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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 March 31, 2004
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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 May 6, 2004
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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 Months
Ended March 31, 2004 and 2003 1
Consolidated Statements of Comprehensive Income -
Three Months Ended March 31, 2004 and 2003 2
Consolidated Balance Sheets - March 31, 2004
and December 31, 2003 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2004 and 2003 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 26
Item 3. Quantitative and Qualitative Disclosures About Market Risk 76
Item 4. Controls and Procedures 76
Part II. Other Information:
Item 1. Legal Proceedings 77
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities 78
Item 6. Exhibits and Reports on Form 8-K 79
Signatures
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
March 31,
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In millions, except per-share amounts 2004 2003
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(Unaudited)
Electric utility $ 1,696 $ 1,814
Nonutility power generation 783 684
Financial services and other 31 25
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Total operating revenue 2,510 2,523
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Fuel 342 334
Purchased power 580 452
Provisions for regulatory adjustment clauses - net (19) 304
Other operation and maintenance 905 783
Depreciation, decommissioning and amortization 295 288
Property and other taxes 51 51
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Total operating expenses 2,154 2,212
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Operating income 356 311
Interest and dividend income 13 46
Equity in income from partnerships and
unconsolidated subsidiaries - net 64 60
Other nonoperating income 80 16
Interest expense - net of amounts capitalized (316) (299)
Other nonoperating deductions (31) (12)
Dividends on preferred securities subject to mandatory redemption -- (28)
Dividends on utility preferred stock not subject to mandatory redemption (1) (1)
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Income from continuing operations before tax 165 93
Income tax 67 30
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Income from continuing operations 98 63
Income from discontinued operations - net of tax -- 3
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Income before accounting change 98 66
Cumulative effect of accounting change - net of tax (1) (9)
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Net income $ 97 $ 57
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Weighted-average shares of common stock outstanding 326 326
Basic earnings per share:
Continuing operations $ 0.30 $ 0.19
Discontinued operations -- 0.01
Cumulative effect of accounting change -- (0.03)
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Total $ 0.30 $ 0.17
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Weighted-average shares, including
effect of dilutive securities 330 328
Diluted earnings per share:
Continuing operations $ 0.30 $ 0.19
Discontinued operations -- 0.01
Cumulative effect of accounting change -- (0.03)
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Total $ 0.30 $ 0.17
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Dividends declared per common share $ 0.20 --
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
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In millions 2004 2003
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(Unaudited)
Net income $ 97 $ 57
Other comprehensive income (expense), net of tax:
Foreign currency translation adjustments 22 21
Unrealized gains (losses) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges - net (45) (3)
Reclassification adjustment for gain (loss) included in net income 21 (1)
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Other comprehensive income (expense) (2) 17
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Comprehensive income $ 95 $ 74
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The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions 2004 2003
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(Unaudited)
ASSETS
Cash and equivalents $ 2,749 $ 2,198
Restricted cash 65 79
Receivables, less allowances of $39 and $37 for uncollectible
accounts at respective dates 1,128 1,200
Accrued unbilled revenue 396 408
Fuel inventory 78 92
Materials and supplies, at average cost 262 252
Accumulated deferred income taxes - net 423 508
Trading and price risk management assets 32 48
Prepayments 42 88
Other current assets 142 176
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Total current assets 5,317 5,049
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Nonutility property - less accumulated provision for
depreciation of $1,855 and $1,318 at respective dates 8,278 7,701
Nuclear decommissioning trusts 2,606 2,530
Investments in partnerships and unconsolidated subsidiaries 1,747 1,908
Investments in leveraged leases 2,385 2,361
Other investments 146 176
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Total investments and other assets 15,162 14,676
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Utility plant, at original cost:
Transmission and distribution 14,977 14,861
Generation 1,381 1,371
Accumulated provision for depreciation (4,398) (4,386)
Construction work in progress 680 600
Nuclear fuel, at amortized cost 140 141
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Total utility plant 12,780 12,587
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Goodwill 888 868
Restricted cash 278 339
Regulatory assets - net 421 510
Other deferred charges 956 917
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Total deferred charges 2,543 2,634
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Assets of discontinued operations 16 16
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Total assets $ 35,818 $ 34,962
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions, except share amounts 2004 2003
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 36 $ 252
Long-term debt due within one year 2,028 2,003
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,037 1,086
Accrued taxes 523 596
Trading and price risk management liabilities 266 168
Regulatory liabilities - net 248 361
Other current liabilities 1,529 1,692
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Total current liabilities 5,676 6,167
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Long-term debt 12,673 11,787
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Accumulated deferred income taxes - net 6,060 5,967
Accumulated deferred investment tax credits 147 149
Customer advances and other deferred credits 1,463 1,554
Power-purchase contracts 230 213
Other preferred securities subject to mandatory redemption 306 305
Accumulated provision for pensions and benefits 461 425
Asset retirement obligations 2,128 2,106
Other long-term liabilities 262 247
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Total deferred credits and other liabilities 11,057 10,966
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Liabilities of discontinued operations 11 13
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Total liabilities 29,417 28,933
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Commitments and contingencies (Notes 2 and 4)
Minority interest 857 517
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Preferred stock not subject to mandatory redemption 129 129
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Common stock (325,811,206 shares outstanding at each date) 1,973 1,970
Accumulated other comprehensive loss (55) (53)
Retained earnings 3,497 3,466
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Total common shareholders' equity 5,415 5,383
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Total liabilities and shareholders' equity $ 35,818 $ 34,962
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended
March 31,
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In millions 2004 2003
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 97 $ 54
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax 1 9
Depreciation, decommissioning and amortization 295 288
Other amortization 23 27
Minority interest 12 4
Deferred income taxes and investment tax credits 138 28
Equity in income from partnerships and unconsolidated subsidiaries (64) (60)
Income from leveraged leases (24) (21)
Regulatory assets - long-term - net 45 69
Gain on sale of assets (43) --
Gas options (5) (15)
Levelized rent expense -- (5)
Other assets 1 (43)
Other liabilities 67 (74)
Changes in working capital net of effects from consolidation and
deconsolidation of variable interest entities:
Receivables and accrued unbilled revenue 109 41
Regulatory liabilities - short-term - net (113) 159
Fuel inventory, materials and supplies 13 18
Prepayments and other current assets 75 (124)
Accrued interest and taxes (126) 56
Accounts payable and other current liabilities (207) 252
Distributions and dividends from unconsolidated entities 26 30
Operating cash flows from discontinued operations (1) (13)
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Net cash provided by operating activities 319 680
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Cash flows from financing activities:
Long-term debt issued 1,619 215
Long-term debt repaid (966) (472)
Bonds remarketed - net 350 --
Redemption of preferred securities (2) (5)
Rate reduction notes repaid (62) (62)
Short-term debt financing - net (220) 133
Dividends paid (65) --
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Net cash provided (used) by financing activities 654 (191)
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Cash flows from investing activities:
Additions to property and plant (339) (323)
Acquisition costs related to nonutility generation plant (285) --
Purchase of common stock of acquired companies -- (275)
Proceeds from sale of interests in projects 118 --
Contributions to nuclear decommissioning trusts - net (21) (21)
Distributions from (investments in) partnerships and unconsolidated subsidiaries 19 (29)
Other assets 35 13
Investing cash flows from discontinued operations -- 4
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Net cash used by investing activities (473) (631)
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Effect of exchange rate changes on cash 6 7
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Effect of consolidation of variable interest entities on cash 79 --
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Effect of deconsolidation of variable interest entities on cash (34) --
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Net increase (decrease) in cash and equivalents 551 (135)
Cash and equivalents, beginning of period 2,198 2,468
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Cash and equivalents, end of period, continuing operations $ 2,749 $ 2,333
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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 March 31, 2004
are not necessarily indicative of the operating results for the full year.
This quarterly report should be read in conjunction with Edison International's Annual Report on Form 10-K for the year ended
December 31, 2003 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 2003 Annual Report. Edison International follows the same accounting policies for interim reporting purposes, with
the exception of the change in accounting for variable interest entities (VIEs).
In accordance with a new accounting standard for consolidation of VIEs, effective March 31, 2004, Southern California Edison Company
(SCE) began consolidating four cogeneration projects from which SCE typically purchases 100% of the energy produced under long-term
power-purchase agreements, Edison Mission Energy (EME) deconsolidated two power projects and Edison Capital began consolidating two
affordable housing partnerships and three wind projects. See further discussion in "New Accounting Principles."
Certain prior-period amounts were reclassified to conform to the March 31, 2004 financial statement presentation.
Dividend Restriction
The California Public Utilities Commission (CPUC) regulates SCE's capital structure, limiting the dividends it may pay Edison
International. In its most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a
common equity component of 48%. SCE determines compliance with this capital structure based on a 13-month weighted-average
calculation. At March 31, 2004, SCE's 13-month weighted-average common equity component of total capitalization was 56%. At
March 31, 2004, SCE had the capacity to pay $746 million in additional dividends and continue to maintain its CPUC-authorized capital
structure based on the 13-month weighted-average method. Based on recorded March 31, 2004 balances, SCE's common equity to total
capitalization ratio, for rate-making purposes, was approximately 48%. SCE had no capacity to pay additional dividends based on
March 31, 2004 recorded balances.
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
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the weighted-average shares. Due to their antidilutive effect, dilutive securities are excluded from the diluted EPS calculation if
the numerator is negative.
The following table presents the effect of dilutive securities on the number of weighted-average shares of common stock outstanding:
Three Months Ended
March 31,
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In millions 2004 2003
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(Unaudited)
Basic weighted-average shares
of common stock outstanding 326 326
Stock-based compensation awards exercisable 4 2
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Dilutive weighted-average shares
of common stock outstanding 330 328
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Goodwill
Goodwill represents the excess of cost incurred over the fair value of net assets acquired in a purchase transaction. EME evaluates
goodwill whenever indicators of impairment exist, but at least annually on October 1 of each year. EME's goodwill ($887 million at
March 31, 2004 and $867 million at December 31, 2003) is primarily related to the acquisitions of Contact Energy and First Hydro.
New Accounting Principles
In December 2003, the Financial Accounting Standards Board issued a revision to an accounting Interpretation (originally issued in
January 2003), Consolidation of Variable Interest Entities. The primary objective of the Interpretation is to provide guidance on
the identification of, and financial reporting for, VIEs, where control may be achieved through means other than voting rights.
Under the Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected losses or residual
returns, or both, must consolidate the VIE, unless specific exceptions apply. This Interpretation is effective for special purpose
entities, as defined by accounting principles generally accepted in the United States, as of December 31, 2003, and all other
entities as of March 31, 2004. See Edison International's 2003 Annual Report for information on special purpose entities
consolidated as of December 31, 2003.
SCE has 275 long-term power-purchase contracts with independent power producers that own qualifying facilities (QFs). SCE was
required under federal law to sign such contracts, which typically require SCE to purchase 100% of the power produced by these
facilities; the CPUC controls the terms and pricing. SCE conducted a review of its QF contracts and determined that SCE has variable
interests in 22 contracts with gas-fired cogeneration plants that contain variable pricing provisions based on gas prices. SCE
requested from the entities that hold these contracts the financial information necessary to determine whether SCE must consolidate
these projects. All 22 entities declined to provide SCE with the necessary financial information. However, four of the 22 contracts
are with entities 49%-50% owned by a related party, EME. EME is an indirect wholly owned subsidiary of Edison International.
Although the four related-party entities have declined to provide their financial information to SCE, Edison International has access
to such information and has provided that information to SCE on a combined basis. SCE has determined that it must consolidate the
four power projects partially owned by EME
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
based on a qualitative analysis of the facts and circumstances of the entities, including the related-party nature of the
transaction. SCE will continue to attempt to obtain information for the other 18 projects in order to determine whether they should
be consolidated by SCE.
The remaining 253 contracts will not be consolidated by SCE under the new accounting standard since SCE lacks a variable interest in
these contracts or the contracts are with governmental agencies, which are generally excluded from the standard.
Edison International analyzes its potential variable interests by calculating operating cash flows. A fixed-price contract to
purchase electricity from a power plant does not absorb sufficient variability to be considered a variable interest. A contract with
a non-gas-fired plant that is based on gas prices is also not a variable interest. Additionally, SCE has six five-year power
contracts with non-QF generators. These contracts are not considered to be significant variable interests due to their short
duration.
Upon implementing this new accounting standard, EME deconsolidated two power projects and Edison Capital consolidated two affordable
housing partnerships and three wind projects. Edison International recorded a cumulative effect adjustment that decreased net income
by approximately $1 million, net of tax, due to negative equity at one of Edison Capital's newly consolidated entities.
See "Variable Interest Entities" for further information.
As discussed in "New Accounting Principles" in Note 1 of "Notes to Consolidated Financial Statements" included in Edison
International's 2003 Annual Report, on 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 in
the period in which it is incurred. Included in Edison International's impact of adopting this standard was EME's recording a
cumulative effect adjustment that decreased net income by approximately $9 million, net of tax.
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 2003 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 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended
March 31,
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In millions, except per-share amounts 2004 2003
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(Unaudited)
Net income, as reported $ 97 $ 57
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 4 2
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 3 2
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Pro forma net income $ 98 $ 57
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Basic earnings per share:
As reported $ 0.30 $ 0.17
Pro forma $ 0.30 $ 0.17
Diluted earnings per share:
As reported $ 0.30 $ 0.17
Pro forma $ 0.30 $ 0.17
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Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flows Information
Three Months Ended
March 31,
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In millions 2004 2003
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(Unaudited)
Non-cash investing and financing activities:
Details of assets acquired:
Fair value of assets acquired $ -- $ 333
Cash paid for acquisitions -- (275)
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Liabilities assumed -- $ 58
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Details of consolidation of variable interest entities:
Assets $ 625 --
Liabilities (704) --
Details of deconsolidation of variable interest entities:
Assets $ (220) --
Liabilities 254 --
Reoffering of pollution-control bonds $ 196 --
Details of pollution-control bond redemption:
Release of funds held in trust $ 20 --
Pollution-control bonds redeemed (20) --
Details of long-term debt exchange offer:
Variable rate notes redeemed -- $ (966)
First and refunding bonds issued -- 966
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Variable Interest Entities
Entities Consolidated Upon Implementation of New Accounting Standard
SCE has variable interests in contracts with gas-fired cogeneration plants that contain variable pricing provisions based on gas
prices. Further, four of these contracts are with entities that are partnerships owned in part by a related party, EME. These four
contracts have 20-year terms. The cogeneration plants sell electricity to SCE and steam to non-related parties. Under a new
accounting standard, SCE consolidated these four projects effective March 31, 2004. Prior periods have not been restated. The book
value of the projects' plant assets is $401 million ($896 million at original cost less $495 million in accumulated depreciation) and
is recorded in nonutility property.
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Project Capacity Termination Date EME Ownership
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Kern River 290 MW August 2005 50%
Midway-Sunset 200 MW May 2009 50%
Sycamore 300 MW December 2007 50%
Watson 340 MW December 2007 49%
SCE has no investment in, nor obligation to provide support to, these entities other than its requirement to make payment as required
by the power-purchase agreements. Any liabilities of these projects are non-recourse to SCE.
Edison Capital has investments in affordable housing and wind projects that are variable interests. Effective March 31, 2004,
Edison Capital consolidated two affordable housing partnerships and three wind projects. These projects are funded with non-recourse
debt totaling $35 million at March 31, 2004. Properties serving as collateral for these loans had a carrying value of $50 million
and are classified as nonutility property on the March 31, 2004 balance sheet. The creditors to these projects do not have recourse
to the general credit of Edison Capital.
Entities Deconsolidated Upon Implementation of New Accounting Standard
EME deconsolidated the following two projects effective March 31, 2004. Prior periods have not been restated. EME will record its
interests in the Doga and Kwinana projects on the equity method beginning April 1, 2004.
Doga, a 180 MW gas-fired power plant in Turkey (of which EME owns 80%), has a power sales contract that is considered a variable
interest due to the energy price provisions that absorb the risk of changes in operating costs and the transfer of ownership of the
cogeneration plant to the energy purchaser at the end of the power sales contract.
Kwinana, a 116-MW gas-fired power plant in Australia (of which EME owns 70%), has power sales contracts that are considered variable
interests due to the energy price provisions that absorb the risk of changes in operating costs.
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant Variable Interests in Entities Not Consolidated
EME's
Variable EME's Ownership
Interest Investment at Interest at
Entity Location March 31, 2004 March 31, 2004 Description
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(In millions)
Paiton Indonesia $580 45% Coal-fired facility
EcoElectrica Puerto Rico 275 50% Liquefied natural gas
cogeneration facility
Sunrise California 84 50% Gas-fired facility
ISAB Italy 84 49% Gasification facility
CBK Philippines 74 50% Pumped-storage
hydroelectric facility
IVPC4 Srl Italy 39 50% Wind facilities
Doga Turkey 24 80% Gas-fired facility
Tri Energy Thailand 19 25% Gas-fired facility
EME's maximum exposure to loss is generally limited to its investment in these entities. EME's interest in the Kwinana project is
not a significant variable interest and, therefore, is not included in the table above.
Edison Capital's maximum exposure to loss from affordable housing investments in this category is generally limited to its investment
balance of $187 million and recapture of tax credits.
