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On July 15, 2003, SCE requested that the CPUC open a third phase (Phase 3) of the GRC to consider SCE's request
to track certain security-related costs ordered by the Nuclear Regulatory Commission in a memorandum account for
future recovery in rates. These required Nuclear Regulatory Commission modifications, together with a change in
SCE's California property tax rate will increase SCE's GRC revenue requirement by $23 million during 2004-2005.
In a separate matter, a change in federal tax law is expected to lower SCE's federal income tax liability for
2004 and 2005 by the same amount. SCE has reached agreement with GRC intervenors to fund the security-related
increase with the surplus general rate case revenue requirement resulting from the change in income and property
taxes. As a result, on October 23, 2003, the ALJ in the GRC granted SCE's request to withdraw Phase 3.
Cost of Capital Filing
SCE's annual cost of capital applications with the CPUC are required to be filed by May 8 of each year, with
decisions rendered in such proceedings becoming effective January 1 of the following year. On April 1, 2003, SCE
filed a petition with the CPUC seeking to eliminate the 2004 proceeding. On August 21, 2003, the CPUC granted
SCE's petition. Thus, SCE's 2003 cost of capital decision, issued on November 7, 2002, will remain in effect
throughout 2004 and SCE's CPUC-authorized return on equity will be maintained at its current 11.6% level through
2004. SCE's CPUC-authorized costs of long-term debt and preferred stock and SCE's authorized rate-making capital
structure are also maintained at their current levels through 2004.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection
and Safety Division (CPSD), which alleged a pattern of noncompliance with the CPUC's general orders for the
maintenance of electric lines over the period 1998-2000. The order also alleged that noncompliant conditions
were involved in 37 accidents resulting in death, serious injury or property damage. The CPSD identified 4,817
alleged violations of the general orders during the three-year period; and the order put SCE on notice that it
could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief
on October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC ALJ issued a presiding officer's decision (POD) fining SCE $576,000 for alleged
violations involving death, injury or property damage, failure to identify unsafe conditions or exceeding
required inspection intervals. The POD imposes no fines for over 98% of the alleged violations and does not find
that any of the alleged violations compromised the integrity or safety of SCE's electric system or were excessive
compared to other utilities. The POD orders SCE to consult with the CPSD and refine SCE's maintenance priority
system consistent with the discussion in the POD. On July 21, 2003, SCE filed an appeal opposing the POD's
interpretation that all general order non-conformances are violations subject to potential penalty. The CPSD
also filed an appeal, challenging the fact that the POD did not, in fact, penalize SCE for 4,721 of the
violations alleged by the CPSD in the OII. SCE, PG&E, SDG&E and the California Cable and Telecommunications
Association filed responses challenging the CPSD's appeal. The CPSD filed a response objecting to the
intervention and appeals of PG&E, SDG&E and the California Cable and Telecommunications Association.
Transmission Rate Case
In July 2000, the FERC issued a decision in SCE's 1998 transmission rate case in which it ordered a reduction of
approximately $38 million to SCE's requested annual transmission revenue requirement of $213 million.
Approximately $24 million of the ordered reduction was associated with the FERC's rejection of SCE's proposed
method for allocating overhead costs to transmission operations. In August 2000, SCE filed for rehearing of the
FERC decision, asking for reconsideration of this decision,
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assuming that the CPUC would not allow SCE to recover the $24 million in CPUC jurisdictional rates. SCE
continued to collect the $24 million annually in FERC rates subject to refund until new transmission rates became
effective on September 1, 2002. In February 2001, SCE filed with the CPUC a request to recover in CPUC rates the
overhead costs not permitted in FERC rates. On August 21, 2003, the CPUC issued a decision approving SCE's
application. On September 2, 2003, SCE filed an advice letter with the CPUC to implement recovery of
approximately $133 million in accordance with the decision. The advice filing was approved on September 29, 2003
and SCE credited this amount to provisions for regulatory adjustment clauses - net in the consolidated statements
of income (see "Results of Operations--Operating Expenses"). On September 22, 2003, the CPUC's Office of
Ratepayer Advocates applied for rehearing of the August 21, 2003 decision. SCE cannot, at this time, predict how
or when the CPUC will resolve the rehearing application.
