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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 November 5, 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 and Nine Months
Ended September 30, 2004 and 2003 1
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2004 and 2003 2
Consolidated Balance Sheets - September 30, 2004
and December 31, 2003 3
Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2004 and 2003 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 34
Item 3. Quantitative and Qualitative Disclosures About Market Risk 92
Item 4. Controls and Procedures 92
Part II. Other Information:
Item 1. Legal Proceedings 93
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 94
Item 6. Exhibits 95
Signatures
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions, except per-share amounts 2004 2003 2004 2003
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(Unaudited)
Electric utility $ 2,655 $ 2,794 $ 6,527 $ 6,994
Nonutility power generation 509 602 1,228 1,326
Financial services and other 24 25 85 73
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Total operating revenue 3,188 3,421 7,840 8,393
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Fuel 415 239 1,010 630
Purchased power 915 1,013 2,022 2,187
Provisions for regulatory adjustment clauses - net (34) 332 (85) 1,141
Other operation and maintenance 782 709 2,351 2,096
Asset impairment and loss on lease termination 35 -- 989 251
Depreciation, decommissioning and amortization 232 253 752 726
Property and other taxes 50 50 148 130
Net gain on sale of utility plant -- (5) -- (5)
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Total operating expenses 2,395 2,591 7,187 7,156
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Operating income 793 830 653 1,237
Interest and dividend income 9 19 32 107
Equity in income from partnerships and
unconsolidated subsidiaries - net 30 119 57 196
Other nonoperating income 5 26 97 66
Interest expense - net of amounts capitalized (254) (262) (746) (753)
Other nonoperating deductions (12) (11) (50) (31)
Minority interest (76) -- (119) --
Dividends on preferred securities subject to mandatory redemption -- -- -- (52)
Dividends on utility preferred stock
not subject to mandatory redemption (1) (1) (4) (4)
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Income (loss) from continuing operations before tax 494 720 (80) 766
Income tax (benefit) 181 260 (39) 249
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Income (loss) from continuing operations 313 460 (41) 517
Income from discontinued operations - net of tax 500 84 579 116
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Income before accounting change 813 544 538 633
Cumulative effect of accounting change - net of tax -- -- (1) (9)
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Net income $ 813 $ 544 $ 537 $ 624
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Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings (loss) per share:
Continuing operations $ 0.96 $ 1.41 $ (0.13) $ 1.59
Discontinued operations 1.53 0.26 1.78 0.36
Cumulative effect of accounting change -- -- -- (0.03)
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Total $ 2.49 $ 1.67 $ 1.65 $ 1.92
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Weighted-average shares, including
effect of dilutive securities 330 329 330 329
Diluted earnings (loss) per share:
Continuing operations $ 0.95 $ 1.40 $ (0.13) $ 1.57
Discontinued operations 1.51 0.25 1.76 0.35
Cumulative effect of accounting change -- -- -- (0.02)
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Total $ 2.46 $ 1.65 $ 1.63 $ 1.90
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Dividends declared per common share $ 0.20 $ -- $ 0.60 $ --
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2004 2003 2004 2003
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(Unaudited)
Net income $ 813 $ 544 $ 537 $ 624
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Other comprehensive income (expense), net of tax:
Foreign currency translation adjustments:
Other foreign currency translation adjustments - net 33 7 26 70
Reclassification adjustment for sale of investment
in an international project (134) -- (134) --
Unrealized gain (loss) on investments - net (6) 4 11 2
Unrealized gains (losses) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges - net (1) 53 (49) 76
Reclassification adjustment for gain (loss)
included in net income 27 1 70 (5)
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Other comprehensive income (loss) (81) 65 (76) 143
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Comprehensive income $ 732 $ 609 $ 461 $ 767
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The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions 2004 2003
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(Unaudited)
ASSETS
Cash and equivalents $ 2,434 $ 1,980
Restricted cash 70 79
Receivables, less allowances of $32 and $31 for uncollectible
accounts at respective dates 1,272 983
Accrued unbilled revenue 510 408
Fuel inventory 78 87
Materials and supplies, at average cost 234 211
Accumulated deferred income taxes - net 340 563
Trading and price risk management assets 15 22
Prepayments 82 88
Other current assets 101 59
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Total current assets 5,136 4,480
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Nonutility property - less accumulated provision for
depreciation of $1,267 and $591 at respective dates 3,883 3,179
Nuclear decommissioning trusts 2,609 2,530
Investments in partnerships and unconsolidated subsidiaries 650 828
Investments in leveraged leases 2,410 2,361
Other investments 209 176
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Total investments and other assets 9,761 9,074
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Utility plant, at original cost:
Transmission and distribution 15,396 14,861
Generation 1,367 1,371
Accumulated provision for depreciation (4,588) (4,386)
Construction work in progress 737 600
Nuclear fuel, at amortized cost 153 141
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Total utility plant 13,065 12,587
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Restricted cash 130 187
Regulatory assets - net 265 510
Other deferred charges 869 738
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Total deferred charges 1,264 1,435
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Assets of discontinued operations 4,512 7,440
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Total assets $ 33,738 $ 35,016
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The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions, except share amounts 2004 2003
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ -- $ 200
Long-term debt due within one year 985 1,921
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,164 932
Accrued taxes 494 486
Trading and price risk management liabilities 66 36
Regulatory liabilities - net 9 361
Other current liabilities 1,674 1,722
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Total current liabilities 4,401 5,667
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Long-term debt 11,129 9,147
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Accumulated deferred income taxes - net 4,984 5,361
Accumulated deferred investment tax credits 141 149
Customer advances and other deferred credits 954 807
Power-purchase contracts 154 213
Preferred securities subject to mandatory redemption 139 141
Accumulated provision for pensions and benefits 496 425
Asset retirement obligations 2,158 2,106
Other long-term liabilities 256 247
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Total deferred credits and other liabilities 9,282 9,449
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Liabilities of discontinued operations 2,794 4,724
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Total liabilities 27,606 28,987
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Commitments and contingencies (Notes 2 and 4)
Minority interest 355 517
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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) 1,985 1,970
Accumulated other comprehensive loss (129) (53)
Retained earnings 3,792 3,466
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Total common shareholders' equity 5,648 5,383
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Total liabilities and shareholders' equity $ 33,738 $ 35,016
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The accompanying notes are an integral part of these financial statements.