Information Out Scope Exception
SCE has 18 non-related-party contracts with gas-fired generating plants that contain variable pricing provisions based on gas
prices. SCE might be considered to be the consolidating entity under the new accounting standard. However, these entities are not
legally obligated to provide the financial information to SCE that is necessary to determine whether SCE must consolidate these
entities. These 18 entities have declined to provide SCE with the necessary financial information. SCE will continue to attempt to
obtain information for these projects in order to determine whether they should be consolidated by SCE. The aggregate capacity
dedicated to SCE for these projects is 471 MW. SCE paid $51 million for the quarter ended March 31, 2004 and $47 million for the
quarter ended March 31, 2003 to these projects. These amounts are recoverable in utility customer rates. SCE has no exposure to
loss as a result of its involvement with these projects.
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 holding company, is described in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2003 Annual Report.
CPUC Litigation Settlement Agreement
As discussed in the "CPUC Litigation Settlement Agreement" disclosure in Note 2 of "Notes to Consolidated Financial Statements"
included in Edison International's 2003 Annual Report, in
Page 12
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
October 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC that allowed SCE to recover $3.6 billion
in past procurement-related obligations. The Utility Reform Network, a consumer advocacy group, and other parties appealed to the
United States Court of Appeals for the Ninth Circuit (Ninth Circuit) seeking to overturn the stipulated judgment of the federal
district court that approved the 2001 CPUC settlement agreement. In September 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.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate California law in any
of the respects raised by the Ninth Circuit. The matter was returned to the Ninth Circuit for final disposition and in
December 2003, the Ninth Circuit unanimously affirmed the original stipulated judgment of the federal district court. In January
2004, the Ninth Circuit issued its mandate, relinquishing jurisdiction of the case and returning jurisdiction to the federal district
court. No petitions were filed within the 90-day period in which parties could seek discretionary review by the United States
Supreme Court of the federal district court's decision. Accordingly, the appeals of the stipulated judgment approving the 2001 CPUC
settlement agreement have been resolved in SCE's favor.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation 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, which alleged a pattern of
noncompliance with the CPUC's general orders for the maintenance of electric lines for 1998-2000. The order also alleged that
noncompliant conditions were involved in 37 accidents resulting in death, serious injury or property damage. The Consumer Protection
and Safety Division 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.
On April 22, 2004, the CPUC issued its decision which recognizes that a utility cannot avoid all nonconforming conditions and that no
penalty should be assessed unless the utility knew or should have known of the condition and failed to repair within a reasonable
amount of time. Of the 37 incidents involving personal injury or property damage, the decision concludes that in 7 incidents, there
was no violation of the general orders. The decision imposes a $20,000 penalty for each of the remaining 30 accidents. The decision
also provided the utility with more flexibility in scheduling inspections. In all, the decision imposes a total of $656,000 in
penalties on SCE. The decision declined to impose any penalty for 4,721 of the violations the Consumer Protection and Safety
Division originally identified because SCE promptly corrected those conditions when they were brought to SCE's attention and because
there was no showing that they could lead to serious potential harm. The decision also requires SCE to meet and confer with the CPUC
staff on several issues, including revisions to its maintenance priority system and possible alternatives to the existing high
voltage signage requirements.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2003 Annual Report, in May 2002, SCE filed an application with the CPUC to address
certain issues (mainly coal and slurry-water supply issues) facing the future extended operation of Mohave Generating Station
(Mohave), which is partly owned by SCE. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave
co-owners from making approximately $1.1 billion in Mohave-related
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
investments (SCE's share is $605 million), including the installation of pollution-control equipment that must be put in place in
order for Mohave to continue to operate beyond 2005, pursuant to a 1999 consent decree concerning air quality.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. SCE and other parties submitted further testimony and made various other filings in 2003 in SCE's application
proceeding. Pursuant to the assigned administrative law judge's March 9, 2004 ruling, on April 16, 2004 SCE updated its position and
testimony on cost data and, where unavailable, cost estimates for Mohave on the following options: (1) the cost of permanent
shutdown; (2) the cost of installation of required pollution controls and related capital improvements to allow the facility to
continue as a coal-fired plant beyond 2005; (3) if option 2 is undertaken, the cost of temporary shutdown for complete installation
of pollution controls; and any costs related to restarting the facility; and (4) other alternatives and their costs. SCE's testimony
presented a summary of work performed to date and provided an update on the status of the coal and water supply issues. The
testimony also stated that SCE does not now have detailed cost projections for any of the cost categories identified in the March 9,
2004 ruling due to the uncertainties remaining on these issues. The testimony reiterated SCE's belief that, even if the coal and
water supply issues can be satisfactorily resolved in the near future, thereby avoiding a permanent shutdown, a temporary shutdown of
at least approximately three years is likely. Evidentiary hearings have been scheduled for June 2004 with further submission of
written testimony by all parties prior to the hearings. The outcome of the coal and water negotiations and SCE's application are not
expected to impact Mohave's operation through 2005, but the presence or absence of Mohave as an available resource beyond 2005 could
have a major impact on SCE's long-term resource plan.
For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.
Wholesale Electricity and Natural Gas Markets
In 2000, the Federal Energy Regulatory Commission (FERC) initiated an investigation into the justness and reasonableness of rates
charged by sellers of electricity in the California Power Exchange and California Independent System Operator markets. On March 26,
2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and
natural gas markets in California and on the West Coast during 2000-2001 and describing many of the techniques and effects of that
market manipulation. SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and
natural gas who manipulated the electric and natural gas markets. Under the 2001 CPUC settlement agreement, mentioned in "CPUC
Litigation Settlement Agreement," 90% of any refunds actually realized by SCE will be refunded to customers, except for the El Paso
Natural Gas Company settlement agreement discussed below.
El Paso Natural Gas Company entered into a settlement agreement with parties to a class action lawsuit (including SCE, Pacific Gas
and Electric (PG&E) and the State of California) settling claims stated in proceedings at the FERC and in San Diego County Superior
Court that El Paso Natural Gas Company had manipulated interstate capacity and engaged in other anticompetitive behavior in the
natural gas markets in order to unlawfully raise gas prices at the California border in 2000-2001. The San Diego County Superior
Court approved the settlement on December 5, 2003. On April 21, 2004, parties to the settlement filed a joint request for a
stipulated judgment with the United States District Court seeking the court to supervise certain structural relief. Until the United
States District Court issues an order approving the stipulated judgment, the settlement agreement will not become effective and no
refunds will be paid. Pursuant to a CPUC decision, SCE will refund to customers any amounts received under
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the terms of the El Paso Natural Gas Company settlement (net of legal and consulting costs) through its energy resource recovery
account mechanism. In addition, amounts El Paso Natural Gas Company refunds to the CDWR will result in equivalent reductions in the
CDWR's revenue requirement allocated to SCE.
On February 24, 2004, SCE and PG&E agreed to settlement terms with The Williams Cos. and Williams Power Company, providing for
approximately $140 million in refunds and other payments to the settling purchasers and others against some of Williams' power
charges in 2000-2001. A settlement agreement based on the February 24, 2004 terms was executed by both the original settling parties
and by San Diego Gas & Electric Co. (SDG&E) on April 26, 2004. This settlement agreement proposed that approximately $34 million of
the total refunds and other payments be allocated to SCE. Also, on April 26, 2004, SCE, PG&E and SDG&E and several California state
governmental entities agreed to settlement terms with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc. The
April 26, 2004 settlement terms provide for refunds and other payments totaling $285 million, with a proposed allocation to SCE of
approximately $40 million. The allocation of refunds to market participants under these settlements has not been finally determined
and both settlements remain subject to the approval of the FERC and the CPUC.
Note 3. Pension Plan and Postretirement Benefits Other Than Pensions
Pension Plan
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2003 Annual Report that it expects to contribute approximately $47 million to its United States pension plans in
2004. As of March 31, 2004, $8 million in contributions have been made. Edison International expects to contribute approximately
$4 million to its foreign pension plans in 2004. As of March 31, 2004, $1 million in contributions have been made. Edison
International anticipates that its original expectations will be met by year-end 2004.
Expense components for United States plans are:
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 26 $ 24
Interest cost 43 43
Expected return on plan assets (58) (48)
Net amortization and deferral 6 9
- ---------------------------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 17 28
Regulatory adjustment - deferred -- (11)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 17 $ 17
- ---------------------------------------------------------------------------------------------------------------------------------------
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components for foreign plans are:
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 5 $ 4
Interest cost 10 8
Expected return on plan assets (10) (10)
Curtailment/settlement -- 8
Net amortization and deferral 1 --
- ---------------------------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 6 $ 10
- ---------------------------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2003 Annual Report that it expects to contribute approximately $100 million to its postretirement benefits other than
pensions plan in 2004. As of March 31, 2004, $6 million in contributions have been made. Edison International anticipates that its
original expectation will be met by year-end 2004.
Expense components are:
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 12 $ 11
Interest cost 34 31
Expected return on plan assets (28) (22)
Net amortization and deferral 7 10
- ---------------------------------------------------------------------------------------------------------------------------------------
Total expense $ 25 $ 30
- ---------------------------------------------------------------------------------------------------------------------------------------
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 invested in three aircraft leased to American Airlines. The independent auditors' opinion on the year-end 2003
financial statements of AMR Corporation, parent company of American Airlines, removed the comment on AMR Corporation's ability to
continue as a going concern from year-end 2002. However, while AMR Corporation reports some improvement, uncertainty remains and 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 March 31, 2004, American Airlines was
current in its lease payments to Edison Capital.
Employee Compensation and Benefit Plans
On July 31, 2003, a federal district court held that the formula used in a cash balance pension plan created by International
Business Machine Corporation (IBM) in 1999 violated the age discrimination provisions of the Employee Retirement Income Security Act
of 1974. In its decision, the federal district court set forth a standard for cash balance pension plans. This decision, however,
conflicts with the decisions from two other federal district courts and with the proposed regulations for cash balance pension plans
issued by the Internal Revenue Service (IRS) in December 2002. On February 12, 2004, the same federal district court ruled that IBM
must make back payments to workers covered under this plan. IBM has indicated that it will appeal both decisions to the United
States Court of Appeals for the Seventh Circuit. The formula for Edison International's cash balance pension plan does not meet the
standard set forth in the federal district court's July 31, 2003 decision. Edison International cannot predict with certainty the
effect of the two IBM decisions on Edison International's cash balance pension plan.
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 34 identified sites at SCE (26 sites) and EME (8 sites)
is $89 million, $87 million of which is related to SCE. 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $186 million, all 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 $29 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 $70 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 $13 million to $25 million. Recorded costs for the twelve months ended March 31, 2004 were
$16 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 IRS asserting deficiencies in federal corporate income taxes for its
1994 to 1996 tax years. The vast majority of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately
paid (exclusive of interest and penalties), 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.
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. This matter is now being considered by the
Administrative Appeals branch of the IRS. Edison Capital will contest the assessment through administrative appeals and litigation,
if necessary, and believes it should prevail in an outcome that will not have a material adverse financial impact.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The IRS is examining the tax returns for Edison International, which include Edison Capital, for years 1997 through 1999. Edison
Capital expects the IRS will also challenge several of its other leveraged leases based on recent Revenue Rulings 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.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the
possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice on contingent liability companies that was published in 2001. These transactions
include certain Edison Capital leveraged lease transactions discussed above and a transaction entered into by an SCE subsidiary,
which may be considered substantially similar to a listed transaction. Edison International filed these amended returns under
protest retaining its appeal rights and believes that it will prevail in an outcome that will not have a material financial impact.
Investigation Regarding Performance Incentives Rewards
SCE is eligible under its CPUC-approved performance-based rate-making (PBR) mechanism to earn rewards or penalties based on its
performance in comparison to CPUC-approved standards of reliability, customer satisfaction, and employee safety. SCE received two
letters over the last year from anonymous employees alleging that personnel in the service planning group of SCE's transmission and
distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by
an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any
incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE is conducting an internal
investigation and has determined that some wrongdoing by a number of the service planning employees has occurred. SCE has informed
the CPUC of its findings to date, and will continue to inform the CPUC of developments as the investigation progresses. SCE has
committed to the CPUC to refund or forego any customer satisfaction awards that were not appropriately earned. The CPUC could
instigate its own proceedings to determine whether any portion of past and potential rewards for customer satisfaction should be
refunded or disallowed. It also is possible that penalties could be imposed. SCE recorded aggregate customer satisfaction rewards
of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards aggregating $10 million for 2001 and 2002
are pending before the CPUC and have not been recognized in income by SCE. SCE also had anticipated that it could be eligible for
customer satisfaction rewards of about $10 million for 2003. SCE cannot predict with certainty the outcome of this matter. SCE has
taken prompt remedial action by severing the employment of several supervisory personnel, updating system processes and related
documentation for survey reporting, and implementing additional supervisory controls over data collection and processing.
Navajo Nation Litigation
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 Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power
District, and SCE arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,
violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual
relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed
motions to dismiss. The D.C. District Court denied these motions, except for Salt River Project Agricultural Improvement District's
motion requesting its separate dismissal from the lawsuit.
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 in the Court of Federal Claims against the United States Department of Interior. 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 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. Based on the Supreme
Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for summary judgment in the
D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003 motions to dismiss, or
in the alternative, for summary judgment.
The Federal Circuit Court of Appeals, acting on a suggestion on remand filed by the Navajo Nation, held in a October 24, 2003
decision that the Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations 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 Government and the Navajo Nation both filed petitions for rehearing of
the October 24, 2003 Court of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the Court of
Appeals issued an order remanding the case against the Government to the Federal Court of Claims.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of the Supreme Court's
decision in the Navajo Nation's suit against the Government on this complaint, 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 $10.8 billion. 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 United States 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
operators. All licensed operating plants including San Onofre and Palo Verde are grandfathered under the applicable law.
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 United States Department of Energy (DOE) is responsible for the selection and construction of a facility for
the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE has the obligation to begin acceptance of
spent nuclear fuel not later than January 31, 1998. However, the DOE did not meet its obligation. It is not certain when the DOE
will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the
construction of costly alternatives, including 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. On January 29, 2004,
SCE, as operating agent, filed a complaint against the DOE in the Federal Court of Claims seeking damages for DOE's failure to meet
its obligation to begin accepting spent nuclear fuel from San Onofre.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored
in the San Onofre Units 1, 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation. Movement of Unit
1 spent fuel from the Unit 3 spent fuel pool to the independent spent fuel storage installation was completed in late 2003. Movement
of Unit 1 spent fuel from the Unit 1 spent fuel pool to the independent spent fuel storage installation is scheduled to be completed
by late 2004 and from the Unit 2 spent fuel pool to the independent spent fuel storage installation by late 2005. With these moves,
there will be sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008,
respectively. In order to maintain a full core off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the
independent spent fuel storage installation 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, as operating agent, plans to continually load casks on a schedule to maintain full core off-load
capability for all three units.
Storm Lake
As of March 31, 2004, Edison Capital had an investment of approximately $63 million in Storm Lake Power, a project developed by Enron
Wind, a subsidiary of Enron Corporation. As of March 31, 2004, Storm Lake had outstanding loans of approximately $55 million. The
lenders claim that Enron's bankruptcy, among other things, is an event of default under the loan agreement and as a result, the debt
has been reclassified to long-term debt due within one year. However, the lenders are currently discussing resolution of the
defaults with Storm Lake and are not actively pursuing remedies.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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).
Segment information for the three months ended March 31, 2004 and 2003 was:
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 1,696 $ 1,814
Nonutility power generation 783 684
Financial services 29 21
Corporate and other 2 4
- ---------------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,510 $ 2,523
- ---------------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 100 $ 102
Nonutility power generation(2) 31 (17)
Financial services(3) 11 15
Corporate and other (45) (43)
- ---------------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 97 $ 57
- ---------------------------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock. Includes earnings from discontinued operations of $3 million for the three months
ended March 31, 2003.
(2) Includes a loss of $9 million from the cumulative effect of an accounting change for the three months ended March 31, 2003.
(3) Includes a loss of $1 million from the cumulative effect of an accounting change for the three months ended March 31, 2004.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment. The net loss of
$45 million and $43 million, respectively, reported for the three months ended March 31, 2004 and 2003, also includes Mission Energy
Holding Company's (MEHC) net loss of $25 million and $24 million, respectively, for the same periods.
Total segment assets as of March 31, 2004 were: electric utility, $20 billion; nonutility power generation, $12 billion; and,
financial services, $4 billion.
Note 6. Acquisitions and Dispositions
On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in Redlands, California.
SCE has recommenced full construction of the
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately $600 million project, which is expected to be completed in 2006. The construction work in progress for this project is
recorded in nonutility property on Edison International's March 31, 2004 balance sheet.
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 United States dollar denominated notes. The Taranaki station is a 357 MW
combined cycle, natural gas-fired plant located near Stratford, New Zealand.
On March 31, 2004, EME completed the sale of its 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P. for a
sales price of approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related
to the planned disposition of this investment and a pre-tax loss of approximately $4 million during the first quarter of 2004 due to
changes in the terms of the sale.
On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn holds minority
interests in Four Star Oil & Gas. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale
of approximately $47 million during the first quarter of 2004.
Note 7. 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 the three months ended March 31, 2003. 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.
For the three months ended March 31, 2004 and 2003, revenue from discontinued operations was zero and $9 million, respectively, and
pre-tax income was zero and $5 million, respectively.
The discontinued operations balance sheet at March 31, 2004 and December 31, 2003 is comprised of current assets of $5 million, for
each period, other noncurrent assets of $11 million, for each period, current liabilities of $2 million and $3 million, respectively,
and noncurrent liabilities of $9 million and $10 million, respectively.