Wholesale Electricity and Gas Markets
In a consolidated proceeding related to the justness and reasonableness of rates charged by sellers in the
California Power Exchange and ISO markets as described in the "--Wholesale Electricity Markets" disclosure in the
year-ended 2002 MD&A, the FERC issued orders in March 2003 that initiated procedures for determining additional
refunds arising from market manipulation by energy suppliers. The FERC staff report issued on March 26, 2003,
found that there was pervasive gaming and market manipulation of the electric and gas markets in California and
on the West Coast and also described many of the techniques and effects of electric and gas market manipulation.
In a March 26, 2003 order clarified on April 22, 2003, the FERC adopted a recommendation of the FERC staff's
final report to modify a FERC ALJ's initial decision of December 12, 2002 to reflect the fact that the gas
indices used in the market manipulation formula overstated the cost of gas used to generate electricity. SCE
sought rehearing of the March 26, 2003 and April 22, 2003 orders. On October 16, 2003, the FERC issued an order
on SCE's rehearing request, upholding its March 26, 2003 order. On June 25, 2003, the FERC issued two sets of
enforcement orders. The first set ordered 54 entities, including SCE, to show cause concerning gaming or
anomalous market behavior during the period January 1, 2001 to June 20, 2001. SCE has provided information to
the FERC staff demonstrating that it did not engage in gaming or anomalous market behavior, filed its response to
the show cause order on September 2, 2003, and worked with the FERC staff to resolve the issue. On November 3,
2003, the FERC staff filed a motion to dismiss the charges against SCE. The second set of enforcement orders
ordered 25 entities to show cause concerning gaming and anomalous market behavior in concert with Enron and other
entities. Under both sets of orders, the remedy for tariff violations will be the disgorgement of unjust profits
and possibly other non-monetary remedies. On June 25, 2003, the FERC also opened a new investigation into
anomalous bidding behavior during the period May 1, 2000 to October 2, 2000, focused primarily on economic
withholding by bidding above $250/MWh with disgorgement of profits as the possible penalty. Since these orders,
the FERC staff has filed numerous motions to dismiss against various respondents in the proceeding and has
entered into settlements with a number of respondents. SCE and other parties subject to the order have filed
dozens of opposition pleadings. SCE cannot, at this time, determine the timing or amount of any potential
refunds. Under the settlement agreement with the CPUC, 90% of any refunds actually realized by SCE will be
refunded to ratepayers. On October 30, 2003, the CPUC issued a decision on the accounting and rate-making
mechanisms related to the consideration that will be received by regulated gas and electric utilities under a
settlement with El Paso Natural Gas Company and other parties. Based on this decision, SCE will refund to
ratepayers amounts (net of legal and consulting costs) through its ERRA balancing account as they are received
from El Paso under the terms of the settlement. In addition, amounts El Paso refunds to CDWR will result in
equivalent reductions in CDWR's revenue requirement from SCE ratepayers. Refunds from El Paso will not be
received until the proposed settlement is approved by the California Superior Court in San Diego County. A
hearing for approval of the proposed settlement is scheduled for November 20, 2003.
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Other Regulatory Matters
Catastrophic Event Memorandum Account
The catastrophic event memorandum account (CEMA) is a CPUC-authorized mechanism that allows SCE to immediately
commence the tracking of all of its incremental costs associated with declared disasters or emergencies and to
subsequently receive rate recovery of its reasonably incurred costs upon CPUC approval. Incremental costs
associated with restoring utility service; repairing, replacing or restoring damaged utility facilities; and
complying with governmental agency orders are tracked in the CEMA. If a catastrophic event occurs, SCE is to
inform the CPUC within thirty days after such event if SCE has starting tracking costs in the CEMA. SCE
currently has a CEMA for the bark beetle emergency and recently initiated a second CEMA associated with the fires
that occurred in SCE territory in October 2003. Costs tracked through the CEMA mechanism are expected to be
recovered in future rates with no impact on earnings.