Page 4
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
September 30,
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In millions 2004 2003
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(Unaudited)
Cash flows from operating activities:
Income (loss) from continuing operations, after accounting change, net of tax $ (42) $ 508
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax 1 9
Depreciation, decommissioning and amortization 752 726
Other amortization 78 81
Minority interest 119 --
Deferred income taxes and investment tax credits (138) (22)
Equity in income from partnerships and unconsolidated subsidiaries (57) (196)
Income from leveraged leases (62) (62)
Regulatory assets - long-term - net 284 414
Asset impairment 35 251
Gain on sale of assets (44) (5)
Levelized rent expense (59) (96)
Other assets (80) 57
Other liabilities 79 (296)
Changes in working capital net of effects from consolidation and
deconsolidation of variable interest entities:
Receivables and accrued unbilled revenue (300) (219)
Regulatory liabilities - short-term - net (352) 792
Prepayments and other current assets 50 (43)
Accrued interest and taxes 9 219
Accounts payable and other current liabilities 86 326
Distributions and dividends from unconsolidated entities 41 306
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Net cash provided by operating activities 400 2,750
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Cash flows from financing activities:
Long-term debt issued 3,358 (10)
Long-term debt repaid (2,542) (918)
Bonds remarketed - net 350 --
Redemption of preferred securities (2) (6)
Rate reduction notes repaid (177) (176)
Short-term debt financing - net (263) --
Dividends to minority shareholders (90) --
Dividends paid (195) --
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Net cash provided (used) by financing activities 439 (1,110)
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Cash flows from investing activities:
Additions to property and plant (1,165) (890)
Acquisition costs related to nonutility generation plant (285) --
Proceeds from sale of interest in projects 858 --
Contributions to nuclear decommissioning trusts - net (62) (16)
Distributions from (investments in) partnerships and unconsolidated subsidiaries 15 (35)
Investments in other assets 54 76
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Net cash used by investing activities (585) (865)
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Effect of consolidation of variable interest entities on cash 79 --
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Net changes in cash of discontinued operations 40 4
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Net increase in cash and equivalents 373 779
Cash and equivalents, beginning of period 2,198 2,468
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Cash and equivalents, end of period 2,571 3,247
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Cash and equivalents, discontinued operations (137) (132)
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Cash and equivalents, continuing operations $ 2,434 $ 3,115
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The accompanying notes are an integral part of these financial statements.
Page 5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting principles generally
accepted in the United States for the periods covered by this report. The results of operations for the period ended September 30,
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).
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."
Effective second quarter 2004, 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. Despite the ring-fencing
provisions, EME's Standard & Poor's credit rating fell to "B" and therefore, EME's management believed that these provisions, which
included dividend restrictions and a requirement to maintain an independent director, were no longer necessary. Due to the removal
of these ring fencing provisions, Edison International will include Mission Energy Holding Company (MEHC) - parent only, which holds
debt of $1.2 billion and has no business activities other than through its ownership interest in EME, in its nonutility power
generation business segment. As a result, the nonutility power generation business segment will be comprised of MEHC (parent only)
and EME.
Effective third quarter 2004, Edison International's consolidated financial statements for all periods presented reflect the
reclassification of the results of EME's international power generation portfolio as discontinued operations in accordance with an
accounting standard related to the impairment and disposal of long-lived assets. See further discussion in Note 8.
Certain other prior-period amounts were reclassified to conform to the September 30, 2004 financial statement presentation.
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Dividend Restriction
The California Public Utilities Commission (CPUC) regulates SCE's capital structure, limiting the dividends it may pay Edison
International. In SCE's 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 September 30, 2004, SCE's 13-month weighted-average common equity component of total capitalization was 51%. At
September 30, 2004, SCE had the capacity to pay $230 million in additional dividends based on the 13-month weighted-average method.
Based on recorded September 30, 2004 balances, SCE's common equity to total capitalization ratio, for rate-making purposes, was 50%.
SCE had the capacity to pay $139 million of additional dividends to Edison International based on September 30, 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 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 Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
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(Unaudited)
Basic weighted-average shares
of common stock outstanding 326 326 326 326
Stock-based compensation awards exercisable 4 3 4 3
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Dilutive weighted-average shares
of common stock outstanding 330 329 330 329
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Goodwill
Goodwill represents the excess of cost incurred over the fair value of net assets acquired in a purchase transaction. As a result of
the reclassification of results of EME's international operations (including Contact Energy and First Hydro) as discontinued
operations, EME's goodwill, which was primarily related to the acquisition of Contact Energy and First Hydro, is now included in
assets of discontinued operations. See Note 8 for further information.
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
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 deconsolidated as of
December 31, 2003.
SCE has 272 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 under terms and pricing controlled by the CPUC. SCE conducted a review of its QF contracts and determined that SCE has
variable interests in 17 contracts with gas-fired cogeneration plants that are potential VIEs and that contain variable pricing
provisions based on the prices of natural gas and for which SCE does not have sufficient information to determine if the projects
qualify for a scope exception. SCE requested from the entities that hold these contracts the financial information necessary to
determine whether SCE must consolidate these projects. All 17 entities declined to provide SCE with the necessary financial
information. However, four of the 17 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 combined financial statements to SCE. 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 13 projects in order to determine whether they should be consolidated by SCE.
The remaining 255 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 transfer sufficient risk to the purchaser to be considered a variable interest. A
contract with a non-natural-gas-fired plant that is based on the price of natural gas is also not a variable interest. SCE has other
power contracts with non-QF generators. SCE has determined that these contracts are not significant variable interests.
On March 31, 2004, 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. 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 (ARO)
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.
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear
Effective January 1, 2004, San Onofre Nuclear Generating Station Units 2 and 3 returned to traditional cost-of-service ratemaking.
The July 8, 2004 CPUC decision on SCE's 2003 general rate case returned Palo Verde Nuclear Generating Station to traditional
cost-of-service ratemaking retroactive to May 22, 2003 (the date a final CPUC decision was originally scheduled to be issued).
SCE's nuclear plant investments are recorded as a regulatory asset on its balance sheets. This classification does not affect the
rate-making treatment for these assets. SCE had been recovering its investments in San Onofre Units 2 and 3 and Palo Verde on an
accelerated basis, as authorized by the CPUC. The accelerated recovery was to continue through December 2001, earning a 7.35% fixed
rate of return on investment. San Onofre's operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental
capital expenditures, were recovered through an incentive pricing plan that allowed SCE to receive about 4(cent)per kilowatt-hour (kWh)
through 2003. Any differences between these costs and the incentive price flowed through to shareholders. Palo Verde's accelerated
plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, were subject to balancing account treatment through the effective date of the 2003 general rate case.