Note 8. Subsequent Event
Midwest Generation Financing Developments
On April 27, 2004, EME's subsidiary, Midwest Generation, completed a private offering of $1 billion aggregate principal amount of its
8.75% second priority senior secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase the notes on
May 1, 2014 and on each one-year
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrently with the issuance of the
notes, Midwest Generation borrowed $700 million under a new first priority senior secured institutional term loan facility. The term
loans mature on April 27, 2011 and bear interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to repay $1,750,000 of
the term loans on each quarterly payment date. Midwest Generation also entered into a new, three-year $200 million working capital
facility that replaced a prior facility. The new working capital facility also provides for the issuance of letters of credit.
Midwest Generation used the proceeds of the notes issuance and the term loans to refinance $693 million of indebtedness (plus accrued
interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which was guaranteed by Midwest Generation and was
due in December 2004, and to make termination payments under the Collins Station lease of approximately $960 million, including
accrued interest and fees.
Midwest Generation is permitted to use the new working capital facility and cash on hand to provide credit support for forward
contracts with third party counterparties entered into by Edison Mission Marketing & Trading for capacity and energy generated from
the Illinois plants. Utilization of this credit facility in support of such forward contracts is expected to provide additional
liquidity support for implementation of EME's contracting strategy for the Illinois plants.
The term loan and working capital facility share a first priority lien and the senior secured notes have a second priority lien in a
collateral package which consists of, among other things, substantially all of the coal-fired generating plants owned by Midwest
Generation and the assets relating to those plants, as well as the equity interests of Midwest Generation and its parent company and
the intercompany notes entered into by EME and Midwest Generation in connection with the Powerton-Joliet sale-leaseback transaction.
Termination of Collins Station Lease
On April 27, 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity
investor. Midwest Generation made a lease termination payment of approximately $960 million, including accrued interest and fees.
This amount repaid the $774 million of lease debt outstanding, accrued interest and fees, and the amount owing to the lease equity
investor upon an early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction
and, subject to its power-purchase agreement with Exelon Generation, plans to abandon the Collins Station or sell it to a third
party. EME expects to record a pre-tax loss of approximately $1 billion (approximately $620 million after tax) during the second
quarter ended June 30, 2004, due to termination of the lease and the planned abandonment or sale of the asset. Prior to the
termination of the lease, EME reached an agreement with the lease equity investors in the Powerton-Joliet leases to waive the net
worth covenant included in the EME lease equity guarantee provided to them and, accordingly, the reduction in shareholder equity
resulting from the loss on termination of the Collins Station lease did not result in a default under this guarantee.
If the termination of the Collins Station lease is followed by abandonment or sale to a third party as currently planned, EME
anticipates that the termination payment would result in a substantial income tax deduction, thereby providing additional
tax-allocation payments through the income tax-allocation agreement when such loss can be used by Edison International in its
consolidated and combined income tax returns.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EME Financing Developments
On April 27, 2004, EME replaced its $145 million corporate credit facility with a new $98 million secured credit facility. This
credit facility matures on April 26, 2007. Loans made under this credit facility bear interest at LIBOR plus 3.50% per annum. As
security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which
it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects (four cogeneration projects located in
California), and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it
from the Kern River, Midway-Sunset, Sycamore, and Watson cogeneration projects will be deposited. EME will be free to use these
proceeds unless and until an event of default occurs under its corporate credit facility.
In addition, EME completed the repayment of the remaining $28 million due under the Coal and Capex facility (guaranteed by EME) in
April 2004. Accordingly, this credit agreement has been terminated and EME no longer has a contingent liability related to this
credit agreement.
Page 25
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
INTRODUCTION
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three-month period ended
March 31, 2004 discusses material changes in the financial condition, results of operations and other developments of Edison
International since December 31, 2003, and as compared to the three-month period ended March 31, 2003. This discussion presumes that
the reader has read or has access to Edison International's MD&A for the calendar year 2003 (the year-ended 2003 MD&A), which was
included in Edison International's 2003 annual report to shareholders and incorporated by reference into Edison International's
Annual Report on Form 10-K for the year ended December 31, 2003.
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 and uncertainties that could cause actual future outcomes and results of operations to be
materially different from those set forth in this discussion. Important factors that could cause actual results to differ are
discussed throughout this MD&A. The following discussion provides updated information about material developments since the issuance
of the year-ended 2003 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, 2003.
Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison
International's principal operating subsidiaries are Southern California Edison Company (SCE), Edison Mission Energy (EME) and Edison
Capital. Mission Energy Holding Company (MEHC) is a holding company for EME. SCE comprises the largest portion of the assets and
revenue of Edison International. 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.
This MD&A is presented in 11 major sections. The MD&A begins with a discussion of current developments. Following is a
company-by-company discussion of Edison International's principal operating subsidiaries (SCE, MEHC and EME, Edison Capital) and
Edison International (parent). Each principal operating subsidiary's discussion includes discussions of liquidity, market risk
exposures, and other matters (as relevant to each principal operating subsidiary). The remaining sections discuss Edison
International on a consolidated basis, including results of operations and historical cash flow analysis, acquisitions and
dispositions, critical accounting policies, new accounting principles, commitments and guarantees, and other developments. These
sections should be read in conjunction with each subsidiary's section.
Page
----
Current Developments 28
SCE 31
MEHC and EME 41
Edison Capital 63
Edison International (Parent) 64
Results of Operations and Historical Cash Flow Analysis 66
Page 26
Acquisitions and Dispositions 71
Critical Accounting Policies 71
New Accounting Principles 72
Commitments and Guarantees 73
Other Developments 73
Page 27
CURRENT DEVELOPMENTS
SCE: Current Developments
CPUC Litigation Settlement Agreement
As discussed in the "CPUC Litigation Settlement Agreement" disclosure in the year-ended 2003 MD&A, the United States Court of Appeals
for the Ninth Circuit and the California Supreme Court issued decisions upholding the federal district court judgment that approved
SCE's settlement agreement with the CPUC. The settlement agreement provided for SCE to recover $3.6 billion of procurement-related
costs from the California energy crisis. The time during which The Utility Reform Network (TURN) and other parties could further
appeal the court decisions has now expired. Accordingly, the appeals of the stipulated judgment approving the 2001 CPUC settlement
agreement have been resolved in SCE's favor. See "SCE: Regulatory Matters--Generation and Power Procurement--CPUC Litigation
Settlement Agreement."
General Rate Case
On April 22, 2004, a CPUC commissioner issued an alternate proposed decision on SCE's 2003 General Rate Case (GRC) application. This
alternate proposed decision, if adopted, would increase SCE's authorized base rate revenue requirement by $129 million, an increase
of $80 million over the proposed decision previously issued by a CPUC administrative law judge. On May 3, 2004, SCE filed comments
on the alternate proposed decision which (1) identified calculation errors resulting in a downward revision to SCE's authorized base
rate revenue requirement increase from $129 million to approximately $107 million and (2) argued for an increase in certain areas of
capital-related costs and operating and maintenance expenses. SCE expects to receive a final decision in the second quarter of
2004. Because processing of the 2003 General Rate Case took longer than initially scheduled, in May 2003 the CPUC approved SCE's
request to establish a memorandum account to track the revenue requirement increase during the period between May 22, 2003 (the date
a final CPUC decision was originally scheduled to be issued) and the date a final decision is ultimately adopted. The revenue
requirement approved in the final 2003 General Rate Case decision will be effective retroactive to May 22, 2003. As a result,
depending on the final outcome, SCE could report a benefit from the recording of revenue that was tracked in this memorandum account
since May 2003. See "SCE: Regulatory Matters--Transmission and Distribution--2003 General Rate Case Proceeding" for further details.
Mountainview Acquisition
On March 12, 2004, SCE completed the purchase of Mountainview Power Company LLC, the owner of a new 1,054-megawatt (MW),
combined-cycle, natural gas-fired power plant currently being developed in Redlands, California. SCE estimates that the project will
be completed in March 2006 at a cost of approximately $600 million, excluding financing costs. SCE expects to finance the capital
costs of the project with debt and equity consistent with SCE's authorized capital structure. Mountainview Power Company LLC will
sell all the output of the power plant to SCE pursuant to a 30-year tolling power-purchase agreement. See "Acquisitions and
Dispositions" for further discussion.
MEHC and EME: Current Developments
Exercise of Term Loan Put-Option at MEHC
On April 5, 2004, the lenders under MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase
$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 to pay its obligations with respect
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to the exercise by its term loan lenders of the Term Loan Put-Option, MEHC will require additional cash from dividends from EME.
Dividend Plan to MEHC
EME expects to make a dividend of approximately $75 million to MEHC during the next three months in order to provide funds for MEHC
to pay its obligations with respect to the exercise by its term loan lenders of the Term Loan Put-Option.
EME amended its certificate of incorporation and bylaws to eliminate the so-called "ring fencing" provisions that were implemented in
early 2001 during the California energy crisis. The ring fencing provisions were implemented to protect EME's credit rating from the
negative events then affecting Edison International and SCE. Management believes that these provisions, which included dividend
restrictions and a requirement to maintain an independent director, are no longer necessary.
Completion of Midwest Generation Refinancing
On April 27, 2004, Midwest Generation completed the issuance of $1 billion aggregate principal amount of its 8.75% second priority
senior secured notes and entered into a new credit agreement, which includes a $700 million, first priority senior secured term loan
facility and a $200 million, first priority senior secured working capital facility. Proceeds from these transactions were used to
refinance $693 million of indebtedness (plus accrued interest and fees) and to make termination payments under the Collins Station
lease in the amount of approximately $960 million, including accrued interest and fees. The new working capital facility replaced an
existing working capital facility. Completion of these financings was a major goal of 2004. See "MEHC and EME: Liquidity--Key
Financing Developments--Midwest Generation Financing Developments" for further details related to these financings. Also, see "MEHC
and EME: Liquidity --Termination of the Collins Station Lease" for details related to termination of the Collins Station lease.
EME Financing Developments
On April 27, 2004, EME replaced its $145 million corporate credit facility with a new three-year $98 million secured credit facility.
In addition, EME repaid the remaining $28 million due under the Coal and Capex facility (guaranteed by EME) in April 2004.
Accordingly, this credit agreement has been terminated and EME no longer has a contingent liability related to this credit agreement.
Selling Some or All of EME's International Operations
As indicated in the year-ended 2003 MD&A, EME has engaged investment bankers to market for sale its international project portfolio.
The marketing efforts continue to progress, and an announcement will be made once one or more buyers are selected and successful
negotiations are concluded.
Expansion of PJM in Illinois
The Illinois plants are located within the service territory of Exelon Generation's affiliate, Commonwealth Edison, which on April
27, 2004 was granted approval by the Federal Energy Regulatory Commission (FERC), to join the Pennsylvania-New Jersey-Maryland (PJM)
System effective May 1, 2004.
On March 19, 2004, in a separate but related matter, the FERC issued an order having the effect of postponing to December 1, 2004 the
effective date for elimination of regional through and out rates in the region encompassed by PJM (as expanded by the addition of
Commonwealth Edison and as to be further
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expanded by the addition of American Electric Power (AEP)) and the Midwest Independent System Operation (MISO). The effect of this
order is that the so-called rate pancaking was not eliminated prior to Commonwealth Edison's integration into PJM, nor will it be
eliminated prior to AEP's scheduled date for integration into PJM. Rate pancaking occurs when energy must move through multiple,
separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner
along the line charges separately for the use of its system. Accordingly, EME will continue to have to pay transmission charges for
power sold for delivery outside of Commonwealth Edison's former control area, now known under PJM as PJM's Northern Illinois Control
Area (NICA). The FERC has included in its order a strong statement that the existing through and out rates must be eliminated no
later than December 1, 2004. See "MEHC and EME: Market Risk Exposures--Commodity Price Risk --Illinois Plants."
EME is continuing to monitor the activities at the FERC related to the expansion of PJM in Illinois and advocate regulatory positions
that promote efficient and fair markets in which the Illinois plants compete.
Page 30
SOUTHERN CALIFORNIA EDISON COMPANY
SCE: LIQUIDITY ISSUES
SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs and access to capital markets or
external financings. At March 31, 2004, SCE's credit ratings from both Moody's Investors Service and Standard & Poor's were
investment grade.
At March 31, 2004, SCE had cash and equivalents of $528 million and long-term debt, including current maturities, of $5.6 billion.
SCE has a $700 million credit facility that expires in December 2006. As of March 31, 2004, the credit facility was not utilized,
except for $2 million supporting letters of credit. SCE's 2004 estimated cash outflows consist of:
o $125 million of 5.875% bonds due in September 2004;
o Approximately $246 million of rate reduction notes that are due at various times in 2004, but which have a separate cost
recovery mechanism approved by state legislation and CPUC decisions;
o Projected capital expenditures of $1.9 billion, including the investment in the Mountainview project and related capital
expenditures (see "Acquisitions and Dispositions");
o Dividend payments to SCE's parent company;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations and cash outflows for undercollections (if incurred) through cash and equivalents on
hand, operating cash flows and short-term borrowings, when necessary. Projected capital expenditures are expected to be financed
through cash flows and the issuance of long-term debt.
On March 30, 2004, SCE transferred, through a dividend to Edison International, $300 million of common equity that exceeded the
CPUC-authorized level. The purpose of this dividend was to continue to rebalance SCE's capital structure in accordance with CPUC
requirements.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In its most recent cost of
capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE
determines compliance with this capital structure based on a 13-month weighted-average calculation. At March 31, 2004, SCE's
13-month weighted-average common equity component of total capitalization was 56%. At March 31, 2004, SCE had the capacity to pay
$746 million in additional dividends and continue to maintain its CPUC-authorized capital structure based on the 13-month
weighted-average method. Based on recorded March 31, 2004 balances, SCE's common equity to total capitalization ratio, for
rate-making purposes, was approximately 48%. SCE had no capacity to pay additional dividends based on March 31, 2004 recorded
balances.
In January 2004, SCE issued $975 million of first and refunding mortgage bonds. The issuance included $300 million of 5% bonds due
in 2014, $525 million of 6% bonds due in 2034 and $150 million of floating rate bonds due in 2006. The proceeds were used to redeem
$300 million of 7.25% first and refunding mortgage bonds due March 2026, $225 million of 7.125% first and refunding mortgage bonds
due July 2025, $200 million of 6.9% first and refunding mortgage bonds due October 2018, and
Page 31
$100 million of junior subordinated deferrable interest debentures due June 2044. In the first quarter of 2004, SCE remarketed
approximately $550 million of pollution-control bonds with varying maturity dates ranging from 2008 to 2040, of which approximately
$196 million of these pollution-control bonds were reoffered. In March 2004, SCE issued $300 million of 4.65% first and refunding
mortgage bonds due in 2015 and $350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the proceeds from
the March 2004 first and refunding mortgage bond issuances were used to fund the acquisition and construction of the Mountainview
project, with the remainder of the proceeds to be used for ongoing capital expenditures for generation, transmission and distribution
facilities, and for general corporate purposes.
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 California Department of Water Resources (CDWR) contracts) on January 1, 2003,
and as of March 31, 2004, had posted approximately $23 million ($21 million in cash and $2 million in letters of credit) as
collateral to secure its obligations under power-purchase contracts and to transact through the Independent System Operator (ISO) for
imbalance energy. SCE's collateral requirements can vary depending upon the level of unsecured credit extended by counterparties,
the ISO's credit requirements, changes in market prices relative to contractual commitments, and other factors.
SCE's liquidity may be affected by, among other things, matters described in "SCE: Regulatory Matters."
SCE: MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, generating fuel commodity prices and volume and counterparty
credit. Fluctuations in interest rates can affect earnings and cash flows. However, fluctuations in fuel prices and volumes and
counterparty credit losses temporarily affect cash flows, but should not affect earnings. See "SCE: Market Risk Exposures" in the
year-ended 2003 MD&A for a complete discussion of SCE's market risk exposures.
SCE: REGULATORY MATTERS
This section of the MD&A describes SCE's regulatory matters in three main subsections:
o generation and power procurement;
o transmission and distribution; and
o other regulatory matters.
Generation and Power Procurement
Proposed Legislation
The California legislature is currently considering a bill that is intended to create a durable regulatory framework to stimulate
investment in generation resources. Assembly Bill 2006, which is entitled the "Reliable Electric Service Act," proposes to affirm
the obligation of utilities to plan and provide adequate, efficient, and cost-effective supply and demand resources and requires
utilities to prepare a long-term resource plan to achieve a diversified portfolio of cost-effective supply and demand resources. The
proposed bill also states that the CPUC must establish and maintain rates that ensure the full recovery of reasonable investments
made by utilities, and the full cost of contracting for non-utility generation.
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CPUC Litigation Settlement Agreement
As discussed in the "CPUC Litigation Settlement Agreement" disclosure in the year-ended 2003 MD&A, in October 2001, SCE and the CPUC
entered into a settlement of SCE's lawsuit against the CPUC that allowed SCE to recover $3.6 billion in past procurement-related
obligations. TURN, a consumer advocacy group, and other parties appealed to the Ninth Circuit seeking to overturn the stipulated
judgment of the federal district court that approved the 2001 CPUC settlement agreement. In September 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.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate California law in any
of the respects raised by the Ninth Circuit. The matter was returned to the Ninth Circuit for final disposition, and in December
2003, the Ninth Circuit unanimously affirmed the original stipulated judgment of the federal district court. In January 2004, the
Ninth Circuit issued its mandate, relinquishing jurisdiction of the case and returning jurisdiction to the federal district court.