Bark Beetle CEMA
On March 7, 2003, the Governor of California issued a proclamation declaring a state of emergency in Riverside,
San Bernardino and San Diego counties where an infestation of bark beetles has created the potential for
catastrophic forest fires. The proclamation requested that the CPUC direct utilities with transmission lines in
these three counties to ensure that all dead, dying and diseased trees and vegetation are completely cleared from
their utility rights-of-way to mitigate the potential fire damage. The CPUC has authorized SCE to track its
incremental expenses associated with the bark beetle emergency incurred on or after April 3, 2003, in the CEMA.
The CPUC also authorized SCE to file annual advice letters demonstrating the reasonableness of the recorded costs
and requesting rate recovery of the costs deemed reasonable by the CPUC. On October 10, 2003, the CPUC
authorized SCE to reimburse property owners for their removal of dead or dying trees (on or after April 3, 2003)
that could impact SCE's electrical lines and facilities. SCE estimates that it may incur several hundred million
dollars in incremental expenses over the next several years to remove over 350,000 of these trees. This cost
estimate is subject to significant change, depending on a number of evolving circumstances, including, but not
limited to the spread of the bark beetle infestation, the speed at which trees can be removed, and tree disposal
costs. In addition, although the recent devastating fires in southern California burned in some bark beetle
infested areas, it is too early to determine what impact, if any, the fires may have on the number and location
of dead and dying trees that are to be removed.
Fire-Related CEMA
During the last two weeks of October 2003, wildfires damaged SCE's electrical infrastructure, primarily in the
San Bernardino Mountains of Southern California where an estimated 1,500 power poles and 220 transformers were
damaged or downed. SCE has notified the CPUC that it initiated a CEMA on October 21, 2003 to track the
incremental costs to repair and restore its infrastructure. These costs are preliminarily estimated to be in
excess of $50 million.
Customer Rate-Reduction Plan
On January 17, 2003, SCE filed with the CPUC a detailed plan outlining how customer rates could be reduced later
in 2003 when SCE completed recovery of uncollected procurement costs incurred on behalf of its customers during
the California energy crisis and reflected in the PROACT. In its January 17, 2003 filing, SCE proposed that the
CPUC apply rate reductions of about $1.2 billion in the same manner it applied a series of rate surcharges during
the energy crisis in 2001.
On July 10, 2003, a CPUC decision reduced SCE's annual rates by $1.2 billion, beginning August 1, 2003. The
decision approved an April 2003 settlement agreement between SCE and active parties in this
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proceeding in which rates are reduced by 8% for residential customers, 18% for small businesses, 13% for medium
businesses and 19% for large businesses, and had no impact on SCE's earnings. In accordance with the settlement
agreement, on July 15, 2003, SCE submitted an advice filing to the CPUC to implement the rate reduction effective
on August 1, 2003, and to transfer the July 31, 2003 balance in the PROACT account (a $148 million
overcollection) and the temporary surcharge balancing account (a $37 million overcollection) to the ERRA
regulatory balancing account.
OTHER DEVELOPMENTS
Clean Air Act
Prior to EME's purchase of the Homer City facilities, the United States Environmental Protection Agency (EPA)
requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning
physical changes at the plant. This request was part of EPA's industry-wide investigation of compliance by
coal-fired plants with the Clean Air Act new source review, or NSR, requirements. On February 21, 2003, Midwest
Generation received a request for information under Section 114 regarding past operations, maintenance and
physical changes at the Illinois coal plants from EPA. On July 28, 2003, Commonwealth Edison received a
substantially similar request for information from EPA related to these same plants. Other than these requests
for information, no enforcement-related proceedings have been initiated by EPA with respect to any of EME's
United States facilities.
A federal district court, ruling on a lawsuit filed by EPA, found on August 7, 2003, that the Ohio Edison Company
violated requirements of the NSR program within the Clean Air Act by upgrading certain coal-fired power plants
without first obtaining the necessary preconstruction permits. On August 26, 2003, another federal district
court, ruling in an NSR enforcement action against Duke Energy Corporation, adopted a different interpretation of
the NSR provisions that could limit liability for similar upgrade projects.
In addition, however, EPA, on October 27, 2003, issued its final rule (effective December 26, 2003) revising its
regulations to define more clearly a category of activities that are not subject to NSR requirements under the
"routine maintenance, repair and replacement" exclusion. This regulation may mitigate some or all of the
potential impact of the Ohio Edison decision, particularly as to future repair and replacement projects.