The nuclear rate-making plans were to continue for rate-making purposes at least through the 2003 general rate case effective date
for Palo Verde operating costs and through 2003 for the San Onofre incentive pricing plan. However, due to the various unresolved
regulatory and legislative issues as of December 31, 2000, SCE was no longer able to conclude that the unamortized nuclear investment
was probable of recovery through the rate-making process. As a result, this balance was written off as a charge to earnings at that
time. As a result of the CPUC's April 4, 2002 decision that returned SCE's utility-retained generation (URG) assets to cost-based
ratemaking, SCE reestablished for financial reporting purposes its unamortized nuclear investment and related flow-through taxes,
retroactive to August 31, 2001, based on a 10-year recovery period, effective January 1, 2001, with a corresponding credit to
earnings. SCE adjusted the procurement-related obligations account regulatory asset balance to reflect recovery of the nuclear
investment in accordance with the final URG decision.
In a September 2001 decision, the CPUC granted SCE's request to continue the rate-making treatment for Palo Verde, including the
continuation of the nuclear unit incentive procedure with a 5(cent)per kWh cap on replacement power costs, until resolution of SCE's 2003
general rate case or further CPUC action. Palo Verde's nuclear unit incentive procedure calculated a reward for performance of any
unit above an 80% capacity factor for a fuel cycle. The San Onofre Units 2 and 3 incentive rate-making plan continued until
December 31, 2003.
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:
September 30, December 31,
In millions 2004 2003
- ---------------------------------------------------------------------------------------------------------
(Unaudited)
Current:
Regulatory balancing accounts and other - net $ (9) $ (361)
- ---------------------------------------------------------------------------------------------------------
Long-term:
Flow-through taxes - net 1,056 974
Rate reduction notes - transition cost deferral 769 949
Unamortized nuclear investment - net 618 601
Nuclear-related ARO investment - net 276 288
Unamortized coal plant investment - net 65 66
Unamortized loss on reacquired debt 246 222
Environmental remediation 61 71
ARO (716) (720)
Costs of removal (2,102) (2,020)
Regulatory balancing accounts and other - net (8) 79
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265 510
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Total $ 256 $ 149
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The regulatory asset related to the rate reduction notes will be recovered over the terms of those notes. The net regulatory asset
related to the unamortized nuclear investment will be recovered by the end of the remaining useful lives of the nuclear assets. SCE
has requested a four-year recovery period for the net regulatory asset related to its unamortized coal plant investment. CPUC
approval is pending. The other regulatory assets and liabilities are being recovered through other components of electric rates.
Balancing account undercollections and overcollections accrue interest based on a three-month commercial paper rate published by the
Federal Reserve. Income tax effects on all balancing account changes are deferred.
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 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income, as reported $ 813 $ 544 $ 537 $ 624
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 3 2 11 5
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 3 3 10 7
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 813 $ 543 $ 538 $ 622
- -------------------------------------------------------------------------------------------------------------------
Basic earnings per share:
As reported $ 2.49 $ 1.67 $ 1.65 $ 1.92
Pro forma $ 2.49 $ 1.67 $ 1.65 $ 1.91
Diluted earnings per share:
As reported $ 2.46 $ 1.65 $ 1.63 $ 1.90
Pro forma $ 2.46 $ 1.65 $ 1.63 $ 1.89
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Supplemental Accumulated Other Comprehensive Loss Information
Supplemental information regarding Edison International's accumulated other comprehensive loss, including the discontinued operations
of EME's international power generation portfolio (sale pending), Ferrybridge and Fiddler's Ferry power plants and Lakeland project,
is:
September 30, December 31,
In millions 2004 2003
- -----------------------------------------------------------------------------------------------------
(Unaudited)
Foreign currency translation adjustments - net $ 38 $ 146
Minimum pension liability - net(1) (23) (23)
Unrealized gain (loss) on investments - net 4 (7)
Unrealized losses on cash flow hedges - net (148) (169)
- -----------------------------------------------------------------------------------------------------
Accumulated other comprehensive loss $ (129) $ (53)
- -----------------------------------------------------------------------------------------------------
Included in Edison International's accumulated other comprehensive loss at September 30, 2004, was a $140 million loss related to
EME's unrealized losses on cash flow hedges. Of the $140 million loss, $63 million was related to EME's commodity hedges and
$77 million was related to EME's interest rate hedges. Unrealized losses (comprised of losses on interest rate hedges and commodity
hedges) pertained to both continuing and discontinued operations as follows:
o Continuing operations - Unrealized losses on commodity hedges for continuing operations included those primarily related to
EME's Homer City and Midwest Generation forward electricity contracts that did not meet the normal sales and purchases exception
under the derivative accounting standard. These losses arise because current forecasts of future electricity prices in these
markets are greater than contract prices.
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unrealized losses on cash flow hedges for continuing operations included those related to SCE's interest rate swap. The swap
terminated on January 5, 2001, but the related debt matures in 2008. The unamortized loss of $7 million (as of September 30,
2004, net of tax) on the interest rate swap will be amortized over a period ending in 2008. Approximately $2 million (after tax)
of the unamortized loss on this swap will be reclassified into earnings during the next 12 months.
As EME's hedged positions for continuing operations are realized, approximately $29 million (after tax) of the net unrealized
losses on cash flow hedges at September 30, 2004 are expected to be reclassified into earnings during the next 12 months. EME
expects that reclassification of net unrealized losses will offset energy revenue recognized at market prices. Actual amounts
ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of
changes in market conditions. The maximum period over which an EME cash flow hedge is designated is through December 31, 2006.
o Discontinued operations - Unrealized losses on commodity hedges for discontinued operations included primarily EME's hedge
agreement with the State Electricity Commission of Victoria for electricity prices from the Loy Yang B project in Australia that
did not meet the normal sales and purchases exception under the derivative accounting standard. Unrealized losses on interest
rate hedges for discontinued operations included those related to EME's share of interest rate swaps of its unconsolidated
affiliates, the Loy Yang B project and the Spanish Hydro project.
The unrealized losses for discontinued operations will be reclassified into earnings upon the completion of the sale of EME's
international projects.