No petitions were filed within the 90-day period in which parties could seek discretionary review by the United States Supreme Court
of the federal district court's decision. Accordingly, the appeals of the stipulated judgment approving the 2001 CPUC settlement
agreement have been resolved in SCE's favor.
Energy Resource Recovery Account Proceedings
As discussed in the "Energy Resource Recovery Account Proceedings" disclosure in the year-ended 2003 MD&A, the CPUC established the
Energy Resource Recovery Account (ERRA) as the rate-making mechanism to track and recover SCE's generation-related costs.
SCE submitted its first ERRA forecast application in April 2003, in which it forecasted a procurement-related revenue requirement for
the 2003 calendar year of $2.5 billion. On January 22, 2004, the CPUC issued a decision that approved SCE's forecast as submitted.
SCE submitted its second ERRA forecast application on October 3, 2003, in which it forecasted a procurement-related revenue
requirement for the 2004 calendar year of $2.3 billion. The CPUC issued a decision on April 22, 2004, approving SCE's 2004 forecast
revenue requirement and rates for both generation and delivery services.
On October 3, 2003, SCE submitted its first ERRA reasonableness review application requesting that the CPUC find its
procurement-related operations during the period from September 1, 2001 through June 30, 2003 to be reasonable. Because this is the
first annual review of this activity, pursuant to new California state law, the CPUC's interpretation and application of California
state law is uncertain. Pursuant to the assigned commissioner's scoping memo issued on December 9, 2003, the CPUC's Office of
Ratepayer Advocates (ORA) was allowed to review the accounting calculations used in the Procurement-Related Obligations Account
(PROACT) mechanism. The ORA testimony, filed on March 19, 2004, included an audit of these accounting calculations, in which ORA
recommended disallowances that totaled approximately $14 million of costs recovered through the PROACT mechanism during the period
from September 1, 2001 through June 30, 2003. In April 2004, SCE reached an agreement with the ORA (subject to CPUC approval) to
reduce the PROACT disallowances to approximately $3.6 million. This amount, which is mainly comprised of ISO grid management charges
and employee-related retraining costs, would be refunded to ratepayers through a credit to the ERRA account. A decision on this
matter is expected in mid-2004.
In addition to its disallowance recommendations, ORA recommended that in reviewing SCE's administration of its procurement contracts
and the daily dispatch of its generation resources, the CPUC should perform a traditional "reasonableness review," that is, SCE
should have the burden of proving that its decisions during the record period complied with what a "reasonable manager" would have
done under similar circumstances. In its opening brief filed on April 30, 2004, SCE urged the CPUC to reject
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this recommendation, stating that under recent California law, SCE's burden is to demonstrate that its decisions complied with the
dispatch standard that a 2002 CPUC decision had placed in SCE's approved procurement plan; i.e., that SCE used the most
cost-effective mix of the total generation resources available to it, thereby minimizing the cost of delivering electric services to
its customers. SCE believes the latter standard is required by law, and is more objective than the standard ORA advocates. A
decision on ERRA operations through June 30, 2003 is expected in mid-2004.
On April 1, 2004, SCE filed an ERRA application requesting that the CPUC find that its procurement-related costs and operations,
including its dispatch of generation resources and administration of procurement contracts costs, for the period July 1, 2003 through
December 31, 2003, were reasonable. In addition, SCE requested a $15 million increase in its annual revenue requirement, consisting
of a $10 million reward for efficient operation of Unit 3 of the Palo Verde Nuclear Generating Station (Palo Verde), and $5 million
in electric energy transaction administration costs. A decision on this application is expected in by the end of 2004.
Generation Procurement Proceedings
SCE resumed power procurement responsibilities for its residual-net short position on January 1, 2003, pursuant to CPUC orders and
California statutes passed in 2002. The current regulatory and statutory framework requires SCE to assume limited responsibilities
for CDWR contracts allocated by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term
procurement plans, long-term resource plans and increased procurement of renewable resources. See "Generation Procurement
Proceedings" disclosure in the year-ended 2003 MD&A for further discussion of the matters discussed below.
Short-Term Procurement Plan
In December 2003, the CPUC adopted a 2004 short-term procurement plan for SCE, which established a maximum target level for spot
market purchases equal to 5% of monthly need, and allowed SCE to enter into contracts of up to five years. SCE is currently
operating under this approved short-term procurement plan.
Long-Term Resource Plan
On April 15, 2003, SCE filed its long-term resource plan with the CPUC which included both a preferred plan and an interim plan. In
January 2004, the CPUC issued a decision which did not adopt any long-term resource plan, but adopted a framework for resource
planning. Until the CPUC approves a long-term resource plan for SCE, SCE will operate under its interim resource plan.
On April 1, 2004, the CPUC instituted a resource planning proceeding which will coordinate consideration of long-term resource
plans. This resource planning proceeding is designed to (1) review and adopt long-term resource plans for SCE, Pacific Gas and
Electric (PG&E) and San Diego Gas & Electric (SDG&E); (2) address resource adequacy issues; (3) address the treatment of confidential
information; (4) develop procurement incentives for each utility; (5) develop a long-term policy for expiring qualifying facilities
(QF) contracts; and (6) review the management audits of SDG&E's and PG&E's electric procurement transactions with affiliates. SCE
and the other utilities have submitted outlines of their respective long-term resource plans. SCE expects a ruling on the schedule
for the proceeding in May 2004.
Procurement of Renewable Resources
As part of SCE's resumption of power procurement, in accordance with a California statute passed in 2002, SCE is required to increase
its procurement of renewable resources by at least 1% of its annual
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electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than
December 31, 2017. In June 2003, the CPUC issued a decision adopting preliminary rules and guidance on renewable procurement-related
issues, including penalties for noncompliance with renewable procurement targets. The CPUC has set further proceedings to develop
additional renewable procurement-related rules.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003, and is finalizing its
evaluation of such bids to determine which bidders, if any, it intends to negotiate with regarding potential procurement contracts.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2003 MD&A, on May 17, 2002, SCE
filed an application with the CPUC to address certain issues (mainly coal and slurry-water supply issues) facing the future extended
operation of Mohave Generating Station (Mohave), which is partly owned by SCE. The uncertainty over a post-2005 coal and water
supply has prevented SCE and other Mohave co-owners from making approximately $1.1 billion in Mohave-related investments (SCE's share
is $605 million), including the installation of pollution-control equipment that must be put in place in order for Mohave to continue
to operate beyond 2005, pursuant to a 1999 consent decree concerning air quality.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. SCE and other parties submitted further testimony and made various other filings in 2003 in SCE's application
proceeding. Pursuant to the assigned administrative law judge's March 9, 2004 ruling, on April 16, 2004 SCE updated its position and
testimony on cost data and, where unavailable, cost estimates for Mohave on the following options: (1) the cost of permanent
shutdown; (2) cost of installation of required pollution controls and related capital improvements to allow the facility to continue
as a coal-fired plant beyond 2005; (3) if option 2 is undertaken, cost of temporary shutdown for complete installation of pollution
controls, and any costs related to restarting the facility; and (4) other alternatives and their costs. SCE's testimony presented a
summary of work performed to date and provided an update on the status of the coal and water supply issues. The testimony also
stated that SCE does not now have detailed cost projections for any of the cost categories identified in the March 9, 2004 ruling due
to the uncertainties remaining on these issues. The testimony reiterated SCE's belief that, even if the coal and water supply issues
can be satisfactorily resolved in the near future, thereby avoiding a permanent shutdown, a temporary shutdown of at least
approximately three years is likely. Evidentiary hearings have been scheduled for June 2004 with further submission of written
testimony by all parties prior to the hearings. The outcome of the coal and water negotiations and SCE's application are not
expected to impact Mohave's operation through 2005, but the presence or absence of Mohave as an available resource beyond 2005 could
have a major impact on SCE's long-term resource plan.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its application for a 2003 GRC, requesting an increase of $286 million in SCE's base rate revenue
requirement, which was subsequently revised to an increase of $251 million. The application also proposed an estimated base rate
revenue decrease of $78 million in 2004, and a subsequent increase of $116 million in 2005. The forecast reduction in 2004 was
largely attributable to the expiration of the San Onofre Nuclear Generating Station (San Onofre) incremental cost incentive pricing
(ICIP) rate-making mechanism at year-end 2003 and a forecast of increased sales.
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In a proposed decision issued on February 13, 2004, a CPUC administrative law judge recommended that the CPUC adopt only $15 million
of the $251 million increase in authorized base rate revenue requirement that SCE had requested. On April 1, 2004, the CPUC issued a
draft proposed decision that corrected a number of computational errors, adjusting the previous proposed decision's $15 million
revenue requirement increase to $49 million. On April 22, 2004, a CPUC Commissioner issued an alternate proposed decision, which, if
adopted would authorize a $129 million increase in SCE's base rate revenue requirement. On May 3, 2004, SCE filed comments on the
alternate proposed decision which (1) identified calculation errors resulting in a downward revision to SCE's authorized base rate
revenue requirement increase from $129 million to approximately $107 million and (2) argued for an increase in certain areas of
capital-related costs and operating and maintenance expenses. A final CPUC decision is expected in May 2004, however, SCE cannot
predict with certainty the final outcome of SCE's GRC application.
If the CPUC adopts the CPUC Commissioner's alternative proposed decision and if SCE does not reduce its expected capital or operating
expenditures accordingly, SCE estimates that on an annual basic SCE's earnings per share would be about 6(cent)-per-share lower and cash
flow would be approximately $73 million lower than if SCE's base rate request had been granted in full.
Because processing of the GRC took longer than initially scheduled, in May 2003 the CPUC approved SCE's request to establish a
memorandum account to track the revenue requirement increase during the period between May 22, 2003 (the date a final CPUC decision
was originally scheduled to be issued) and the date a final decision is ultimately adopted. The revenue requirement approved in the
final GRC decision will be effective retroactive to May 22, 2003. Any balance in the GRC memorandum account authorized by the CPUC
would be recovered in rates beginning in 2004, together with the combined revenue requirement authorized by the CPUC in the GRC
decision for 2003 and 2004.
Hearings to address revenue allocation and rate design issues have been continued until after the CPUC issues a decision on SCE's
revenue requirement. Due to the implementation of SCE's $1.2 billion customer rate-reduction plan, rate design changes will not be
effective until August 2004, at the earliest. Until SCE's 2003 GRC is implemented, SCE's revenue requirement related to distribution
operations is determined through a performance-based rate-making (PBR) mechanism.
On April 5, 2004, the ORA petitioned to reopen SCE's 2003 GRC request so the CPUC could consider what effect, if any, the
investigation regarding performance rewards (see "--Other Regulatory Matters--Investigation Regarding Performance Incentive Rewards")
would have on SCE's 2003 GRC revenue requirement. SCE filed its responses to the ORA's petition on April 9, 2004, reiterating its
commitment to refund any improperly collected funds and pointing out the need for a final decision rather than keeping SCE's 2003 GRC
open to litigate the performance incentive rewards.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation 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, which alleged a pattern of
noncompliance with the CPUC's general orders for the maintenance of electric lines for 1998-2000. The order also alleged that
noncompliant conditions were involved in 37 accidents resulting in death, serious injury or property damage. The Consumer Protection
and Safety Division 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.
On April 22, 2004, the CPUC issued its decision which recognizes that a utility cannot avoid all nonconforming conditions and that no
penalty should be assessed unless the utility knew or should have
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known of the condition and failed to repair within a reasonable amount of time. Of the 37 incidents involving personal injury or
property damage, the decision concludes that in 7 incidents, there was no violation of the general orders. The decision imposes a
$20,000 penalty for each of the remaining 30 accidents. The decision also provides the utility with more flexibility in scheduling
inspections. In all, the decision imposes a total of $656,000 in penalties on SCE. The decision declined to impose any penalty for
4,721 of the violations the Consumer Protection and Safety Division originally identified because SCE promptly corrected those
conditions when they were brought to SCE's attention and because there was no showing that they could lead to serious potential
harm. The decision also requires SCE to meet and confer with the CPUC staff on several issues, including revisions to its
maintenance priority system and possible alternatives to the existing high voltage signage requirements.
Transmission Proceeding
In August and November 2002, the FERC issued opinions affirming a September 1999 administrative law judge decision to disallow, among
other things, recovery by SCE and the other California public utilities of costs reflected in network transmission rates associated
with ancillary services and losses incurred by the utilities in administering existing wholesale transmission contracts after
implementation of the restructured California electric industry. After the three California utilities appealed the decisions to the
United States Court of Appeals for the D.C. Circuit, the FERC filed a motion with the Court seeking voluntary remand to permit
issuance of a further order. On February 12, 2004, the Court granted the FERC's motion and remanded the record back to the FERC for
further consideration. On May 6, 2004, the FERC issued its order reaffirming its earlier decisions. At this time, SCE intends to
appeal.
Wholesale Electricity and Natural Gas Markets
In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of electricity in the
California Power Exchange (PX)/ ISO markets. On March 26, 2003, the FERC staff issued a report concluding that there had been
pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the west coast during
2000-2001 and describing many of the techniques and effects of that market manipulation. SCE is participating in several related
proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas
markets. Under the 2001 CPUC settlement agreement, mentioned in "--Generation and Power Procurement--CPUC Litigation Settlement
Agreement," 90% of any refunds actually realized by SCE will be refunded to customers, except for the El Paso Natural Gas Company
settlement agreement discussed below.
El Paso Natural Gas Company entered into a settlement agreement with parties to a class action lawsuit (including SCE, PG&E and the
State of California) settling claims stated in proceedings at the FERC and in San Diego County Superior Court that El Paso Natural
Gas Company had manipulated interstate capacity and engaged in other anticompetitive behavior in the natural gas markets in order to
unlawfully raise gas prices at the California border in 2000-2001. The San Diego County Superior Court approved the settlement of
the San Diego lawsuit on December 5, 2003. On April 21, 2004, parties to the settlement filed a joint request for a stipulated
judgment with the United States District Court seeking the court to supervise certain structural relief. Until the United States
District Court issues an order approving the stipulated judgment, the settlement agreement will not become effective and no refunds
will be paid. Pursuant to a CPUC decision, SCE will refund to customers any amounts received under the terms of the El Paso Natural
Gas Company settlement (net of legal and consulting costs) through its ERRA mechanism. In addition, amounts El Paso Natural Gas
Company refunds to the CDWR will result in equivalent reductions in the CDWR's revenue requirement allocated to SCE.
On February 24, 2004, SCE and PG&E agreed to settlement terms with The Williams Cos. and Williams Power Company, providing for
approximately $140 million in refunds and other payments to the settling purchasers and others against some of Williams' power
charges in 2000-2001. A settlement agreement
Page 37
based on the February 24, 2004 terms was executed by both the original settling parties and by SDG&E on April 26, 2004. This
settlement agreement proposed that approximately $34 million of the total refunds and other payments be allocated to SCE. Also on
April 26, 2004, SCE, PG&E, SDG&E and several California state governmental entities agreed to settlement terms with West Coast Power,
LLC and its owners, Dynegy Inc. and NRG Energy, Inc. The April 26, 2004 settlement terms provide for refunds and other payments
totaling $285 million, with a proposed allocation to SCE of approximately $40 million. The allocation of refunds to market
participants under these settlements has not been finally determined and both settlements remain subject to the approval of the FERC
and the CPUC.
Other Regulatory Matters
Catastrophic Event Memorandum Account
As discussed in the "Catastrophic Event Memorandum Account" disclosure in the year-ended 2003 MD&A, the catastrophic event memorandum
account (CEMA) is a CPUC-authorized mechanism that allows SCE to immediately start 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. SCE currently has these memorandum accounts for the bark beetle emergency and the fires that occurred in SCE
territory in October 2003.
Bark Beetle CEMA
The balance in this memorandum account was approximately $36 million as of March 31, 2004. SCE expects to submit an advice filing
with the CPUC in the second quarter of 2004 to recover these costs. SCE estimates that it will spend up to $135 million on this
project in 2004.
Fire-Related CEMA
The balance in this memorandum account was approximately $10.5 million as of March 31, 2004. SCE expects to request recovery of
these costs in mid-2004.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions authorizing utilities to form
holding companies and initiated an investigation into, among other things: (1) whether the holding companies violated CPUC
requirements to give first priority to the capital needs of their respective utility subsidiaries; (2) any additional suspected
violations of laws or CPUC rules and decisions; and (3) whether additional rules, conditions, or other changes to the holding company
decisions are necessary.
On January 9, 2002, the CPUC issued an interim decision interpreting the CPUC requirement that the holding companies give first
priority to the capital needs of their respective utility subsidiaries. The decision stated that, at least under certain
circumstances, holding companies are required to infuse all types of capital into their respective utility subsidiaries when
necessary to fulfill the utility's obligation to serve its customers. The decision did not determine whether any of the utility
holding companies had violated this requirement, 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 requirement 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 in California state court requesting a review of the CPUC's decisions with
regard to first priority requirements, and Edison International filed a petition for a review of the CPUC decision asserting
jurisdiction over holding companies. PG&E and SDG&E and their respective holding
Page 38
companies filed similar challenges, and all cases have been transferred to the First District Court of Appeal in San Francisco. On
November 26, 2003, the Court of Appeal issued an order indicating it would hear the cases but did not decide the merits of the
petitions. Oral argument was held before the Court of Appeal on March 5, 2004, and the matter was taken under submission at that
time. The Court of Appeal is expected to issue its ruling within 90 days of the March 5, 2004 oral argument.