Both recent judicial decisions and the newly issued regulation are currently under review by Edison
International, SCE and EME, to assess what implications, if any, they will have on the operation of domestic
power plants owned or operated by SCE, EME, or their subsidiaries, or on Edison International's results of
operations or financial position.
Employee Compensation and Benefit Plans
On July 31, 2003, a federal district court held that the formula used in International Business Machine
Corporation's (IBM) cash balance pension plan violated the age discrimination provisions of the Employee
Retirement Income Security Act of 1974. The formula for SCE's cash balance pension plan does not meet the
standard set forth in that federal district court's decision. The IBM decision, however, conflicts with the
decisions from two other federal district courts and with the proposed regulations for cash balance plans issued
by the Internal Revenue Service in December 2002. IBM has announced that it will appeal the decision to the
United States Court of Appeals for the Seventh Circuit. The effect of the IBM decision on SCE's cash balance
plan cannot be determined at this time.
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Palo Verde Steam Generators
During the fall of 2003, Palo Verde Unit 2 steam generators are being replaced. In addition, the Palo Verde
owners have approved the manufacturing of two additional sets of steam generators for installation in Units 1
and 3. The Palo Verde owners expect that these steam generators will be installed in Units 1 and 3 in the 2005 to
2008 time frame. SCE's share of the costs of manufacturing and installing all replacement steam generators at
Palo Verde is approximately $106 million, and is expected to be recovered through the rate-making process.
San Onofre Steam Generators
Like other nuclear power plants with steam generators made of Inconel 600 mill annealed alloy, San Onofre Units 2
and 3 have experienced degradation in their steam generators. Presently, 9% and 7%, respectively, of the tubes
in the existing steam generators of Unit 2 and Unit 3 have been plugged and removed from service. SCE presently
estimates that the San Onofre Units 2 and 3 generator design allows for the plugging and removal from service of
21.4% of the tubes before the units must be shutdown or the steam generators replaced. Industry experience is
that the percentage of tubes requiring plugging accelerates as steam generators made of this alloy age. Based on
this industry experience and SCE's analysis of recent inspection data, SCE has determined that the existing San
Onofre Units 2 and 3 steam generators may not be adequate to permit continued operation beyond the scheduled
refueling outages in 2009-2010. SCE currently estimates that the total project cost of replacing the steam
generators should not exceed $775 million. If the other plant co-owners agree to pay their proportionate shares
of the costs, SCE's 75% share should not exceed $581 million. SCE currently is reviewing the advisability of
replacing the steam generators, as well as additional issues, including participation by co-owners, regulatory
approvals, and permits. To obtain delivery of replacement steam generators in 2009, SCE expects that it may need
to enter into fabrication commitments in 2004. If SCE elects to proceed with replacing the steam generators, it
would seek the prior approval of the CPUC. If the CPUC finds investment in the steam generators to be reasonable
and cost effective, the investment should be reflected in SCE's retail rates for recovery over the remaining
useful life of the plants.
ACQUISITIONS AND DISPOSITIONS
In October 2003, EME agreed to sell its 40% interest in a development project in Thailand to a third party.
Completion of the sale, currently expected during the fourth quarter of 2003, is subject to closing conditions,
including obtaining regulatory approval. Net proceeds from the sale are expected to be approximately $13 million
payable in two installments, one in December 2003 and the other in June 2004.
In July 2003, EME agreed to sell its 50% interest in the Gordonsville project to a third party. Completion of
the sale, currently expected during the fourth quarter of 2003, is subject to closing conditions. Net proceeds
from the sale, including distribution of a debt service reserve fund, are expected to be approximately
$32 million. EME recorded an impairment charge of $6 million during the second quarter of 2003 related to the
planned disposition of this investment.