Page 12
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flows Information
Nine Months Ended
September 30,
- --------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Noncash Investing and Financing Activities:
Components related to continuing operations
Details of consolidation of variable interest entities:
Assets $ 625 --
Liabilities (704) --
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
Components related to discontinued operations
Details of deconsolidation of variable interest entities:
Assets $ (220) --
Liabilities 254 --
Details of assets acquired:
Fair value of assets acquired $ -- $ 333
Cash paid for acquisitions -- (275)
- --------------------------------------------------------------------------------------------------------------
Liabilities assumed -- $ 58
- --------------------------------------------------------------------------------------------------------------
Variable Interest Entities
Entities Consolidated Upon Implementation of New Accounting Standard
SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions based on the price of
natural gas. 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 QFs sell electricity to SCE and steam to nonrelated 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 at September 30, 2004 is $384 million ($896 million at original cost less $512 million in accumulated
depreciation) and is recorded in nonutility property.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Project Capacity Termination Date EME Ownership
- --------------------------------------------------------------------------------------------------------
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 contract payments.
Any liabilities of these projects are nonrecourse to SCE.
The variable interest entities' operating costs, instead of purchased power expense, are shown in Edison International's income
statements effective April 1, 2004. Further, Edison International's electric utility revenue now includes revenue from the sale of
steam by these four projects.
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 nonrecourse debt
totaling $33 million at September 30, 2004. Properties serving as collateral for these loans had a carrying value of $49 million and
are classified as nonutility property on the September 30, 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 Doga and Kwinana projects effective March 31, 2004. Prior periods have not been restated. EME recorded its
interests in these projects on the equity method beginning April 1, 2004. The Doga and Kwinana projects are part of EME's sale of
international operations and, accordingly, are included in discontinued operations.
Significant Variable Interests in Entities Not Consolidated
EME has a significant variable interest in the Sunrise project, which is a gas-fired facility located in California. As of
September 30, 2004, EME had a 50% ownership interest in the project and its investment was $112 million. EME's maximum exposure to
loss is generally limited to its investment in this entity. Previously, EME had determined that it had significant variable
interests in the following entities or projects (Paiton, EcoElectrica, ISAB, CBK, IVPC4 Srl, Doga and Tri Energy); however, due to
the pending sale of EME's international power generation portfolio, these projects are now included in discontinued operations.
Edison Capital's maximum exposure to loss from affordable housing investments in this category is generally limited to its net
investment balance of $77 million and recapture of tax credits.
Entities with Unavailable Financial Information
SCE has 13 nonrelated-party contracts with certain QFs that contain variable pricing provisions based on the price of natural gas and
are potential VIEs. 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 13 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consolidated by SCE. The aggregate capacity dedicated to SCE for these projects is 359 MW. SCE paid $77 million and $173 million,
respectively, for the three and nine months ended September 30, 2004 and $73 million and $164 million, respectively, for the three
and nine months ended September 30, 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. In third quarter 2004, SCE received additional information
about the legal structure of five projects previously in this category and determined that those projects are not VIEs.
Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources (CDWR) power purchases
and revenue requirements, and generation procurement, 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 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 seeking to overturn
the stipulated judgment of the federal district court that approved the 2001 CPUC settlement agreement. In September 2002, the Ninth
Circuit Court 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 Court 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 Court. The matter was returned to the Ninth Circuit Court for final disposition and in
December 2003, the Ninth Circuit Court unanimously affirmed the original stipulated judgment of the federal district court. In
January 2004, the Ninth Circuit Court 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.
In an April 22, 2004, decision, the CPUC imposed minor penalties ($656,000) related to SCE's overhead and underground electric line
maintenance practices for failing to make repairs within a reasonable amount of time. The decision provides SCE with more
flexibility in scheduling inspections, but 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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Rate Case (GRC)
On May 3, 2002, SCE filed an application for its 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 incremental cost incentive pricing (ICIP) rate-making mechanism at year-end
2003 and a forecast of increased sales.
The CPUC issued a final decision on July 8, 2004, authorizing an annual increase of approximately $73 million in base rates,
retroactive to May 22, 2003 (the date a final CPUC decision was originally scheduled to be issued). The decision also authorized a
base rate revenue decrease of $49 million in 2004, and a subsequent increase of $84 million in 2005. During the second quarter of
2004, SCE recorded pre-tax net regulatory adjustments of $180 million as a result of the implementation of the 2003 GRC decision,
primarily relating to the recognition of revenue from the rate recovery of pension contributions during the time period that the
pension plan was fully funded, the resolution of the allocation of costs between transmission and distribution for 1998 through 2000,
partially offset by the deferral of revenue previously collected during the ICIP mechanism for dry cask storage. The adjustments
were included in provisions for regulatory adjustment clauses - net on the income statement.
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 and the date a final decision was
adopted. In July 2004, SCE submitted an advice filing to record the amount in this memorandum account and recorded an approximate
$55 million pre-tax gain in the third quarter of 2004 included in electric utility revenue on the income statement. In addition,
during the third quarter of 2004 SCE recorded approximately $48 million in pre-tax gains related to the 1997-1998 generation-related
capital additions ($31 million, which is included in provisions for regulatory adjustment clauses - net on the income statement) and
the related rate recovery ($17 million, which is included in electric utility revenue on the income statement).
The amount recorded in the GRC memorandum account will be recovered in rates together with the 2004 revenue requirement authorized by
the CPUC in the GRC decision. The GRC rate increase was combined with other rate changes from pending rate proceedings and became
effective August 5, 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.
In January 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
violated this requirement, reserving such a determination for a later phase of the proceedings. In February 2002, SCE and Edison
International filed an application before the CPUC for rehearing of the decision. In July 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. In August 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. Pacific Gas and
Electric (PG&E) and San Diego Gas & Electric Co. (SDG&E) and their respective holding companies filed similar challenges, and all
cases were transferred to the First District Court of Appeal in San Francisco.
On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities' and their holding
companies' challenges to both CPUC decisions. The Court of Appeal held that the CPUC has limited jurisdiction to enforce in a CPUC
proceeding the conditions agreed to by holding companies incident to their being granted authority to assume ownership of a
CPUC-regulated utility. The Court of Appeal held that the CPUC's decision interpreting the first priority requirement was not
reviewable because the CPUC had not made any ruling that any holding company had violated the first priority requirement. However,
the Court of Appeal suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of violation and the
underlying interpretation of the first priority requirement itself. On June 30, 2004, Edison International and the other utility
holding companies filed with the California Supreme Court a petition for review of the Court of Appeal decision as to jurisdiction
over holding companies, but they and the utilities did not file a challenge to the decision as to the first priority issue. On
September 1, 2004, the California Supreme Court denied the petition for review. The Court of Appeal's decision on jurisdiction is
now final.