Investigation Regarding Performance Incentives Rewards
SCE is eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to
CPUC-approved standards of reliability, customer satisfaction, and employee safety. SCE received two letters over the last year from
one or more anonymous employees alleging that personnel in the service planning group of SCE's transmission and distribution business
unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey
organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or
penalties to SCE under the PBR provisions for customer satisfaction. SCE is conducting an internal investigation and has determined
that some wrongdoing by a number of the service planning employees has occurred. SCE has informed the CPUC of its findings to date,
and will continue to inform the CPUC of developments as the investigation progresses. SCE has committed to the CPUC to refund or
forego any customer satisfaction awards that were not appropriately earned. The CPUC could institute its own proceedings to
determine whether any portion of past and potential rewards for customer satisfaction should be refunded or disallowed. It also is
possible that penalties could be imposed. SCE recorded aggregate customer satisfaction rewards of $28 million for the years 1998,
1999 and 2000. Potential customer satisfaction rewards aggregating $10 million for 2001 and 2002 are pending before the CPUC and
have not been recognized in income by SCE. SCE also had anticipated that it could be eligible for customer satisfaction rewards of
about $10 million for 2003. SCE cannot predict with certainty the outcome of this matter. SCE has taken prompt remedial action by
severing the employment of several supervisory personnel, updating system processes and related documentation for survey reporting,
and implementing additional supervisory controls over data collection and processing.
SCE: OTHER DEVELOPMENTS
Navajo Nation Litigation
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 Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power
District, and SCE arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,
violations of the federal Racketeer Influenced and Corrupt Organizations 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. SCE joined Peabody's
motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District
Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District's motion for its
separate dismissal from the lawsuit.
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 in the Court of Federal Claims against the United States Department of Interior. 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 SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that
Page 39
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 and Peabody filed motions to dismiss or, in the alternative, for summary
judgment in the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003 motions
to dismiss or, in the alternative, for summary judgment.
The Federal Circuit Court of Appeals, acting on a suggestion on remand filed by the Navajo Nation, held in a October 24, 2003
decision that the Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations 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 Government and the Navajo Nation both filed petitions for rehearing of
the October 24, 2003 Court of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the Court of
Appeals issued an order remanding the case against the Government to the Federal Court of Claims.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of the Supreme Court's
decision in the Navajo Nation's suit against the Government on this complaint, or the impact of the complaint on the operation of
Mohave beyond 2005.
San Onofre Steam Generators
As discussed in the "San Onofre Steam Generators" disclosure in the year-ended 2003 MD&A, on February 27, 2004, SCE filed an
application with the CPUC in which it asked the CPUC to issue a decision by July 2005 finding that it is reasonable for SCE to
replace the San Onofre Unit 2 and 3 steam generators and establishing appropriate ratemaking for the replacement costs.
On April 7, 2004, several parties, including co-owners SDG&E and the City of Anaheim, protested SCE's application to the CPUC. SDG&E
and the City of Anaheim have asked the CPUC to postpone consideration of SCE's application until the co-owners decide whether to
participate in steam generator replacement. On April 21, 2004, SCE filed a reply and a motion requesting the CPUC to order SDG&E to
show cause why it should not participate in steam generator replacement. SCE currently does not expect that it would proceed with
replacement of the San Onofre Units 2 and 3 steam generators without CPUC approval of reasonable cost recovery.
Under the San Onofre operating agreement among the co-owners, a co-owner may elect to reduce its ownership share in lieu of paying
its share of the cost of repairing an "operating impairment," as such term is defined in the San Onofre operating agreement. On
April 14, 2004, SDG&E filed a complaint in San Diego County Superior Court requesting a determination that an operating impairment
exists at San Onofre Units 2 and 3. SCE has not yet responded to the compliant. However, SCE does not agree that an operating
impairment exists. On April 14, 2004, SDG&E also submitted to the other co-owners, including SCE, a demand for arbitration of issues
relating to steam generator replacement. No arbitrator has yet been selected.
Page 40
MISSION ENERGY HOLDING COMPANY
and EDISON MISSION ENERGY
MEHC AND EME: LIQUIDITY
Introduction
MEHC's and EME's liquidity discussion is organized in the following sections:
o MEHC's Liquidity
o EME's Liquidity
o Key Financing Developments
o Termination of the Collins Station Lease
o 2004 Capital Expenditures
o EME's Credit Ratings
o EME's Liquidity as a Holding Company
o Dividend Restrictions in Major Financings
o MEHC's Interest Coverage Ratio
MEHC's Liquidity
MEHC's ability to honor its obligations under the senior secured notes and the term loan, and to pay overhead is entirely 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. See "--EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Payments." Dividends from
EME are limited based on its earnings and cash flow, business and tax considerations, and restrictions imposed by applicable law.
At March 31, 2004, MEHC had cash and cash equivalents of $86 million (excluding amounts held by EME and its subsidiaries). On
April 5, 2004, the lenders under MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase
$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 to pay its obligations with respect to the exercise by its term loan lenders of the Term Loan Put-Option, MEHC will
require additional cash from dividends from EME. The timing and amount of dividends from EME and its subsidiaries may be affected by
many factors beyond MEHC's control.
Dividend Plan to MEHC
EME expects to make a dividend of approximately $75 million to MEHC during the next three months in order to provide funds for MEHC
to pay its obligations with respect to the exercise by its term loan lenders of the Term Loan Put-Option.
EME amended its certificate of incorporation and bylaws to eliminate the so-called "ring fencing" provisions that were implemented in
early 2001 during the California energy crisis. The ring fencing provisions were implemented to protect EME's credit rating from the
negative events then affecting Edison International and SCE. Management believes that the provisions, which included dividend
restrictions and a requirement to maintain an independent director, are no longer necessary.
EME's Liquidity
At March 31, 2004, EME and its subsidiaries had cash and cash equivalents of $555 million and EME had available a total of
$145 million of borrowing capacity under a $145 million corporate credit facility.
Page 41
EME's consolidated debt at March 31, 2004 was $6.1 billion, including $693 million of debt maturing on December 15, 2004 which was
owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's subsidiaries had $6.7 billion of long-term
lease obligations that are due over periods ranging up to 31 years.
Key Financing Developments
EME Financing Developments
On April 27, 2004, EME replaced its $145 million corporate credit facility with a new $98 million secured credit facility. This
credit facility matures on April 26, 2007. Loans made under this credit facility bear interest at LIBOR plus 3.50% per annum. As
security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which
it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also
granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME
will be free to use these proceeds unless and until an event of default occurs under its corporate credit facility.
In addition, EME completed the repayment of the remaining $28 million due under the Coal and Capex facility (guaranteed by EME) in
April 2004. Accordingly, this credit agreement is terminated and EME no longer has a contingent liability related to this credit
agreement.
Midwest Generation Financing Developments
On April 27, 2004, Midwest Generation completed a private offering of $1 billion aggregate principal amount of its 8.75% second
priority senior secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase the notes on May 1, 2014
and on each one-year anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrently with
the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority senior secured institutional term loan
facility. The term loans mature on April 27, 2011 and bear interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to
repay $1,750,000 of the term loans on each quarterly payment date. Midwest Generation also entered into a new three-year $200 million
working capital facility that replaced a prior facility. The new working capital facility also provides for the issuance of letters
of credit. Midwest Generation used the proceeds of the notes issuance and the term loans to refinance $693 million of indebtedness
(plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which was guaranteed by Midwest
Generation and was due in December of this year, and to make termination payments under the Collins Station lease in the amount of
approximately $960 million, including accrued interest and fees.
Midwest Generation is permitted to use the new working capital facility and cash on hand to provide credit support for forward
contracts with third party counterparties entered into by Edison Mission Marketing & Trading for capacity and energy generated from
the Illinois plants. Utilization of this credit facility in support of such forward contracts is expected to provide additional
liquidity support for implementation of EME's contracting strategy for the Illinois plants.
The term loan and working capital facility share a first priority lien and the senior secured notes have a second priority lien in a
collateral package which consists of, among other things, substantially all of the coal-fired generating plants owned by Midwest
Generation and the assets relating to those plants, as well as the equity interests of Midwest Generation and its parent company and
the intercompany notes entered into by EME and Midwest Generation in connection with the Powerton-Joliet sale-leaseback transaction.
Page 42
Termination of the Collins Station Lease
On April 27, 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity
investor. Midwest Generation made a lease termination payment of approximately $960 million, including accrued interest and fees.
This amount repaid the $774 million of lease debt outstanding, accrued interest and fees, and the amount owing to the lease equity
investor upon an early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction
and, subject to its power-purchase agreement with Exelon Generation, plans to abandon the Collins Station or sell it to a third
party. EME expects to record a pre-tax loss of approximately $1 billion (approximately $620 million after tax) during the second
quarter ended June 30, 2004, due to termination of the lease and the planned abandonment or sale of the asset. Prior to termination
of the lease, EME reached an agreement with the lease equity investors in the Powerton-Joliet leases to waive the net worth covenant
included in the EME lease equity guarantee provided to them and, accordingly, the reduction in shareholder equity resulting from the
loss on termination of the Collins Station lease did not result in a default under this guarantee.
If termination of the Collins Station lease is followed by abandonment or sale to a third party as currently planned, EME anticipates
that the termination payment would result in a substantial income tax deduction, thereby providing additional tax-allocation payments
through the income tax-allocation agreement when such loss can be used by Edison International in its consolidated and combined
income tax returns.
2004 Capital Expenditures
The estimated capital and construction expenditures of EME's subsidiaries for the final three quarters of 2004 are $72 million. These
expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations.
EME's Credit Ratings
Overview
Credit ratings for EME and its subsidiaries, Midwest Generation, LLC and Edison Mission Marketing & Trading, are as follows:
Moody's Rating S&P Rating
- ----------------------------------------------------------------- -------------------- ----------------
EME B2 B
Midwest Generation, LLC:
First priority senior secured rating Ba3 B+
Second priority senior secured rating B1 B-
Edison Mission Marketing & Trading Not Rated B
- ----------------------------------------------------------------- -------------------- ----------------
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.
On April 22, 2004, Moody's assigned ratings of "Ba3" and "B1" to Midwest Generation's new first priority senior secured credit
facility and second priority senior secured notes, respectively. On April 21, 2004, Standard & Poor's assigned ratings of "B+" and
"B-" to Midwest Generation's new first priority senior secured credit facility and second priority senior secured notes, respectively.
Page 43
EME does not have any "rating triggers" contained in subsidiary financings that would result in EME being required to make equity
contributions or provide additional financial support to its subsidiaries.
The credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide support to Edison Mission Marketing
& Trading 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 ($119 million as of April 30, 2004). As a result of the new
working capital facility entered into by Midwest Generation described above, Midwest Generation expects to provide credit support for
forward contracts entered into by Edison Mission Marketing & Trading related to the Illinois plants. A subsidiary of EME has also
supported a portion of First Hydro's United Kingdom hedging activities through a cash collateralized credit facility, under which
letters of credit totaling(pound)16 million have been issued as of April 30, 2004.
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 potential working capital required to support price risk
management and trading activity to be between $100 million and $200 million from time to time.
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. 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 a consent
from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions. EME
Homer City continues to be in compliance with the terms of the consent; however, the consent is 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 spot market at
any time. See "MEHC and EME: Market Risk Exposures--Commodity Price Risk--Homer City Facilities."
EME's Liquidity as a Holding Company
Overview
At March 31, 2004, EME had corporate cash and cash equivalents of $232 million to meet liquidity needs. EME had no borrowings
outstanding on the $145 million line of credit in existence on March 31, 2004. In April 2004, EME terminated the $145 million line of
credit and entered into a new three-year
Page 44
$98 million secured line of credit. 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. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its
control. See "--Dividend Restrictions in Major Financings." 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 Liquidity as a
Holding Company--Intercompany Tax-Allocation Payments."
EME's new secured corporate credit facility provides credit available in the form of cash advances or letters of credit. At April 30,
2004, there were no cash advances outstanding or letters of credit outstanding under the credit facility. In addition to the interest
payments, EME pays a commitment fee of 0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum interest
coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the credit agreement).
As security for its obligations under its new corporate credit facility, EME pledged its ownership interests in the holding companies
through which it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project.
EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be
deposited. EME will be free to use these proceeds unless and until an event of default occurs under its corporate credit facility.
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 debt service costs of recourse
debt.
In millions Three Months Ended March 31, 2004 2003
------------------------------------------------------------------------------ -------------- ---------------
Domestic Projects
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) $ 41 $ 21
Holding companies of other consolidated operating projects -- 1
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects) 21 20
Holding companies for Westside projects 3 9
Holding companies of other unconsolidated operating projects 1 2
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions from Domestic Projects $ 66 $ 53
International Projects (Mission Energy Holdings International)
Distributions from Consolidated Operating Projects:
Loy Yang B $ -- $ 12
Contact Energy 27 16
Valley Power 4 5
Kwinana -- 2
Holding companies of other consolidated operating projects 6 --
------------------------------------------------------------------------------ -------------- ---------------
Distributions from Unconsolidated Operating Projects:
IVPC4 (Italian Wind project) 1 3
Paiton -- 9
Holding companies of other unconsolidated operating projects 6 --
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions from International Projects $ 44 $ 47
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions $ 110 $ 100
------------------------------------------------------------------------------ -------------- ---------------
Page 45
Intercompany Tax-Allocation Payments
MEHC and EME are included in the consolidated federal and combined state income tax returns of Edison International and are 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 MEHC and EME 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 and EME are parties 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 Edison Mission Group on
July 2, 2001, when it became part of the Edison International consolidated filing group. EME and MEHC have historically received
tax-allocation payments related to domestic net operating losses incurred by EME and MEHC. The right of MEHC and EME to receive and
the amount and timing of tax-allocation payments are dependent on the inclusion of MEHC and EME, respectively, 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 MEHC, EME, its subsidiaries, and
other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive
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 or the tax losses of EME in the consolidated income tax returns for
Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC and EME may be obligated during
periods they generate taxable income to make payments under the tax-allocation agreements. MEHC paid $73 thousand and $286 thousand
in tax-allocation payments to Edison International during the first quarters of 2004 and 2003, respectively. EME paid $9 million in
tax-allocation payments to Edison International and received $13 million in tax-allocation payments from Edison International during
the first quarters of 2004 and 2003, respectively.
Dividend Restrictions in Major Financings
General
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.
Page 46
Key Ratios of EME's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EME's principal subsidiaries, other than Midwest Generation, for the twelve months ended March 31,
2004:
Subsidiary Financial Ratio Covenant Actual
---------------------------------- -------------------------------- ------------------------- -------------------
EME Homer City Generation L.P. Senior Rent Service Greater than 1.7 to 1 3.43 to 1
(Homer City facilities) Coverage Ratio
Edison Mission Energy Funding Debt Service Coverage Ratio Greater than or 2.58 to 1
Corp. equal to 1.25 to 1
(Big 4 Projects)
Mission Energy Holdings Interest Coverage Ratio Greater than or 2.50 to 1(1)
International equal to 1.3 to 1
First Hydro Holdings Interest Coverage Ratio Greater than 1.2 to 1 1.6 to 1(2)
---------------------------------- -------------------------------- ------------------------- -------------------
--------------
(1) For more information about the interest coverage ratio, see "--Dividend Restrictions in Major Financings--Mission Energy
Holdings International Interest Coverage Ratio" below.
(2) Ratio is determined on June 30 and December 31 of each year, therefore actual shown is for the twelve-month period ended
December 31, 2003.
For a more detailed description of the 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, refer to "MEHC and EME:
Liquidity--Dividend Restrictions in Major Financings" in the year-ended 2003 MD&A.
Midwest Generation Financing Restrictions on Distributions
Midwest Generation is no longer bound by the covenants, including restrictions on the ability to make distributions, in the Edison
Mission Midwest Holdings credit agreement, which was repaid on April 27, 2004. However, Midwest Generation is now bound by the
covenants in its new credit facility and indenture. These covenants include restrictions on the ability to, among other things, incur
debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make
distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines
of business or engage in transactions for any speculative purpose. In addition, the credit facility contains financial covenants
binding on Midwest Generation.
Covenants in Credit Facility
In order for Midwest Generation to make a distribution, it must be in compliance with covenants specified under its new credit
facility. Compliance with the covenants in its credit facility includes maintaining the following two financial performance
requirements:
o At the end of each fiscal quarter, Midwest Generation's consolidated interest coverage ratio for the immediately preceding
four consecutive fiscal quarters must be at least 1.25 to 1. The consolidated interest coverage ratio is defined as the ratio
of consolidated net income (plus or minus specified amounts as set forth in the credit agreement), to consolidated interest
expense (as more specifically defined in the credit agreement).
Page 47
o Midwest Generation's secured leverage ratio for the 12-month period ended on the last day of the immediately preceding
fiscal quarter may be no greater than 8.75 to 1. The secured leverage ratio is defined as the ratio of the aggregate principal
amount of Midwest Generation secured debt plus all indebtedness of a subsidiary of Midwest Generation, to the aggregate amount of
consolidated net income (plus or minus specified amounts as set forth in the credit agreement).