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen,
to acquire Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands,
California. This acquisition requires regulatory approval from both the CPUC and the FERC. On July 21, 2003,
SCE filed an application with the CPUC proposing a power-purchase agreement between SCE and Mountainview Power
Company LLC. Hearings were completed in October 2003, and a CPUC decision on this matter is expected in December
2003. If approved by the CPUC, SCE will seek FERC approval of the power-purchase agreement. SCE does not expect
to exercise the option without CPUC and FERC approvals. The option must be exercised prior to February 29,
2004. If SCE exercises the option, SCE would recommence full construction of the project.
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Under the option agreement, Sequoia may elect to terminate the option agreement at any time prior to SCE's
exercise of the option. In such event, Sequoia must return all previously tendered option payments.
On July 10, 2003, the CPUC approved a joint application filed by SCE and Pacific Terminals LLC, requesting
authorization for the sale of certain oil storage and pipeline facilities by SCE to Pacific Terminals for $158
million. The sale closed on July 31, 2003 and resulted in a $44 million after-tax gain to shareholders recorded
in the third quarter of 2003.
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to
acquire the Taranaki Combined Cycle power station and related interests. The Taranaki station is a 357 MW
combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki
station consisted of a cash payment of approximately $275 million, which was initially financed with bridge loan
facilities. The bridge loan facilities were subsequently repaid with proceeds from the issuance of long-term
U.S. dollar denominated notes.
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 2001, EME recorded asset impairment charges of $32 million related to these projects based on
the expected sales proceeds. No gain or loss was recorded from the sale of EME's interests in these projects
during the first quarter of 2002.
NEW ACCOUNTING PRINCIPLES
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset
Retirement Obligations, which requires entities to record the fair value of a liability for a legal asset
retirement obligation (ARO) 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. However, rate-regulated entities may recognize
regulatory assets or liabilities as a result of timing differences between the recognition of costs in accordance
with this standard and the recovery of costs through the rate-making process. Regulatory assets and liabilities
may also be recorded if it is probable that the ARO will be recovered through the rate-making process.
Edison International's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its
nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and
$12 million to decommission its share of a coal-fired generating plant, under accounting principles in effect
at that time. Of these amounts, $298 million to decommission its inactive nuclear facility was recorded in
other long-term liabilities, and the remaining $2.0 billion was recorded as a component of the accumulated
provision for depreciation and decommissioning on the consolidated balance sheets in Edison International's
Annual Report on Form 10-K for the year ended December 31, 2002.
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning,
recorded the fair value of its AROs of approximately $2.0 billion in the deferred credits and other
liabilities section of the balance sheet, and increased its unamortized nuclear
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investment by $303 million. The cumulative effect of a change in accounting principle from unrecognized
accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date
was a $354 million after-tax gain, which under accounting standards for rate-regulated enterprises was
deferred as a regulatory liability, partially offset by a $235 million deferred tax asset, as of January 1,
2003. Accretion and depreciation expense resulting from the application of the new standard is expected to
be approximately $143 million in 2003. This cost will reduce the regulatory liability, with no impact on
earnings. As of September 30, 2003, SCE's ARO for its nuclear facilities totaled approximately $2.1 billion
and its nuclear decommissioning trust assets had a fair value of $2.4 billion. If the new standard had been
in place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $2.0
billion collected through rates for cost of removal of plant assets not considered to be legal obligations
remain in accumulated depreciation and decommissioning.
o As of January 1, 2003, EME's ARO was $17 million and EME recorded a cumulative effect adjustment that
decreased net income by approximately $9 million, net of tax. If the new standard had been applied
retroactively in the nine months ended September 30, 2002, it would not have had a material effect on EME's
results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities
(VIEs). The primary objective of the interpretation is to provide guidance on the identification of, and
financial reporting for, entities over which control is achieved through means other than voting rights; such
entities are known as VIEs. This interpretation applies to VIEs created after January 31, 2003 and beginning
July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it acquired before February 1,
2003. Effective October 9, 2003, an additional interpretation was issued which delays the effective date for
applying the provisions of the original interpretation to VIEs that were acquired before February 1, 2003. For
Edison International, the new effective date is December 31, 2003.
Under the interpretation, if an enterprise absorbs the majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns, or both, it must consolidate the VIE. An enterprise that is
required to consolidate the VIE is called the primary beneficiary. Additional disclosure requirements are also
applicable when an enterprise holds a significant variable interest in a VIE, but is not the primary
beneficiary. In addition, financial statements issued after January 31, 2003 must include certain disclosures if
it is reasonably possible that an enterprise will consolidate or disclose information about a VIE when this
interpretation is effective.