The original order instituting investigation into whether the utilities and their holding companies have complied with CPUC decisions
and applicable statutes remains in effect, and the CPUC could initiate further proceedings as to any of the issues mentioned in the
first paragraph above. It is uncertain whether or when the CPUC would do so.
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. Until the post-2005 coal and water supply uncertainty is resolved, SCE and other Mohave
co-owners cannot determine whether it would be cost-effective to make the 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.
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 data are 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 three years is likely.
On October 20, 2004, the CPUC issued a proposed decision which, among other things, (1) directed SCE to continue negotiations
regarding the post-2005 coal and water supply; (2) directed SCE to conduct a study of potential alternatives to Mohave including
solar generation and coal gasification; and (3) provided an opportunity for SCE to recover in future rates certain Mohave-related
costs that SCE has already incurred or is expected to incur by 2006, including certain preliminary engineering costs, water study
costs and the costs of the study of Mohave alternatives. A final decision is not expected before December 2004.
In parallel with the CPUC proceedings, negotiations have continued among the relevant parties in an effort to resolve the coal and
water supply issues. In September 2004 the parties reached agreement on certain "key principles" related to the study and possible
development of a potential alternative water supply, and the parties agreed to retain a professional mediator for further
negotiations, but no further resolution has been reached.
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.
The outcome of this matter is not expected to have a material impact on earnings.
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 (El Paso) 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
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 United States District Court has issued an order approving the
stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC decision, SCE will refund to customers
amounts received under the terms of the El Paso
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
settlement (net of legal and consulting costs) through its energy resource recovery account mechanism. In June 2004, SCE received
its first settlement payment of $76 million. Approximately $66 million of this amount was credited to purchased-power expense and
will be refunded to SCE's ratepayers through the energy resource recovery account over the next 12 months and the remaining
$10 million was used to offset SCE's incurred legal costs. Additional settlement payments totaling approximately $134 million are due
from El Paso over a 20-year period. Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement
allocated to SCE in proportion to SCE's share of the CDWR's power charge revenue requirement.
On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and 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. On August 2, 2004, SCE received its approximately $37 million share of the refunds and other
payments under the Williams settlement.
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. (collectively, Dynegy). The settlement terms provide for refunds and
other payments totaling $285 million, with a proposed allocation to SCE of approximately $40 million. The Dynegy settlement terms
were submitted to the FERC for its approval on June 28, 2004. The FERC is expected to act on the Dynegy settlement before year-end
2004.
On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy Corporation and a
number of its affiliates. The settlement terms agreed to with the Duke parties provide for refunds and other payments totaling in
excess of $200 million, with a proposed allocation to SCE of approximately $45 million. The Duke settlement was submitted to the
FERC for its approval on October 1, 2004.
The exact manner in which net settlement proceeds under the Duke, Williams and Dynegy settlements will be refunded to customers is
expected to be the subject of a future CPUC determination. Any settlement amounts received have been deferred, pending a final
decision.
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 September 30, 2004, $16 million in contributions have been made. Additional funding in 2004 may be restricted by
tax-deductible funding limits. Edison International's expenses for its foreign plans are included in discontinued operations.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components for United States pension plans are:
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 26 $ 24 $ 79 $ 71
Interest cost 43 43 130 128
Expected return on plan assets (59) (48) (177) (143)
Net amortization and deferral 6 9 18 27
- --------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 16 28 50 83
Regulatory adjustment - deferred -- (11) -- (33)
- --------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 16 $ 17 $ 50 $ 50
- --------------------------------------------------------------------------------------------------------------------
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 September 30, 2004, $18 million in contributions have been made. Additional funding in 2004 may be
restricted by tax-deductible funding limits. Additionally, contributions will be lower than expected due to the impact of the
Medicare Prescription Drug, Improvement and Modernization Act of 2003 (see below).
In May 2004, the Financial Accounting Standards Board issued accounting guidance related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003. Edison International adopted this guidance effective July 1, 2004, which resulted in a
decrease of $83 million to Edison International's accumulated benefit obligation. Edison International's third quarter 2004 expense
decreased approximately $5 million as a result of the subsidy. According to proposed federal regulations, Edison International's
retiree health care plans provide prescription drug benefits that are deemed to be actuarially equivalent to Medicare benefits.
Accordingly, Edison International recognized the subsidy in the measurement of its accumulated obligation and recorded an actuarial
gain.
Expense components are:
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 9 $ 11 $ 32 $ 33
Interest cost 29 32 96 94
Expected return on plan assets (27) (23) (82) (67)
Net amortization and deferral (1) 10 14 30
- -------------------------------------------------------------------------------------------------------------------
Total expense $ 10 $ 30 $ 60 $ 90
- -------------------------------------------------------------------------------------------------------------------
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings
before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International
believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has 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 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 investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison Capital in
2004 is $41 million. A restructure of the lease could also result in a loss of some or all of the investment. At September 30,
2004, American Airlines was current in its lease payments to Edison Capital.
Employee Compensation and Benefit Plans
In April 1999, Edison International adopted a cash balance feature for its pension plan. 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 (including a post-IBM decision issued in June 2004) 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. On September 15 and September 29, 2004, IBM announced settlements of
some of the claims, but stated the company would continue to appeal the two claims relating to age discrimination. The settlements
also cap the potential damages IBM will face if it loses its appeal on the age discrimination issues. 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 31 identified sites at SCE (24 sites) and EME (7 sites)
is $90 million, $88 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 $131 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 $30 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 $61 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 September 30, 2004
were $17 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 these
matters 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 deferral of income taxes associated with the EPZ
and Dutch electric locomotive leases. The IRS has also given notice that it will assert the same arguments for the 1997 to 1999
audit 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. In
conjunction with this examination, Edison Capital received notices of proposed adjustments to Edison International's tax liability
which, if upheld, would accelerate the payment of taxes that were deferred as a result of several of its other leveraged leases
entered into in 1997 and 1998. The proposed adjustment is based on revenue rulings issued by the IRS in 1999 and 2002 in connection
with the IRS' industry-wide challenge mounted against a specific type of leveraged lease (termed a lease in/lease out or LILO
transaction). The estimated federal and state income taxes deferred from these leases was $558 million in the 1997-1999 audit period
and $565 million in subsequent years through 2003. The IRS has also proposed interest and penalties. Edison International believes
that the positions described in the revenue rulings are incorrectly applied to Edison Capital's transactions and that its leveraged
leases are factually and legally distinguishable in material respects from that position. Edison International 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 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 described by the IRS as a contingent liability company. 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.