In addition, Midwest Generation's distributions are limited in amount. The aggregate amount of distributions made by Midwest
Generation after April 27, 2004 may not exceed the sum of (i) 75% of excess cash flow (as defined in the credit facility) generated
since that date, plus (ii) up to 100% of the amount of equity contributions or subordinated loans made by EME or a subsidiary of EME
to Midwest Generation after April 27, 2004, but in this latter case only to the extent excess cash flow not used for a dividend under
(i) is available for such payments. If Midwest Generation is rated investment grade, the aggregate amount of distributions made by
Midwest Generation since April 27, 2004 may not exceed 100% of excess cash flow generated since becoming investment grade.
Covenants in Indenture
Midwest Generation's new indenture contains restrictions on its ability to make a distribution substantially similar to those in the
credit facility. Under the indenture, however, failure to achieve the conditions required for distributions will not result in a
default, nor does the indenture contain any other financial performance requirements.
Mission Energy Holdings International Interest Coverage Ratio
Under the credit agreement governing its term loan, Mission Energy Holdings International has agreed to a minimum interest coverage
ratio of 1.30 to 1 beginning March 2004 for the trailing twelve-month period.
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The following table sets forth the major components of the interest coverage ratio for the twelve months ended March 31, 2004 and the
year ended December 31, 2003 on a pro forma basis assuming the term loan had been in existence at the beginning of 2003:
March 31, 2004 December 31, 2003
----------------------------------- -----------------------------------
Actual Pro Forma Pro Forma Actual Pro Forma Pro Forma
In millions Adjustment Adjustment
---------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations
Historical distributions from
international projects(1) $ 155 $ -- $ 155 $ 158 $ -- $ 158
Other fees and cash payments
considered distributions under the
term loan 7 -- 7 20 -- 20
Administrative and general expenses (2) -- (2) (2) -- (2)
---------------------------------------------------------------------------------------------------------------------
Total Flow of Funds from Operations $ 160 $ -- $ 160 $ 176 $ -- $ 176
---------------------------------------------------------------------------------------------------------------------
Term Loan Interest Expense $ 20 $ 44 $ 64 $ 4 $ 60 $ 64
---------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 2.50 2.75
---------------------------------------------------------------------------------------------------------------------
--------------
(1) See "--EME's Liquidity as a Holding Company--Historical Distributions Received By EME."
(2) The pro forma adjustment assumes that the $800 million loan was outstanding at the beginning of 2003. Pro forma interest
expense was calculated using the interest rate floor of 7% plus amortization of deferred financing costs.
The above details of Mission Energy Holdings International's interest coverage ratio are provided as an aid to understanding the
components of the computations that are set forth in the term loan credit agreement. The terms Funds Flow from Operations and
Interest Expense are as defined in the term loan and are not the same as would be determined in accordance with generally accepted
accounting principles.
Page 49
Summarized combined financial information (unaudited) of Mission Energy Holdings International, Inc. and its subsidiaries and Edison
Mission Project Co. is set forth below:
In millions Three Months Ended March 31, 2004 2003
--------------------------------------------------------------------------------------------------------------
Revenue $ 423 $ 314
Expenses 374 295
--------------------------------------------------------------------------------------------------------------
Net income (loss) $ 49 $ 19
--------------------------------------------------------------------------------------------------------------
In millions Three Months Ended March 31, 2004 2003
--------------------------------------------------------------------------------------------------------------
Current assets $ 466 $ 628
Noncurrent assets 6,630 6,723
--------------------------------------------------------------------------------------------------------------
Total assets $ 7,096 $ 7,351
--------------------------------------------------------------------------------------------------------------
Current liabilities $ 495 $ 587
Noncurrent liabilities 4,742 4,994
Minority interest 756 746
Equity 1,103 1,024
--------------------------------------------------------------------------------------------------------------
Total liabilities and equity $ 7,096 $ 7,351
--------------------------------------------------------------------------------------------------------------
The majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME.
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 MEHC's 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.
Page 50
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 "MEHC's Interest Coverage Ratio--EME's Interest Coverage Ratio" below. The following table sets forth MEHC's interest
coverage ratio for the twelve months ended March 31, 2004 and the year ended December 31, 2003:
March 31, December 31,
In millions 2004 2003
------------------------------------------------------------------- -------------------------------------------
Funds Flow from Operations:
EME $ 722 $ 699
Operating cash flow from unrestricted subsidiaries (1) (2)
Funds flow from operations of projects sold (23) (1)
MEHC 1 1
------------------------------------------------------------------- ---------------------- --------------------
$ 699 $ 697
Interest Expense:
EME $ 279 $ 286
EME - affiliate debt 1 1
MEHC interest expense 161 160
Interest savings on projects sold (7) --
------------------------------------------------------------------- ---------------------- --------------------
Total interest expense $ 434 $ 447
------------------------------------------------------------------- ---------------------- --------------------
Interest Coverage Ratio 1.61 1.56
------------------------------------------------------------------- ---------------------- --------------------
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 2.0 to 1 for the immediately preceding four fiscal quarters.
Page 51
EME's Interest Coverage Ratio
The following table sets forth the major components of the interest coverage ratio for the twelve months ended March 31, 2004 and the
year ended December 31, 2003:
March 31, December 31,
In millions 2004 2003
--------------------------------------------------------------------- --------------------- --------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants(3) $ 289 $ 242
Homer City 126 153
First Hydro 10 (8)
Other consolidated operating projects 203 165
Price risk management and energy trading (4) 11
Distributions from unconsolidated Big 4 projects 99 98
Distributions from other unconsolidated operating projects 165 178
Interest income 4 4
Interest expense at Mission Energy Holdings International (20) --
Operating expenses (150) (144)
--------------------------------------------------------------------- --------------------- --------------------
Total funds flow from operations $ 722 $ 699
Interest Expense:
From obligations to unrelated third parties $ 166 $ 172
From notes payable to Midwest Generation 113 113
--------------------------------------------------------------------- --------------------- --------------------
Total interest expense $ 279 $ 285
--------------------------------------------------------------------- --------------------- --------------------
Interest Coverage Ratio 2.59 2.45
--------------------------------------------------------------------- --------------------- --------------------
--------------
(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 EME's 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 its 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 "--Dividend
Restrictions in Major Financings--Midwest Generation Financing Restrictions to Make Distributions," for a description of
restrictions applicable to future periods.
MEHC AND EME: MARKET RISK EXPOSURES
Introduction
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 market 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 "MEHC and EME: Liquidity--EME's Credit Ratings" for
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a discussion of market developments and their impact on EME's credit and the credit of its counterparties.
This section discusses these market risk exposures under the following headings:
o Commodity Price Risk
o Credit Risk
o Foreign Exchange Rate Risk
For a complete discussion of these issues, read this quarterly report in conjunction with the year-ended 2003 MD&A.
Commodity Price Risk
General Overview
EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively
monitored by a risk management committee 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 the 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 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.
Page 53
Introduction
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, as has been the case for the Homer City facilities, to
the PJM and/or the New York Independent System Operator (NYISO) markets. As discussed further below, beginning in 2003, EME has been
selling a significant portion of the power generated from its Illinois plants into wholesale power markets.
EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in
the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure
compliance with EME's risk management policies. Policies are in place which define the risk tolerance for EME's merchant
activities. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by the risk management
committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.
Illinois Plants
Energy 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 is obligated to make capacity payments
for the plants under contract and energy payments for the energy produced by these plants and taken by Exelon Generation. The
power-purchase agreements began on December 15, 1999 and expire in December 2004. The capacity payments provide units under contract
with revenue for fixed charges, and the energy payments compensate to those units for all, or a portion of, variable costs of
production.
Approximately 40% and 58% of the energy and capacity sales from the Illinois plants in the first quarters of 2004 and 2003,
respectively, were to Exelon Generation under the power-purchase agreements. As a result of Exelon Generation's election to release
units from contract for 2004, Midwest Generation's reliance on sales into the wholesale market increased in 2004 from 2003. As
discussed in detail below, 3,859 MW of Midwest Generation's generating capacity remains subject to power-purchase agreements with
Exelon Generation in 2004. 2004 is the final contract year under these power-purchase agreements.
In June 2003, Exelon Generation exercised its option, in accordance with the terms of its power-purchase agreement, to contract
687 MW of capacity and the associated energy output (out of a possible total of 1,265 MW subject to 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 capacity at the Crawford Unit 7, Waukegan Unit 6 and Will County Unit 3 has not
been subject to the power-purchase agreement since January 1, 2004. For 2004, Midwest Generation has 2,383 MW of capacity related to
its coal-fired generation units under contract with Exelon Generation.
In October 2003, Exelon Generation exercised 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. 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 energy and capacity from units not subject to a power-purchase agreement with Exelon Generation are sold under terms, including
price and quantity, negotiated by Edison Mission Marketing & Trading with customers through a combination of bilateral agreements,
forward energy sales and spot market
Page 54
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 from those units. EME expects that capacity prices for merchant energy sales will, in the near term, be
substantially less than those Midwest Generation currently receives under its existing agreements with Exelon Generation. 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.
Presently, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants are
expected to be direct "wholesale customers" and broker-arranged "over-the-counter customers" and, after May 1, 2004, bilateral and
spot sales into the expanded PJM. The most liquid over-the-counter markets in the Midwest region have historically been for sales
into the control area of Cinergy, referred to as "Into Cinergy," and, to a lesser extent, for sales into the control areas of
Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. "Into Cinergy," "Into
ComEd" and "Into AEP" are bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic
proximity, "Into ComEd" has been the primary market for Midwest Generation. Following Commonwealth Edison's joining PJM as of May 1,
2004, sales of electricity from the Illinois plants now include bilateral and spot sales into PJM, with spot sales being based on
locational marginal pricing. These sales replace sales previously made as bilateral sales and spot sales "Into ComEd." See "MEHC and
EME: Other Developments--PJM Regulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth
Edison's application to join PJM and "--Commodity Price Risk--Homer City Facilities" below for a discussion of locational marginal
pricing. 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 three months of 2004. Market prices are included for "Into Cinergy" for illustrative purposes.
2004 2004
Into ComEd* Into Cinergy*
-------------------------------------------------------------------------------
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- ---------------------------------------------------------------------------------------------------------------
January $ 43.30 $ 15.18 $ 27.88 $ 41.97 $ 19.17 $ 29.46
February 43.05 18.85 29.98 44.42 24.85 33.85
March 40.38 21.15 30.66 41.75 23.88 32.72
- ---------------------------------------------------------------------------------------------------------------
Quarterly Average $ 42.25 $ 18.39 $ 29.51 $ 42.71 $ 22.63 $ 32.01
- ---------------------------------------------------------------------------------------------------------------
--------------
(1) On-peak refers to the hours of the day between 6:00 a.m. and 10:00 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.
Midwest Generation intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. 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
Page 55
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 Edison Mission Marketing & Trading'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. See "--Credit Risk," 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 at the end of 2002 pending improvement in market conditions.
Under PJM's proposed revisions to the PJM Tariff, the integration of Commonwealth Edison into PJM could result in market power
mitigation measures being imposed on future power sales by Midwest Generation in the Northern Illinois Control Area energy and
capacity markets. In addition, power produced by Midwest Generation not under contract with Exelon Generation has been sold in the
past using transmission obtained from Commonwealth Edison under its open-access tariff filed with the FERC and the application of the
PJM Tariff to Commonwealth Edison's transmission system could also affect the rates, terms and conditions of transmission service
received by Midwest Generation. EME and Midwest Generation contested the appropriateness of Commonwealth Edison joining PJM on an
"islanded" basis, but such integration was approved by the FERC and was implemented on May 1, 2004. On April 30, 2004, Commonwealth
Edison submitted a filing to the FERC purporting to satisfy those conditions. EME and Midwest Generation continue to oppose the
imposition of market power mitigation measures proposed by PJM for the Northern Illinois Control Area energy and capacity markets.
EME is unable to predict the outcome of these efforts, the effect of integration of Commonwealth Edison into PJM on an "islanded"
basis, the timing or effect of integration of American Electric Power into PJM, or any final integration configuration for PJM on the
markets into which Midwest Generation sells its power.
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 working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will
be resolved.
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 markets. 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.
Page 56
The following table depicts the average market prices per megawatt-hour in PJM during the first quarters of 2004 and 2003:
24-Hour PJM
Historical Energy Prices*
-----------------------------
2004 2003
- -----------------------------------------------------------------------
January $ 51.12 $ 36.56
February 47.19 46.13
March 39.54 46.85
- -----------------------------------------------------------------------
Quarterly Average $ 45.95 $ 43.18
- -----------------------------------------------------------------------
- --------------
* Energy prices were calculated at the Homer City busbar (delivery point) using historical hourly real-time 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 three
months of 2004 were higher than the average historical market prices during the first three months of 2003. 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, plant outages in the region, 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 set forth in the table below.
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 energy to be
delivered 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 a delivery point known as the 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,
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), which establishes hourly prices at specific
locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, 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 on an average of 2%.
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 fixed transmission rights in PJM, and may continue to do so in the future. A fixed transmission right is a
financial instrument that entitles the holder thereof to receive actual spot prices at one point of delivery and pay prices at
another point of delivery that are pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's
price risk management activities include using fixed
Page 57
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
March 31, 2004:
24-Hour PJM West
2004 Forward Energy Prices*
- --------------------------------------------------------------------------------
April $ 39.31
May 38.17
June 41.96
July 52.46
August 52.09
September 38.88
October 37.24
November 37.91
December 38.80
2005 Calendar "strip"(1) $ 40.79
- --------------------------------------------------------------------------------
--------------
(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 depends on revenue generated by the Homer City facilities, which depend in part on the market conditions
for the sale of capacity and energy. These market conditions are beyond EME's control.
United Kingdom
The First Hydro plant sells electrical energy and ancillary services through bilateral contracts of varying terms in the England and
Wales wholesale electricity market.
The electricity trading arrangements introduced in March 2001 provide, among other things, for the establishment of a range of
voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 1 hour prior to the delivery or
receipt of power. In the final hour after the notification of all contracts, the system operator can accept bids and offers in the
Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is a mandatory settlement
process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance, and a Balancing
and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also purchase system reserve and
response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary
services"). Ancillary services contracts typically run for up to a year and can consist of both fixed amounts and variable amounts
represented by prices for services that are only paid for when actually called upon by the grid operator. A key feature of the
trading arrangements is the requirement for firm physical delivery, which means that a generator must deliver, and a consumer must
take delivery of, its net contracted positions or pay for any energy imbalance at the imbalance prices calculated by the system
operator based on the prices of bids and offers accepted in the Balancing Mechanism. This provides an incentive for parties to
contract in advance and for the development of forwards and futures markets.
Page 58
Under these arrangements, there has been an increased emphasis on credit quality, including the need for parent company guarantees or
letters of credit for companies below investment grade.
The wholesale price of electricity has decreased significantly in recent years. The reduction has been driven principally by surplus
generating capacity and increased competition. During 2003, prices were more volatile. There was further downward pressure on
wholesale prices in the first part of the year followed by some recovery during the summer in prices and in the peak/off peak
differentials for the 2003-2004 winter period. That recovery tailed off towards the end of the year with a considerable narrowing in
the peak/off peak differentials which has continued during the first quarter of 2004. Compliance with First Hydro's bond financing
documents is subject to market conditions for electric energy and ancillary services, which are beyond First Hydro'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 on various dates through June 30, 2010, although the majority of the forward contracts are short term (less
than two years).
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 Electricity Governance Regulations and Rules were finalized in 2003.
The Regulations came into force on January 16, 2004, and the Rules came into force during February and March of 2004.
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 took the following steps:
o the Electricity Commission has been given responsibility for managing dry year reserve, which it is undertaking through the
procurement of reserve capacity; and
o the Electricity Commission has been given additional reserve powers ranging from information disclosure to imposing hedge
obligations on major users and generators.
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 include this plant in its
portfolio of reserve energy. The Whirinaki plant, which is expected to be operational in May 2004, will be located on a site leased
to the government from Contact Energy and will also be operated under contract by Contact Energy.
Credit Risk
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and
financial institutions, collectively referred to as counterparties. In the
Page 59
event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with
reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated
damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered
prior to the time such counterparty defaulted.
To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would
be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and
mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used whenever possible
and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or
lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME
manages the credit risk on the 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. A risk management committee regularly
reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly
successful in mitigating credit risk or that collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) 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. At March 31, 2004, the credit ratings of EME's counterparties were as follows:
In millions March 31, 2004
- ----------------------------------------------------------------------
S&P Credit Rating
A or higher $ 20
A- 13
BBB+ 110
BBB 18
BBB- 3
Below investment grade 16
- ----------------------------------------------------------------------
Total $ 180
- ----------------------------------------------------------------------
Exelon Generation accounted for 14% and 19% of EME's consolidated operating revenue for the first quarters of 2004 and 2003,
respectively. The percentage is less in the first quarter of 2004 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 under the
power-purchase agreements could adversely affect EME's results of operations and financial condition.
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 affect on the operations of such power plant.
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Foreign Exchange Rate Risk
Fluctuations in foreign currency exchange rates can affect, on a United States 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 United States 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 United Kingdom 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 three months of 2004, foreign currencies in the United Kingdom, Australia and New Zealand increased in value
compared to the United States dollar by 3%, 1% and 1%, respectively (determined by the change in the exchange rates from December 31,
2003 to March 31, 2004). The increase in value of these currencies was the primary reason for the foreign currency translation gain
of $22 million during the first three months of 2004.