Edison International believes it is reasonably possible that certain partnership interests in energy projects are
VIEs under this interpretation, as discussed below:
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098
MW of power plants. The maximum exposure to loss from EME's interest in these energy partnerships is $1.1
billion at September 30, 2003. Of this amount, $573 million represents EME's investment in the 1,230 MW Paiton
project and $306 million represents EME's investment in the 540 MW EcoElectrica project.
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another
affiliated project under a fuel supply agreement. TM Star has entered into fuel purchase contracts with
unrelated third parties to meet a portion of the obligations under the fuel supply agreement. EME has guaranteed
50% of the obligation under the fuel supply agreement to this affiliated project. The maximum loss is subject to
changes in natural gas prices. Accordingly, the maximum exposure to loss cannot be determined.
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Edison International is in the process of reviewing the entities discussed above that have a reasonable
possibility of being VIEs to determine if it is the primary beneficiary.
In addition, Edison International is in the process of reviewing Edison Capital's partnership interests in
affordable housing projects to determine if they have a reasonable possibility of being VIEs and also to
determine if Edison Capital is the primary beneficiary.
Although Edison International will continue to evaluate the impact of adoption of this interpretation, Edison
International has concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy
Yard project and Edison Capital's Storm Lake project, since it expects to absorb the majority of these projects'
losses, if any, and expects to receive the majority of these projects' residual returns, if any. Accordingly,
Edison International will consolidate these projects effective October 1, 2003. These consolidations are
expected to increase total assets by approximately $451 million and total liabilities by approximately $533
million. In addition, Edison International expects to record a loss of approximately $82 million (of which $76
million is related to Brooklyn Navy Yard) in the fourth quarter of 2003 as a cumulative accounting change as a
result of consolidating these VIEs.
Effective July 1, 2003, Edison International adopted a new accounting standard, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. This statement amends and clarifies financial accounting and
reporting for derivative instruments and for hedging activities under derivative instrument accounting. The
amendment reflects decisions made by accounting authorities in connection with issues raised about the
application of the derivative instrument accounting standard. Generally, the provisions of this new standard
apply prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The adoption of this standard had no impact on Edison International's
consolidated financial statements.
Effective July 1, 2003, Edison International adopted a new accounting standard, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity, which required issuers to classify certain
freestanding financial instruments as liabilities. These freestanding liabilities include mandatorily redeemable
financial instruments, obligations to repurchase the issuer's equity shares by transferring assets and certain
obligations to issue a variable number of shares. Effective July 1, 2003, Edison International reclassified its
company-obligated mandatorily redeemable securities, its other mandatorily redeemable preferred securities and
SCE's preferred stock subject to mandatory redemption to the liabilities section of its consolidated balance
sheet. These items were previously classified between liabilities and equity. In addition, effective July 1,
2003, dividend payments on these instruments are included in interest expense - net of amounts capitalized on
Edison International's consolidated statements of income. Prior period financial statements are not permitted to
be restated for these changes. Therefore, upon adoption, there was no cumulative impact incurred due to this
accounting change.
In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Determining Whether an Arrangement
Contains a Lease, which provides guidance on how to determine whether an arrangement contains a lease that is
within the scope of the standard, Accounting for Leases. A lease is defined as an agreement conveying the right
to use property, plant, or equipment (land and/or depreciable assets) usually for a stated period of time. The
guidance issued by the EITF could affect the classification of a power sales agreement that meets specific
criteria, such as a power sales agreement for substantially all of the output from a power plant to one
customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease
subject to the lease accounting standard. The consensus is effective prospectively for arrangements entered into
or modified after June 30, 2003. The consensus had no impact on Edison International's consolidated financial
statements.
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In June 2003, clarifying guidance was issued related to derivative instruments and hedging activities. The
guidance is related to pricing adjustments in contracts that qualify under the normal purchases and normal sales
exception under derivative instrument accounting. This implementation guidance became effective on October 1,
2003. As a result of this clarifying guidance, certain contracts that did not previously qualify for the normal
purchases and sales exception may now qualify. EME and SCE are currently evaluating the impact of this guidance
on their contracts.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates,
believes, predict, and other similar expressions are intended to identify forward-looking information that
involves risks and uncertainties. Actual results or outcomes could differ materially from those anticipated.