Investigations Regarding Performance Incentive Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties based on its
performance in comparison to CPUC-approved standards of (1) customer satisfaction, (2) employee injury and illness reporting, and
(3) system reliability.
Page 23
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE has been conducting investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings
of misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own
proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer
satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose
additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of
refunds, disallowances and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 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 recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE
also anticipated that it could be eligible for customer satisfaction rewards of about $10 million for 2003.
SCE has been conducting an internal investigation and keeping the CPUC informed of its progress. On June 25, 2004, SCE submitted to
the CPUC a PBR customer satisfaction investigation report, which concluded that employees in the design organization of the
transmission and distribution business unit deliberately altered customer contact information in order to affect the results of
customer satisfaction surveys. At least 36 design organization personnel engaged in deliberate misconduct including alteration of
customer information before the data were transmitted to the independent survey company. Because of the apparent scope of the
misconduct, SCE proposed to refund to ratepayers all of the $12 million in PBR rewards that are attributable to the design
organization's portion of the customer satisfaction rewards for the entire PBR period (1997-2003). In addition, during its
investigation, SCE determined that it could not confirm the integrity of the method used for obtaining customer satisfaction survey
data for meter reading. Thus, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards
associated with meter reading. SCE expects that it would refund approximately half of the total of $14 million from customer
satisfaction rewards previously received. SCE believes it is likely that it could deal with the approximate remaining half by
adjustments to the pending and to-be-requested rewards noted above.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory
personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls
over data collection and processing.
The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data requests to SCE and has
requested an opportunity to interview a number of SCE employees in the design organization. SCE is in the process of responding to
those requests.
Page 24
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting an investigation into the accuracy of
SCE's employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to
determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has
received $20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, may be entitled to an
additional $15 million for 2001 through 2003.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies
certain findings concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. Under the PBR
mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident rate, which included two equally
weighted measures: Occupational Safety and Health Administration (OSHA) recordable incidents and first aid incidents. The major
issue disclosed in the investigative findings to the CPUC was that SCE failed to implement an effective recordkeeping system
sufficient to capture all required data for first aid incidents. SCE's investigation also found reporting inaccuracies for OSHA
recordable incidents, but the impact of these inaccuracies did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism for any year before 2005,
and it return to ratepayers the $20 million it has already received. SCE has also proposed to withdraw the pending rewards for the
2001-2003 time frames.
SCE is taking other remedial action to address the issues identified, including, revising its organizational structure and overall
program for environmental, health and safety compliance. Additional actions, including disciplinary action against specific
employees identified as having committed wrongdoing, may result once the entire investigation is completed, which is expected by the
end of November 2004.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation into the third PBR
metric, system reliability. Since the inception of PBR payments in 1997, SCE has received $8 million in rewards and has applied for
an additional $5 million reward based on frequency of outage data for 2001. For 2003, SCE's data would result in a penalty of
$5 million which has not yet been assessed.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC that overall, the reliability reporting
system is working well.
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
Page 25
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 United States 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 D.C. District Court subsequently issued a scheduling order that imposed a
December 31, 2004 discovery cut-off. Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay of
the action to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave. The
facilitated negotiations are currently set to commence on November 8, 2004. The stay granted by the D.C. District Court is scheduled
to expire on February 5, 2005.
The United States Court of Appeals for the D.C. Circuit, 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 D.C. Circuit Court decision. Both petitions were denied on March 9, 2004. On
March 16, 2004, the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004. As a result of the status conference discussion, the Court of Federal Claims
has ordered the Navajo Nation and the Government to brief the remaining issues following remand. Peabody's motion to intervene as a
party in the remanded Court of Federal Claims case was denied.
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 San Onofre and Palo
Verde 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
Page 26
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
required to pay a maximum of $199 million per nuclear incident. However, it would have to pay no more than $20 million per incident
in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are
subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further
revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. 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 $43 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 did not meet its obligation to begin
acceptance of spent nuclear fuel not later than January 31, 1998. 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
and associated 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. The case if currently stayed pending development in other spent nuclear fuel cases also before
the Federal Court of Claims.
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 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 was completed in late 2004.
Movement of Unit 1 spent fuel from the Unit 2 spent fuel pool to the independent spent fuel pool storage installation is scheduled to
be completed by spring 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 late 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.
Page 27
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Storm Lake
As of September 30, 2004, Edison Capital had an investment of approximately $76 million in Storm Lake Power, a project developed by
Enron Wind, a subsidiary of Enron Corporation. As of September 30, 2004, Storm Lake had outstanding loans of approximately
$50 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.
Storm Lake and Edison Capital have filed claims for damages in Enron's bankruptcy of approximately $60 million. On July 15, 2004,
Enron's plan of reorganization was confirmed, which indicated that distributions would be made as soon as practical.
Note 5. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), a nonutility power
generation segment (MEHC - parent only and EME), and a financial services provider segment (Edison Capital). In accordance with an
accounting standard related to operating segments, prior periods have been restated to conform to Edison International's new business
segment definition. Also, in accordance with an accounting standard related to the impairment and disposal of long-lived assets,
prior periods have been restated to reflect EME's international operations being reported as discontinued operations. See further
discussion in "Basis of Presentation" in Note 1.
Page 28
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information for the three and nine months ended September 30, 2004 and 2003 was:
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 2,655 $ 2,794 $ 6,527 $ 6,994
Nonutility power generation 509 602 1,228 1,326
Financial services 22 21 78 65
Corporate and other 2 4 7 8
- -------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 3,188 $ 3,421 $ 7,840 $ 8,393
- -------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 259 $ 374 $ 600 $ 700
Nonutility power generation(2) 559 175 (44) (57)
Financial services(3) 12 14 33 41
Corporate and other (17) (19) (52) (60)
- -------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 813 $ 544 $ 537 $ 624
- -------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock. Includes earnings from discontinued operations of $45 million and $50 million,
respectively, for the three and nine months ended September 30, 2003.
(2) Includes a loss of $9 million from the cumulative effect of an accounting change for the nine months ended September 30,
2003. Also, includes earnings from discontinued operations of $500 million and $579 million, respectively, for the three
and nine months ended September 30, 2004 and $39 million and $66 million, respectively, for the three and nine months ended
September 30, 2003.
(3) Includes a loss of $1 million from the cumulative effect of an accounting change for the nine months ended September 30,
2004.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.