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 United States dollars with
varying maturities through February 2006. At March 31, 2004, the outstanding notional amount of the contracts totaled $18 million and
the fair value of the contracts totaled $(2,000).
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 United States and Australian dollar loans into floating-rate New
Zealand dollar loans with varying maturities through April 2018.
EME will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the
future.
MEHC AND EME: OTHER DEVELOPMENTS
PJM Regulatory Matters
Commonwealth Edison's application to join PJM was finally approved by the Federal Energy Regulatory Commission, or the FERC, on
April 27, 2004, with an effective date for integration set for May 1, 2004.
On March 19, 2004, the FERC, in a separate but related matter, issued another order having the effect of postponing to December 1,
2004 the effective date for elimination of regional through and out rates in the region encompassed by PJM (as expanded by the
addition of Commonwealth Edison and as to be further expanded by the addition of AEP) and the MISO. The effect of this order is that
so-called rate pancaking was not eliminated prior to Commonwealth Edison's integration into PJM, nor will it be eliminated prior
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to AEP's scheduled date for integration into PJM. Rate pancaking occurs when energy must move through multiple, separately priced
transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the line
charges separately for the use of its system. Accordingly, Midwest Generation will continue to have to pay transmission charges for
power sold for delivery outside of Commonwealth Edison's former control area, now known under PJM as PJM's Northern Illinois Control
Area, or NICA. The FERC included in its order a strong statement that the existing through and out rates must be eliminated no later
than December 1, 2004.
On March 24, 2004, the FERC, in another order, rejected a proposal by PJM for certain market mitigation procedures to be applied to
the new NICA. On April 23, 2004, PJM filed a request for rehearing of one aspect of the March 24 order and an "Explanation" relating
to another aspect of such order, and supplemented its filing on April 26, 2004. EME and Midwest Generation have filed a motion for a
procedural schedule that will allow 30 days for EME and Midwest Generation to prepare and submit analyses responding to PJM's
findings. It is not possible at this time to predict the outcome of this matter or the impact of the market monitor's proposed
mitigation measures should they or some form of them be adopted.
Apart from the uncertainties regarding the market mitigation issues discussed previously, the direct impact on Midwest Generation of
the above-described matters will for the most part be limited to the delay in the elimination of regional through and out rates. This
is not expected to have a material effect on Midwest Generation's financial results with respect to the period between the May 1,
2004 integration of Commonwealth Edison and the mandated elimination of the through and out rates on December 1, 2004. The impact on
power prices in the new NICA and in the surrounding bilateral markets by reason of the islanded integration of Commonwealth Edison is
difficult to predict, but it is not currently anticipated that it will have a material effect upon Midwest Generation's financial
results in the period prior to the integration of AEP into PJM, currently scheduled for October 1, 2004.
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EDISON CAPITAL
Edison Capital: LIQUIDITY
Since 2001, as a result of the California energy crisis, Edison Capital reduced debt and accumulated cash, which resulted in a
significant de-leveraging of Edison Capital. In light of Edison Capital's improved liquidity, Edison Capital made a $225 million
dividend payment to Edison International in 2003 while maintaining a cash and cash equivalent balance of $325 million at March 31,
2004. The improvement in liquidity is primarily from Edison International's utilization of tax benefits that had been delayed in
previous years because of the California energy crisis. 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. To the extent that certain
funding conditions are satisfied, Edison Capital has unfunded current and long-term commitments of $72 million for energy and
infrastructure investments. Edison Capital is evaluating its capital structure, the potential for additional borrowings and
potentially making dividend payments to Edison International.
At March 31, 2004, Edison Capital's long-term debt had credit ratings of Ba1 and BB+ from Moody's and Standard & Poor's, respectively.
Edison Capital's Intercompany Tax-Allocation Payments
Edison Capital 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 Edison International and other subsidiaries of Edison International. See "MEHC and
EME: Liquidity--EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Payments" for additional information regarding these
arrangements. Edison Capital received $23 million in tax-allocation payments from Edison International during the first quarter of
2004. The amount received is net of payments made to Edison International. In the future, Edison Capital may be obligated to make
payments under the tax-allocation agreements. (See "Other Developments--Federal Income Taxes" for further discussion of tax-related
issues regarding Edison Capital's leveraged leases).
Edison Capital: MARKET RISK EXPOSURES
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. See "Edison Capital: Market Risk Exposures" in the year-ended
2003 MD&A for a complete discussion of Edison Capital's market risk exposures.
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EDISON INTERNATIONAL (PARENT)
Edison International (parent): 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 agreements with its
subsidiaries, and access to capital markets or external financings. Edison International is focused on reducing its parent company
debt in 2004, which may further impact Edison International's liquidity.
Edison International (parent)'s 2004 estimated cash outflows primarily consist of:
o $618 million of 6-7/8% notes due September 15, 2004. During January through April 2004, Edison International repurchased
approximately $47 million of these notes, leaving a remaining balance of $571 million of notes due in September 2004;
o Interest payments on its long-term notes payable related to the quarterly income debt securities of approximately $67
million (approximately $17 million a quarter);
o General operating expenses; and
o Dividends to common shareholders. On March 18, 2004, the Board of Directors of Edison International declared a 20(cent)per
share common stock dividend. The $65 million dividend payment was made on April 30, 2004.
Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand and dividends from
its subsidiaries. At March 31, 2004, Edison International (parent) had approximately $1.2 billion of cash and cash equivalents on
hand. The ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described
below.
The CPUC regulates SCE's capital structure by requiring that SCE maintain prescribed percentages 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. Other factors at SCE that affect the amount and timing of
dividend payments by SCE to Edison International include, among other things, SCE's cash requirements, SCE's access to capital
markets, and actions by the CPUC. On March 30, 2004, SCE paid a cash dividend of $300 million to Edison International.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At March 31, 2004, its interest coverage
ratio was 1.61 to 1. See "MEHC and EME: Liquidity--MEHC's Interest Coverage Ratio." MEHC did not declare or pay a dividend in the
first quarter of 2004. 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 the "MEHC and EME: Liquidity" section above. EME did not declare or
pay a dividend to MEHC in the first quarter of 2004.
Edison International's investment in MEHC, through a wholly owned subsidiary, as of March 31, 2004, was $880 million. MEHC's
investment in EME, as of March 31, 2004, was approximately $2.0 billion. MEHC's and EME's independent accountants' audit opinions
for the year ended December 31, 2003, contain an explanatory paragraph that indicates the December 31, 2003 consolidated financial
statements have been prepared on the basis that EME will continue as a going concern and that the uncertainty about
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Edison Mission Midwest Holdings' ability to repay or refinance Edison Mission Midwest Holdings' $693 million of debt due in December
2004 raises substantial doubt about EME's ability to continue as a going concern. In April 2004, all of the outstanding debt of
Edison Mission Midwest holdings was repaid in full through new financings obtained by Midwest Generation. Although the 2003
financial statements have not been re-issued and, therefore, the audit opinion is still in effect with respect these financial
statements, the condition that was subject to the uncertainty has been resolved. See "MEHC and EME: Liquidity--Key Financing
Developments--Midwest Generation Financing Developments" for further details.
Edison Capital's ability to make dividend payments is currently restricted by debt covenants, which require Edison Capital, through a
wholly owned subsidiary, to maintain a specified minimum net worth of $300 million. Edison Capital did not declare or pay a dividend
to Edison International in the first quarter of 2004.
EDISON INTERNATIONAL (PARENT): MARKET RISK EXPOSURES
The parent company is exposed to changes in interest rates primarily as a result of its borrowing and investing activities, the
proceeds of which are used for general corporate purposes, including investments in nonutility businesses. The nature and amount of
the parent company's long-term and short-term debt can be expected to vary as a result of future business requirements, market
conditions and other factors.
EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS
Holding Company Proceeding
Edison International is a party to a CPUC holding company proceeding. See "SCE: Regulatory Matters--Other Regulatory Matters--Holding
Company Proceeding" for a discussion of this matter.
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EDISON INTERNATIONAL (CONSOLIDATED)
The following sections of the MD&A are on a consolidated basis. The section begins with a discussion of Edison International's
consolidated results of operations and historical cash flow analysis. This is followed by discussions of discontinued operations,
acquisitions and dispositions, critical accounting policies, new accounting principles, commitments and guarantees, off-balance sheet
transactions and other developments.
RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS
The following subsections of "Results of Operations and Historical Cash Flow Analysis" provide a discussion on the changes in various
line items presented on the Consolidated Statements of Income, as well as a discussion of the changes on the Consolidated Statements
of Cash Flows.
Results of Operations
First Quarter 2004 vs. First Quarter 2003
Edison International recorded consolidated earnings of $97 million or 30(cent)per share in the first quarter of 2004, compared to $57
million or 17(cent)per share in the first quarter of 2003. The increased earnings primarily reflect higher operating results at EME and
a gain on the sale of EME's interest in Four Star Oil & Gas. Recorded earnings in the first quarter of 2003 include a charge at EME
from the implementation of a new accounting principle and a charge in earnings from discontinued operations at SCE.
The table below presents Edison International's earnings and earnings per share for the three-month periods ended March 31, 2004 and
2003, and the relative contributions by its subsidiaries.
In millions, except per share amounts Earnings (Loss) Earnings per Share
- ---------------------------------------------------------------------------------------------------------------------------------------
Three-Month Period Ended March 31, 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 100 $ 99 $ 0.31 $ 0.30
EME 31 (8) 0.10 (0.02)
Edison Capital 11 15 0.03 0.04
MEHC (stand alone) (25) (24) (0.08) (0.07)
Edison International (parent) and other (19) (19) (0.06) (0.06)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 98 63 0.30 0.19
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations -- 3 -- 0.01
- ---------------------------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (1) (9) -- (0.03)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 97 $ 57 $ 0.30 $ 0.17
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
Edison International's first quarter 2004 earnings from continuing operations were $98 million, or 30(cent) per share, compared with
earnings of $63 million, or 19(cent)per share, in 2003.
SCE's earnings from continuing operations were essentially unchanged with $100 million in the first quarter of 2004, compared to $99
million in the same period last year.
EME's first quarter 2004 earnings from continuing operations were $31 million compared to a loss of $8 million in the same period
last year. The improved results are primarily due to stronger operating performance at EME's Illinois plants, driven by higher
merchant generation and wholesale energy prices,
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and higher ancillary services and mark-to-market impacts on forward contracts at EME's First Hydro project in the UK. EME's Contact
Energy projects in New Zealand, EME's Loy Yang B project in Australia and EME's Paiton project in Indonesia also contributed to the
earnings increase. First quarter results for 2004 include a $29 million after-tax gain from the sale of EME's interest in Four Star
Oil & Gas. These favorable items were partially offset by outages in 2004 at EME's Homer City project and 2003 earnings at Four Star
Oil & Gas, which did not occur in 2004 due to the sale. EME's earnings are seasonal with higher earnings expected during the summer
months.
Edison Capital's earnings from continuing operations for the first quarter 2004 were $11 million, down $4 million from the same
period last year. The decrease is primarily due to a maturing investment portfolio which produces lower income.
The 2004 losses at MEHC (stand alone) of $25 million, and Edison International (parent) and other of $19 million were essentially
unchanged from the same period last year.
Operating Revenue
SCE's retail sales represented approximately 87% and 94% of electric utility revenue in the first quarter of 2004 and 2003,
respectively. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is
significantly higher than other quarters.
Electric utility revenue decreased in 2004 mainly due to the implementation of a CPUC-approved customer rate reduction plan effective
August 1, 2003 and the recognition of revenue in 2003 from a CPUC-authorized surcharge collected in 2002 and used to recover costs
incurred in 2003. There was no surcharge revenue recognized in 2004. The decrease in electric utility revenue was also due to a
decrease in sales volume resulting from the CDWR providing a greater amount of energy to SCE's customers in 2004, as compared to 2003
(see discussion below). The decrease in electric utility revenue was partially offset by an increase in resale sales revenue due to
a greater amount of excess energy in 2004, as compared to 2003 and an allocation adjustment for the CDWR energy purchases recorded in
2003. As a result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times, which then is
resold in the energy markets.
Amounts SCE bills and collects from its customers for electric power purchased and sold by the 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 the CDWR and are not recognized as revenue by SCE. These amounts were $630 million and $424 million for the three-month
period ended March 31, 2004 and 2003, respectively.
Nonutility power generation revenue increased in 2004. The 2004 increase was primarily due to increased electric revenue from EME's
Contact Energy mostly due to increased retail revenue and an increase in the value of the New Zealand dollar compared to the United
States dollar. In addition, nonutility power generation revenue increased due to higher electric revenue from EME's First Hydro
plant primarily due to higher ancillary service revenue and an increase in the average exchange rate of the British pound compared to
the United States dollar, and higher energy revenue from EME's Illinois plants. Partially offsetting these increases was lower
electric revenue from EME's Homer City facilities due to lower generation resulting from outages.
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 from EME's Homer City facilities and Illinois plants. By
contrast, EME's First Hydro plants have higher revenue during their winter months.
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Operating Expenses
Fuel expense increased in 2004 primarily due to increased fuel costs from EME's Contact Energy projects resulting from an increase in
the value of the New Zealand dollar compared to the United States dollar and increased pumping power costs from EME's First Hydro
plant. The increase was partially offset by lower coal expense at SCE resulting from a first quarter 2004 scheduled major overhaul
at one of its coal facilities.
Purchased-power expense increased in 2004 due to an increase in ISO related costs, higher expenses resulting from an increase in the
number of gas bilateral contracts in 2004, as compared to 2003, and a decrease in purchased-power expense in 2003 resulting from
realized and unrealized gains related to gas hedging activities. These gas hedging instruments expired in 2003.
Provisions for regulatory adjustment clauses - net decreased in 2004. The 2004 decrease was mainly due to the implementation of the
CPUC-authorized rate-reduction plan and a net increase in energy procurement costs. The decrease was also due to the recovery of gas
hedging costs through regulatory mechanisms in 2003, as well as an allocation adjustment for CDWR energy purchases recorded in 2003.
Other operation and maintenance expense increased in 2004 primarily due to increases at both SCE and EME.
SCE's other operating and maintenance expense increase in 2004 was mainly due to higher transmission access charges, costs incurred
in 2004 related to the removal of dead, dying and diseased trees and vegetation associated with the bark beetle infestation (see
"SCE: Regulatory Matters--Other Regulatory Matters--Catastrophic Event Memorandum Account"), higher operation and maintenance costs
related to the San Onofre Unit 2 refueling outage in 2004, as well as a scheduled major overhaul at one of its coal facilities, and
additional costs for 2003 incentive compensation due to upward revisions in the computation.
EME's other operation and maintenance expense increased in 2003 due to an increase in transmission costs primarily resulting from
higher retail sales generated by EME's Contact Energy and higher debt restructuring costs incurred in 2004.
Other Income and Deductions
Interest and dividend income decreased in 2004 due to no interest income on the PROACT balance at SCE in 2004, as compared to 2003.
At July 31, 2003 the PROACT balance was overcollected, and was transferred to the ERRA on August 1, 2003.
Other nonoperating income increased in 2004. The 2004 increase was mainly due to 2001 and 2002 Palo Verde nuclear incentives
approved by the CPUC and recorded in 2004 at SCE, and a gain related to the sale of EME's stock of Edison Mission Energy Oil & Gas
(see "Acquisitions and Dispositions" for further details).
Interest expense - net of amounts capitalized increased in 2004. The 2004 increase was due to higher levels of borrowings at EME's
Contact Energy, and a change in classification of dividend payments on preferred securities to interest expense from dividends on
preferred securities subject to mandatory redemption effective July 1, 2003. The increase was partially offset by lower interest
expense at SCE due to lower long-term debt balances outstanding in 2004, as compared to 2003. In addition, interest expense - net
increased due to the issuance of the $800 million secured loan received by EME's subsidiary, Mission Energy Holdings International,
in December 2003 which was mostly offset by lower interest expense as EME's Midwest Generation due to a reduction of $1.0 billion in
debt partially from the proceeds of such transaction.
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Other nonoperating deductions decreased in 2004, primarily due to a loss related to the sale of EME's interest in Brooklyn Navy Yard
Cogeneration Partners L.P. (see "Acquisitions and Dispositions" for further details) and an increase in minority interest expense.
Minority interest primarily relates to the 49% ownership of EME's Contact Energy that is publicly held.
Income Taxes
Income tax expense increased in 2004 primarily due to an increase in pre-tax income, changes in foreign taxes at EME and cumulative
adjustments made to deferred tax balances at Edison Capital and EME in 2004.
Edison International's composite federal and state statutory rate was approximately 40.5% for both periods presented. The effective
tax rate realized in the first quarter of 2004 was 40.6%. The first quarter 2004 effective tax rate was reduced due to low-income
housing and production tax credits at Edison Capital, as well as resuming dividend payments to the employee stock ownership plan at
SCE. This reduction was offset by an increase in foreign taxes at EME, cumulative adjustments made to deferred tax balances at
Edison Capital and EME, and property-related flow-through taxes at SCE. The lower effective tax rate of 32.3% realized in the first
quarter of 2003 was primarily due to low-income housing and production tax credits at Edison Capital, partially offset by property
related flow-through taxes at SCE.
Earnings (Loss) from Discontinued Operations
Discontinued operations in the first quarter of 2003 reflect earnings from SCE's fuel oil pipeline and storage business, which was
sold in the third quarter of 2003.