Risks, uncertainties and other important factors that could cause results to differ or that otherwise could
impact Edison International and its subsidiaries, include, among other things:
o the outcome of the pending appeal of the stipulated judgment approving SCE's settlement agreement with
the CPUC;
o the substantial amount of debt and lease obligations of MEHC, EME and their subsidiaries, including
$781 million of debt maturing in December 2003 and the term loan put-option, which present the risk that
MEHC, EME, and their subsidiaries might not be able to repay or refinance their obligations, raise
additional financing for their future cash requirements, or provide credit support for ongoing operations;
o the actions of securities rating agencies, including the determination of whether or when to make
changes in ratings assigned to Edison International and its subsidiaries that are rated, the ability of
Edison International and its subsidiaries that are rated below investment-grade to regain their
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 and provide credit
support;
o changes in prices and availability of wholesale electricity, natural gas, other fuels, and transmission
services, and other changes in operating costs, which could affect SCE's and EME's operations and financial
results;
o the operation of some of EME's power plants without long-term power purchase agreements, which may
adversely affect EME's ability to sell the plant's output at profitable terms;
o the substantial amount of EME's revenue derived under power purchase agreements with a single customer,
which could adversely affect EME's results of operations and liquidity;
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 buy or sell power or enter into hedging agreements;
o provisions in MEHC's, EME's and their subsidiaries' organizational and financing documents that limit
their ability to, among other things, incur and repay debt, pay dividends, sell assets, and enter into
specified transactions that they otherwise might enter into, which may impair their ability to compete
effectively or to operate successfully under adverse economic conditions;
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o the possibility that existing tax allocation agreements may be terminated or 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 the effects on SCE and EME of energy legislation currently pending in the United States Congress and
other legislation that may be adopted in the future;
o actions by state and federal regulatory and administrative bodies setting rates, adopting or modifying
cost recovery, holding company rules, accounting and rate-setting mechanisms, or otherwise changing the
regulatory and business environments within which Edison International and its subsidiaries do business, as
well as legislative or judicial actions affecting the same matters;
o the effects of increased competition in energy-related businesses, including new market entrants and the
effects of new technologies that may be developed in the future;
o efforts by municipalities and other local government entities to compete with SCE by forming public
power entities in new development areas, acquiring SCE's electric distribution facilities, or providing
electricity to aggregated SCE customers without paying SCE's full stranded costs and CDWR costs;
o the creditworthiness and financial strength of Edison Capital's counterparties worldwide in energy and
infrastructure projects, including power generation, electric transmission and distribution, transportation,
and telecommunications;
o the effects of changes in interest rates and investment returns on employee benefit plans and nuclear
decommissioning trusts;
o general political, economic and business conditions in the countries in which Edison International and
its subsidiaries do business;
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 operation risks, including equipment failures, availability, output and labor issues;
o the outcome of current and future litigation and other legal proceedings involving Edison International
and its subsidiaries';
o new or increased environmental requirements that could require capital expenditures or otherwise affect
the operations and cost of Edison International and its subsidiaries, and possible increased liabilities
under new or existing requirements; and
o weather conditions, natural disasters, and other unforeseen events.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 3 is included in Item 2, Management's Discussion and Analysis of Financial
Condition and Results of Operations, under Market Risk Exposures, and is incorporated herein by reference.
Item 4. Controls and Procedures
Disclosure Controls and Procedures.
Edison International's management, with the participation of the company's Chief Executive Officer and Chief
Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures
(as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(the "Exchange Act")) as of the end of the period covered by this report. Based on such evaluation, the Chief
Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, Edison
International's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
There have not been any changes in Edison International's internal control over financial reporting (as such term
is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this
report relates that have materially affected, or are reasonably likely to materially affect, Edison
International's internal control over financial reporting.