Total segment assets as of September 30, 2004 were: electric utility, $19 billion; nonutility power generation, $10 billion; and,
financial services, $3 billion.
Note 6. Acquisition and Dispositions
Acquisition
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 early 2006.
The construction work in progress for this project is recorded in nonutility property on Edison International's September 30, 2004
balance sheet.
Page 29
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Dispositions
On September 30, 2004, EME completed the sale of its 51% interest in Contact Energy to Origin Energy New Zealand Limited.
Consideration for the sale was NZ$1.6 billion (approximately $1.1 billion) which includes NZ$535 million of debt assumed by the
purchaser. The after-tax gain on the sale of Contact Energy was $141 million and is included in income from discontinued operations
(net of tax) on the consolidated income statement for the three and nine months ended September 30, 2004.
On July 29, 2004, EME entered into an agreement to sell its remaining international power generation portfolio, owned by a wholly
owned Dutch subsidiary, MEC International B.V., to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd.
(30%). The purchase price is $2.3 billion, subject to certain purchase price adjustments prior to closing that are expected to
result in a net purchase price of approximately $2.2 billion. Closing of the BV transaction is subject to approval by International
Power's shareholders and to a number of regulatory approvals and project level consents. If certain project level approvals and
consents are not obtained, one or more projects may be excluded from the sale transaction and the purchase price may be adjusted
accordingly. The sale is expected to close in the fourth quarter of 2004. EME's estimate of the after-tax gain on the sale of its
international projects is approximately $120 million. Net proceeds from the sale will be used to repay the remaining $200 million
due from the $800 million secured loan at Mission Energy Holdings International, Inc., other indebtedness and for general corporate
purposes. EME will retain its ownership of the subsidiaries associated with the Lakeland project and some inactive subsidiaries.
See Note 8 regarding further discussion of EME's discontinued international operations.
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 held 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. Asset Impairment and Loss on Lease Termination
On April 27, 2004, EME's subsidiary, Midwest Generation LLC, 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. This amount
represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for
early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction and plans to
continue fulfilling its obligation under the power-purchase agreement with Exelon Generation Company LLC, which is scheduled to
expire at the end of 2004 and, thereafter, cease operations at this location. EME recorded a pre-tax loss of approximately
$956 million (approximately $587 million after tax) during the quarter ended June 30, 2004, due to termination of the lease and the
planned decommissioning of the asset, and disposition of excess inventory.
Page 30
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Following the termination of the Collins Station lease, Midwest Generation announced plans to permanently cease operations at the
Collins Station by December 31, 2004 and decommission the plant. On July 30, 2004, PJM Interconnection, LLC (PJM) accepted Midwest
Generation's request to cease operations at the Collins Station. PJM found that the decommissioning of the plant would not affect
the operation or reliability of the PJM markets. During the third quarter of 2004, EME reached an agreement with Exelon Generation
to terminate the power purchase agreement effective September 30, 2004, for the two units at the Collins Station that remained under
contract. As a result of the termination of the power purchase agreement, EME revised the estimated useful life of the remaining
plant assets to end on September 30, 2004 instead of December 31, 2004. Accordingly, EME recorded a pre-tax impairment charge of $5
million during the third quarter of 2004. In October 2004, EME finalized plans to reduce the workforce in Illinois and expects to
recognize a $4 million pre-tax charge for exit costs during the fourth quarter of 2004.
In September 2004, EME completed an analysis of future competitiveness in the expanded PJM marketplace of its eight small peaking
units in Illinois. Based on this analysis, EME decided to decommission six of the eight small peaking units, subject to regulatory
review and approval. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less
than the book value of the units resulting in an impairment under an accounting standard for the impairment or disposal of long-lived
assets. During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately $18 million after
tax).
EME anticipates that the lease termination payment and decommissioning of the Collins Station and small peaking units will result in
substantial income tax deductions. In connection with the termination of the Collins Station lease, Midwest Generation will continue
to have obligations under the tax indemnity agreement with the former lease equity investor. See further discussion of this tax
indemnity agreement in "EME's Guarantees and Indemnities" of Note 9 of "Notes to Consolidated Financial Statements" included in
Edison International's 2003 Annual Report.
During second quarter 2003, EME recorded an asset impairment charge resulting from a revised long-term outlook for capacity revenue
from its eight small peaking units in Illinois due to a number of factors, including the effect of higher long-term natural gas
prices on the competitiveness of these units and the current oversupply of generation. Since capacity value represents a key revenue
component for these small peaking units, the revised outlook resulted in a write-down of the book value of these assets from $286
million to their estimated fair market value of $41 million. The estimated fair value was determined based on discounting estimated
future cash flows using a 17.5% discount rate. In addition, EME recorded an asset impairment charge associated with the planned
disposition of its investment in the Gordonsville project. The Gordonsville project sale was completed in November 2003. These
amounts are included in the asset impairment line item of the September 30, 2003 consolidated statements of income.
Note 8. Discontinued Operations
On September 30, 2004, EME completed the sale of its 51% interest in Contact Energy to Origin Energy New Zealand Limited. In
accordance with an accounting standard related to the impairment and disposal of long-lived assets, Contact Energy's results have
been accounted for as a discontinued operation in the financial statements for the three and nine months ended September 30, 2004 and
2003.
On July 29, 2004, EME entered into an agreement to sell its remaining international power generation portfolio, owned by a wholly
owned Dutch subsidiary, MEC International B.V., to a consortium
Page 31
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%). Closing of the BV transaction is subject to approval by
International Power's shareholders and to a number of regulatory approvals and project level consents. If certain project level
approvals and consents are not obtained, one or more projects may be excluded from the sale transaction and the purchase price may be
adjusted accordingly. The sale is expected to close in the fourth quarter of 2004. EME will retain its ownership of the subsidiaries
associated with the Lakeland project and some inactive subsidiaries. In accordance with an accounting standard related to the
impairment and disposal of long-lived assets, EME's remaining international power generation projects have been accounted for as
discontinued operations in the financial statements for the three and nine months ended September 30, 2004 and 2003.
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 and nine months ended September 30, 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 September 30, 2004 and 2003, revenue from discontinued operations was $354 million and $415 million,
respectively, and pre-tax income was $42 million and $139 million, respectively. For the nine months ended September 30, 2004 and
2003, revenue from discontinued operations was $1.1 billion for both periods and pre-tax income was $172 million and $204 million,
respectively.