Cumulative Effect of Accounting Change - net of tax
Edison International's results for 2004 include a charge for the cumulative effect of a change in accounting principle reflecting the
impact of Edison Capital's implementation of an accounting standard that requires the consolidation of certain variable interest
entities. Edison International's results for 2003 include a charge at EME for the cumulative effect of an accounting change related
to the accounting standard for recording asset retirement obligations. Because SCE follows accounting principles for rate-regulated
enterprises, implementation of this new standard did not affect earnings.
Historical Cash Flow Analysis
The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating, financing and investing
activities.
Cash Flows from Operating Activities
Net cash provided by operating activities:
In millions Three Months Ended March 31, 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ 320 $ 693
Discontinued operations (1) (13)
- ------------------------------------------------------------------------------------------------------------------------------
$ 319 $ 680
- ------------------------------------------------------------------------------------------------------------------------------
The change in cash provided by operating activities was mainly due to the timing of cash receipts and disbursements related to
working capital items.
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Cash Flows from Financing Activities
Net cash provided (used) by financing activities:
In millions Three Months Ended March 31, 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ 719 $ (191)
Discontinued operations (65) --
- ------------------------------------------------------------------------------------------------------------------------------
$ 654 $ (191)
- ------------------------------------------------------------------------------------------------------------------------------
Cash used by financing activities from continuing operations in 2004 mainly consisted of long-term and short-term debt payments at
SCE and EME.
Financing activities in the first quarter of 2004 were mainly due to activities at SCE. During the first quarter of 2004, SCE issued
$300 million of 5% bonds due in 2014, $525 million of 6% bonds due in 2034 and $150 million of floating rate bonds due in 2006. The
proceeds from these issuances were used to redeem $300 million of 7.25% first and refunding mortgage bonds due March 2026, $225
million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding mortgage bonds due
October 2018, and $100 million of junior subordinated deferrable interest debentures due June 2044. During the first quarter of
2004, SCE paid the $200 million outstanding balance of its credit facility. In the first quarter of 2004, SCE remarketed
approximately $550 million of pollution-control bonds with varying maturity dates ranging from 2008 to 2040, of which approximately
$196 million of these pollution-control bonds were reoffered. In March 2004, SCE issued $300 million of 4.65% first and refunding
mortgage bonds due in 2015 and $350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the proceeds from
the March 2004 first and refunding mortgage bond issuances were used to fund the acquisition and construction of the Mountainview
project. Financing activities in 2004 also included a $65 million dividend (which was declared on December 11, 2003) paid by Edison
International to its shareholders on January 30, 2004.
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. SCE repaid $300 million of a one-year term loan due March 3, 2003, which was part of
the $1.6 billion financing that took place in the first quarter of 2002. EME's financing activity in the first quarter of 2003
consisted of net borrowings of $80 million on EME's $487 million corporate credit facility, $320 million in borrowings by Contact
Energy, EME's 51% owned subsidiary, of which $275 million was used to finance Contact Energy's acquisition of the Taranaki Combined
Cycle power station, and debt service payments of $23 million.
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Three Months Ended March 31, 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (473) $ (635)
Discontinued operations -- 4
- ------------------------------------------------------------------------------------------------------------------------------
$ (473) $ (631)
- ------------------------------------------------------------------------------------------------------------------------------
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.
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Investing activities in 2004 reflect $317 million in additions to SCE's property and plant, primarily for transmission and
distribution assets and $22 million in capital additions at EME. In addition, investing activities include $285 million of
acquisition costs related to the Mountainview project at SCE and proceeds received in 2004 at EME from the sale of 100% of EME's
stock of Edison Mission Energy Oil & Gas and the sale of EME's 50% partnership interest in the Brooklyn Navy Yard project.
First quarter 2003 additions to SCE's property and plant were approximately $267 million, primarily for transmission and distribution
assets. EME's capital additions in the first quarter of 2003 were $56 million primarily for new plant and equipment related to EME's
Illinois plants and the Homer City facilities. EME's first quarter 2003 investing activity also included $275 million paid by
Contact Energy for the acquisition of Taranaki Combined Cycle power station, and $23 million in equity contribution to EME's Sunrise
and CBK projects.
ACQUISITIONS AND DISPOSITIONS
On March 31, 2004, EME completed the sale of its 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P. to a third
party for a sales price of approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of
2003 related to the planned disposition of this investment and a pre-tax loss of approximately $4 million during the first quarter of
2004 due to changes in the terms of the sale.
On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in Redlands, California.
SCE has recommenced full construction of the approximately $600 million project, which is expected to be completed in 2006. SCE
expects to finance the capital costs of the project with debt and equity consistent with its authorized capital structure.
On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn holds minority
interests in Four Star Oil & Gas to Medicine Bow Energy Corporation. Proceeds from the sale were approximately $100 million. EME
recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.
CRITICAL ACCOUNTING POLICIES
Variable Interest Entities
A new accounting standard provides guidance on the identification of, and financial reporting for, variable interest entities (VIEs),
where control may be achieved through means other than voting rights. An enterprise that is expected to absorb or receive the
majority of a VIE's expected losses or residual returns, or both, must consolidate the VIE, unless specific exceptions apply. See
"New Accounting Principles."
Edison International analyzes its potential variable interests by calculating operating cash flows. A fixed-price contract to
purchase electricity from a power plant does not absorb sufficient variability to be considered a variable interest. A contract with
a non-gas-fired plant that is based on gas prices is also not a variable interest. A contract of short duration with respect to the
economic life of the project is not considered to be a significant variable interest.
SCE has 275 long-term power-purchase contracts with independent power producers that own QFs. SCE was required under federal law to
sign such contracts, which typically require SCE to purchase 100% of the power produced by these facilities; the CPUC controls the
terms and pricing. SCE conducted a review of its QF contracts and determined that SCE has variable interests in 22 contracts with
gas-fired cogeneration plants that contain variable pricing provisions based on gas prices. SCE requested from the
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entities that hold these contracts the financial information necessary to determine whether SCE must consolidate these projects. All
22 entities declined to provide SCE with the necessary financial information. However, four of the 22 contracts are with entities
49%-50% owned by EME. Although the four related-party entities have declined to provide their financial information to SCE, Edison
International has access to such information and has provided that information to SCE on a combined basis. SCE has determined that
it must consolidate the four power projects partially owned by EME based on a qualitative analysis of the facts and circumstances of
the entities, including the related-party nature of the transaction. SCE will continue to attempt to obtain information for the
other 18 projects in order to determine whether they should be consolidated by SCE. The remaining 253 contracts will not be
consolidated by SCE under the new accounting standard since SCE lacks a variable interest in these contracts or the contracts are
with governmental agencies.
EME reviewed all of its power projects to determine whether they are variable interest entities and, if so, whether EME is the
consolidating entity. EME has four equity-method partnerships that sell power to SCE. EME will continue to use the equity method
for these projects, which have been consolidated by SCE effective March 31, 2004. Doga, a 180-MW gas-fired power plant in Turkey (of
which EME owns 80%), has a power sales contract that is considered a variable interest due to the energy price provisions that absorb
the risk of changes in fuel costs and the transfer of ownership of the cogeneration plant to the energy purchaser at the end of the
power sales contract. Kwinana, a 116 MW gas-fired power plant in Australia (of which EME owns 70%), has power sales contracts that
are considered variable interests due to the energy price provisions that absorb the risk of changes in fuel costs. EME
deconsolidated the Doga and Kwinana projects effective March 31, 2004 and will record its interests in these projects on the equity
method beginning April 1, 2004. The remaining projects either: meet the definition of a business under the new accounting standard
and thus fall outside the scope of the new accounting standard; or absorb insufficient variability for EME to be considered the
consolidating entity.
Edison Capital analyzed all of its projects and consolidated two affordable housing partnerships and three wind projects. Edison
Capital determined it was the related party most closely associated with the business of the VIEs for the two affordable housing
partnerships and absorbs the majority of the expected losses and receives the majority of the expected residual returns for the three
wind projects. For the remaining projects, Edison Capital determined it was not the related party entity most closely associated
with the VIEs.
For a complete discussion of Edison International's other critical accounting policies see the year-ended 2003 MD&A.
NEW ACCOUNTING PRINCIPLES
In December 2003, the Financial Accounting Standards Board issued a revision to an accounting Interpretation (originally issued in
January 2003), Consolidation of Variable Interest Entities. The primary objective of the Interpretation is to provide guidance on
the identification of, and financial reporting for, VIEs, where control may be achieved through means other than voting rights.
Under the Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected losses or residual
returns, or both, must consolidate the VIE, unless specific exceptions apply. This Interpretation is effective for special purpose
entities, as defined by accounting principles generally accepted in the United States, as of December 31, 2003, and all other
entities as of March 31, 2004. See the year-ended 2003 MD&A for information on special purpose entities consolidated as of
December 31, 2003.
Upon implementing this new accounting standard, SCE consolidated four power projects partially owned by EME, EME deconsolidated two
power projects and Edison Capital consolidated two affordable housing partnerships and three wind projects. See "Critical Accounting
Policies--Variable Interest
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Entities" for further discussion. Edison International recorded a cumulative effect adjustment that decreased net income by
approximately $1 million, net of tax, due to negative equity at one of Edison Capital's newly consolidated entities.
COMMITMENTS AND GUARANTEES
The following is an update to Edison International's commitments and guarantees. See the "Commitments and Guarantees" section of the
year-ended 2003 MD&A for a detailed discussion of commitments and guarantees.
Edison International's long-term debt maturities and sinking-fund requirements for the five twelve-month periods following March 31,
2004 are: 2005-- $2.0 billion; 2006-- $1.2 billion; 2007-- $2.5 billion; 2008-- $451 million; 2009-- $1.5 billion; and thereafter--
$7.0 billion. These amounts have been updated to reflect financing activities during the first quarter of 2004.
OTHER DEVELOPMENTS
Environmental Matters
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.
Environmental Remediation
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 34 identified sites at SCE (26 sites) and EME (8 sites)
is $89 million, $87 million of which is related to SCE. 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 $186 million, all of
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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 $29 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 $70 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 $13 million to $25 million. Recorded costs for the twelve months ended March 31, 2004 were
$16 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 asserted tax deficiencies are timing differences
and, therefore, amounts ultimately paid (exclusive of interest and penalties), 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.
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. This matter is now being considered by the
Administrative Appeals branch of the IRS. Edison Capital will contest the assessment through administrative appeals and litigation,
if necessary, and believes it should prevail in an outcome that will not have a material adverse financial impact.
The IRS is examining the tax returns for Edison International, which include Edison Capital, for years 1997 through 1999. Edison
Capital expects the IRS will also challenge several of its other leveraged leases based on recent Revenue Rulings 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
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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.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the
possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice on contingent liability companies that was published in 2001. These transactions
include certain Edison Capital leveraged lease transactions discussed above and a transaction entered into by an SCE subsidiary,
which may be considered substantially similar to a listed transaction. Edison International filed these amended returns under
protest retaining its appeal rights and believes that it will prevail in an outcome that will not have a material financial impact.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition
and Results of Operations," under the headings "SCE: Market Risk Exposures," "MEHC and EME: Market Risk Exposures," "Edison
Capital: Market Risk Exposures," and "Edison International (Parent): Market Risk Exposures" and is incorporated herein by this
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 that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the
period, Edison International's disclosure controls and procedures are effective.
As of March 31, 2004, Edison International implemented the Financial Accounting Standards Board's revision to FASB Interpretation
No. 46 (FIN 46-R), "Consolidation of Variable Interest Entities," referred to as "VIEs." Edison International's implementation of
FIN 46-R resulted in the accounting consolidation of four VIEs that are 49%-50% owned by Edison Mission Energy and in which SCE has
variable interests in the form of power purchase contracts. Edison International performed its evaluation of disclosure controls and
procedures as of March 31, 2004, and therefore did not include these entities in that evaluation. In addition, Edison International
has not designed, established, or maintained disclosure controls and procedures for these consolidated VIEs.
Internal Control over Financial Reporting
As discussed above in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," SCE is
conducting an investigation into allegations that personnel in the service planning group of SCE's transmission and distribution
business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an
independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any
incentive rewards or penalties to SCE under its performance-based ratemaking provisions for customer satisfaction. Based on the
investigation, SCE has concluded that some wrongdoing by service planning employees occurred. SCE has taken prompt remedial action
by severing the employment of certain supervisory personnel, updating system processes and related documentation for survey
reporting, and implementing additional supervisory controls over data collection and processing. These remedial actions constitute
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). The changes were designed to prevent possible future significant deficiencies or material weaknesses in
internal control over financial reporting. SCE is currently in the process of testing the effectiveness of these changes. As SCE's
investigation continues, Edison International and SCE will continue to determine if additional changes in internal control over
financial reporting are necessary.
For the same reasons discussed above in "Disclosure Controls and Procedures," Edison International's most recent evaluation of
internal control over financial reporting did not include the four VIEs that Edison International was required to consolidate because
of FIN 46-R.
There were no changes in Edison International's internal control over financial reporting during the 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, except for the changes noted above to the extent those changes may be considered material.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The following is a description of litigation of subsidiaries of Edison International that may be material to Edison International.
Southern California Edison Company
Navajo Nation Litigation
Information about the Navajo Nation Litigation appears in Part I, Item 2, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" under the heading "SCE: Other Developments--Navajo Nation Litigation" and is incorporated herein
by this reference.
CPUC Litigation Settlement Agreement
Information about Southern California Edison Company's (SCE) lawsuit against the California Public Utilities Commission (CPUC), its
settlement, and the appeal of the stipulated judgment approving the settlement appears in Part I, Item 2, "Management's Discussion
and Analysis of Financial Condition and Results of Operations" under the heading "SCE: Regulatory Matters--Generation and Power
Procurement--CPUC Litigation Settlement Agreement" and is incorporated herein by this reference.
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
Information about the CPUC's order instituting investigation regarding SCE's electric line maintenance practices appears in Part I,
Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the heading "SCE: Regulatory
Matters--Transmission and Distribution--Electric Line Maintenance Practices Proceeding" and is incorporated herein by this reference.
Department of Toxic Substances Control Enforcement Action
SCE received a draft enforcement order, consent order and related documents from the California Department of Toxic Substances
Control, seeking penalties totaling $383,400. The Department of Toxic Substances Control alleged that SCE failed, during a 13-month
period ending in March 2002, to properly maintain prescribed levels of financial assurance in connection with its on-site management
of hazardous waste at the San Onofre nuclear plant. Without admitting liability, SCE settled this alleged violation with the
Department of Toxic Substances Control through the use of an administrative consent order on March 25, 2004 for the sum of $210,000.
County of San Bernardino Investigation
The County of San Bernardino Office of District Attorney notified SCE, in a letter dated September 23, 2003, of its intent to file a
misdemeanor criminal complaint and a civil complaint seeking injunctive relief for the alleged failure to report a spill of oil from
a transformer in an isolated area of San Bernardino County. The penalties according to the County could range from $5,604 to
$555,604. The parties have entered into a tolling agreement and are continuing settlement discussions.
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Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
(e) Issuer purchases of equity securities
The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser
(as defined in Rule 10B-18 under the Securities Act) of shares or other units of any class of Edison International's equity
securities that is registered pursuant to Section 12 of the Exchange Act.
(c) Total (d) Maximum
Number of Shares Number (or
(or Units) Approximate
Purchased Dollar Value)
as Part of of Shares
(a) Total Publicly (or Units) that May
Number of Shares (b) Average Announced Yet Be Purchased
(or Units) Price Paid per Plans or Under the Plans or
Purchased1 Share (or Unit)1 Programs Programs
Period
- --------------------------- ----------------------- ----------------------- ----------------------- ------------------------
January 1, 2004 to 2,131,541 $22.18 --- ---
January 31, 2004
February 1, 2004 to 1,129,595 $21.98 --- ---
February 29, 2004
March 1, 2004 to 2,671,688 $23.45 --- ---
March 31, 2004
- --------------------------- ----------------------- ----------------------- ----------------------- ------------------------
Total 5,932,824 $22.70 --- ---
- --------------------------- ----------------------- ----------------------- ----------------------- ------------------------
- -------------------
1 All of the shares were Edison International Common Stock purchased by Edison International or agents acting on its behalf to
fulfill requirements in connection with Edison International's (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Stock
Purchase Plan, and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant
to plan terms or participant elections. Edison International did not control the quantity of shares purchased, the timing of the
purchases, or the price of the shares purchased in these transactions. None of the shares purchased were retired as a result of
the transactions.
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Edison International
3.1 Restated Articles of Incorporation of Edison International effective May 9, 1996
(File No. 1-9936, filed as Exhibit 3.1 to Edison International 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 (File No. 1-9936, Edison International Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors effective January 1, 2002 (File No.
1-9936, Edison International Form 10-K for the year ended December 31, 2001)*
10.1 Terms and conditions for 2004 long-term compensation awards under the Equity Compensation Plan and the 2000
Equity Plan
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
-------------- ---------- ----------------
February 26, 2004 March 2, 2004 5 and 7
February 26, 2004 February 26, 2004 12*
- ----------------
** The February 26, 2004 Form 8-K reporting events under Item 12 was furnished under Item 12 and shall not be deemed to be "filed"
for purposes of the Securities and Exchange Act of 1934, nor shall it be deemed to be incorporated by reference in any filing
under the Securities Act of 1933.
Page 79
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: May 7, 2004