Page 91
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Edison International
None
Edison Mission Energy
None
Southern California Edison Company
CPUC Litigation Settlement Agreement
As previously reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K for the year ended
December 31, 2002 (2002 Form 10-K), in Part II, Item 1 of Edison International's Quarterly Report on Form 10-Q
for the period ending March 31, 2003 (First Quarter 10-Q) and in Part II, Item 1 of Edison International's
Quarterly Report on Form 10-Q for the period ending June 30, 2003, Southern California Edison Company (SCE) filed
a lawsuit against the California Public Utilities Commission (CPUC) in federal district court seeking a ruling
that SCE is entitled to full recovery of its electricity procurement costs incurred during the energy crisis in
accordance with the tariffs filed with the Federal Energy Regulatory Commission. See the discussion, which is
incorporated herein by this reference, in Part 1, Item 2, Management's Discussion and Analysis of Financial
Condition and Results of Operations under "SCE'S REGULATORY MATTERS - CPUC Litigation Settlement Agreement."
Irvine Underground Storage Tank Matter
In a letter dated October 20, 2003, the office of the District Attorney of Orange County, California alleged that
reports generated by the Orange County Health Care Agency revealed that SCE violated the California Code of
Regulations by failing to upgrade an underground storage tank in Irvine, California, between December 23, 1998
and November 4, 2001. While the tank has been removed, the previous violations are alleged to still exist. The
October 20, 2003 letter advised that it is the intention of the District Attorney's office to bring an action
against SCE in Orange County Superior Court, seeking civil penalties ranging from $500 up to $5,000 per tank per
day of violation, and costs of investigation. A prefiling settlement conference has been scheduled for
November 21, 2003.
Navajo Nation Litigation
As previously reported in the 2002 Form 10-K and in the First Quarter 10-Q, on June 18, 1999, SCE was served with
a complaint filed by the Navajo Nation in the United States District Court for the District of Columbia against
Peabody Holding Company and certain of its affiliates (Peabody), Salt River Project Agricultural Improvement and
Power District and SCE (Salt River Project Agricultural Improvement and Power District was later dismissed as a
defendant). The complaint asserts claims against the defendants for, among other things, violations of the
federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation
by nondisclosure and various contract-related claims.
Some of the issues included in this case were addressed by the United States Supreme Court in a separate legal
proceeding filed by the Navajo Nation against the United States Department of Interior in the Court of Federal
Claims. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning
negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against
Page 92
SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach
of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. On April
28, 2003, SCE filed in the action pending against it and Peabody a motion for summary judgment based on the
foregoing conclusion of the Supreme Court. That motion remains pending.
On October 24, 2003, the Court of Appeals, on remand from the Supreme Court, issued a decision remanding the
action brought by the Navajo Nation against the Government back to the Court of Federal Claims for further
proceedings. The Court of Appeals, acting on a "suggestion on remand" filed by the Navajo Nation, held in its
October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on a particular statute,
the Indian Mineral Leasing Act of 1938 (IMLA), and therefore did not address the question of whether a "network"
of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States
during the time period in question. The Court of Appeals, however, further recognized the possibility that the
Navajo Nation may have waived the right to assert claims based on the "network" theory and directed that the
Court of Federal Claims decide in the first instance whether such a waiver had occurred. If no waiver is found,
then the Court of Federal Claims is directed to determine whether, apart from the IMLA and two other statutes
that the Supreme Court held did not apply to the subject lease, a "network of other statutes and regulations"
imposes an enforceable fiduciary obligation on the Government and, if so, whether such duties were breached under
the relevant facts. SCE is currently analyzing the extent to which the Court of Appeals' October 24, 2003
decision will have any impact on the Navajo Nation's claims against SCE and Peabody and SCE's pending summary
judgment motion.
Page 93
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 9, 1996
(File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of
Edison International dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on January 1,
2002 (File No. 1-9936, Form 10-K for the year ended December 31, 2001)*
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. Section 1350
- ----------------
* Incorporated by reference pursuant to Rule 12b-32.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
July 10, 2003 July 11, 2003 5 and 7
August 5, 2003 August 5, 2003 7 and 12**
August 21, 2003 August 22, 2003 5 and 7
- ----------------
** Reports on Form 8-K reporting events under Item 12 thereunder are furnished to, not filed with, the
Securities and Exchange Commission.
Page 94
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
Dated: November 14, 2003