During the third quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million to recognize the higher
tax basis of its international holding company (MEC International B.V.) over its book basis as required by accounting rules
applicable to discontinued operations. The tax basis of the stock of the BV exceeds the book basis primarily due to taxable income
recognized in the United States on several types of foreign earnings. Even though EME recorded current taxes payable in the United
States, no recognition of deferred taxes was recorded under standards related to income taxes, until the operations of the BV were
classified to discontinued operations. The sale of the remaining international projects is structured as a sale of the stock of the
BV, which held the international assets of MEHC. The taxable income from the sale of MEHC's interest in Contact Energy increased the
stock basis of the BV, resulting in a reduction to the projected tax on the sale of the remaining projects and recognition under
accounting rules of this deferred tax benefit.
Page 32
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The carrying value of major asset and liability classifications associated with Edison International's discontinued operations and
assets held for sale are:
September 30, December 31,
In millions 2004 2003
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Assets
Cash and equivalents $ 137 $ 218
Receivables - net 45 220
Other current assets 85 191
- --------------------------------------------------------------------------------------------------------------
Total current assets 267 629
- --------------------------------------------------------------------------------------------------------------
Investments in partnerships and
unconsolidated subsidiaries 1,158 1,080
Nonutility property - net 2,579 4,522
Goodwill 308 865
Other deferred charges 200 344
- --------------------------------------------------------------------------------------------------------------
Total assets of discontinued operations $ 4,512 $ 7,440
- --------------------------------------------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities $ 62 $ 232
Long-term debt due within one year 29 82
Other current liabilities 52 244
- --------------------------------------------------------------------------------------------------------------
Total current liabilities 143 558
- --------------------------------------------------------------------------------------------------------------
Long-term debt 1,707 2,640
Accumulated deferred income taxes and
investment tax credits - net 378 606
Customer advances and other deferred credits 423 570
Other long-term liabilities 143 350
- --------------------------------------------------------------------------------------------------------------
Total liabilities of discontinued operations $ 2,794 $ 4,724
- --------------------------------------------------------------------------------------------------------------
Note 9. Subsequent Event
On October 5, 2004, EME repaid $600 million of the $800 million secured loan at Mission Energy Holdings International, Inc. with the
majority of the proceeds received from the sale of Contact Energy. See further discussion in "Dispositions" in Note 6.
Page 33
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- and nine-month
periods ended September 30, 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- and nine-month periods ended September 30, 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) (parent), a subsidiary of Edison International, is the holding company for its wholly
owned subsidiary EME. Since the second quarter of 2004, Mission Energy Holding Company (parent) and EME are presented as one
business segment on a consolidated basis due primarily to the elimination of EME's so-called "ring fencing" provisions in EME's
certificate of incorporation and bylaws discussed below under "MEHC: Liquidity." 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, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison
International (parent) or parent company and MEHC (parent) mean Edison International or MEHC on a stand-alone basis, not consolidated
with its subsidiaries. References to SCE, EME or Edison Capital 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 segments (SCE, MEHC, and Edison Capital) and Edison
International (parent). Each principal operating segment's discussion includes discussions of liquidity, market risk exposures, and
other matters (as relevant to each principal operating segment). The remaining sections discuss Edison International on a
consolidated basis, including results of operations and historical cash flow analysis,
Page 34
acquisition and dispositions, critical accounting policies, new accounting principles, commitments and guarantees, and other
developments. These sections should be read in conjunction with each segment's section.
Page
----
Current Developments 36
Southern California Edison Company 39
Mission Energy Holding Company 54
Edison Capital 75
Edison International (Parent) 76
Results of Operations and Historical Cash Flow Analysis 78
Acquisition and Dispositions 86
Critical Accounting Policies 87
New Accounting Principles 88
Commitments and Guarantees 88
Other Developments 89
Page 35
CURRENT DEVELOPMENTS
The following section provides a discussion of current developments related to Edison International and its subsidiaries.
SCE: CURRENT DEVELOPMENTS
2003 General Rate Case Proceeding
On July 8, 2004, the California Public Utilities Commission (CPUC) issued a final decision on SCE's 2003 General Rate Case (GRC)
application. Because processing of the 2003 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 was adopted. In July 2004, SCE submitted an
advice filing to record the amount in this memorandum account, and recorded an approximate $55 million pre-tax gain in the third
quarter of 2004. In addition, during the third quarter of 2004 SCE recorded approximately $48 million in pre-tax gains related to
the rate recovery of 1997-1998 generation-related capital additions and the related revenue requirement. See "SCE: Regulatory
Matters--Transmission and Distribution--2003 General Rate Case Proceeding" for further details on the implementation of the 2003 GRC.
Proposed Legislation
The California Legislature submitted to the Governor of California Assembly Bill 2006, which was entitled the "Reliable Electric
Service Act." The bill proposed to affirm the obligation of utilities to plan and provide adequate, efficient, and cost-effective
supply and demand resources and would have required utilities to prepare a long-term resource plan to achieve a diversified portfolio
of cost-effective supply and demand resources. The Governor of California did not sign Assembly Bill 2006 into law. SCE will
continue to advocate steps to strengthen the regulatory framework to enhance assurance of utility cost recovery and to provide a fair
allocation of cost responsibility to all electricity consumers.
MEHC: CURRENT DEVELOPMENTS
Exercise of Term Loan Put-Option at MEHC (parent)
On April 5, 2004, the lenders under MEHC (parent)'s $385 million term loan due in 2006 exercised their right to require MEHC (parent)
to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million
principal, plus interest, was paid on July 2, 2004.
In July and October 2004, EME made dividend payments of $69 million and $5 million, respectively, to MEHC (parent). These payments
were used together with cash on hand to meet the Term Loan Put-Option payment discussed above.
EME amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were
implemented in early 2001 during the California energy crisis, which had included restrictions on dividends.
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Disposition of EME's International Operations
As indicated in the year-ended 2003 MD&A, EME engaged investment bankers to market for sale its international project portfolio.
During the third quarter of 2004:
o EME completed the sale of its 51.2% interest in Contact Energy Limited (Contact Energy) to Origin Energy New Zealand Limited
on September 30, 2004. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and
NZ$535 million (approximately US$359 million) of debt assumed by the purchaser. The after-tax gain on the sale of Contact Energy
was $141 million. EME also entered into a purchase option to hedge against a decrease in the value of the New Zealand dollar.
The purchased option was settled in October 2004 with a net after-tax cost of $15 million. The majority of the proceeds were
used to repay $600 million of the $800 million secured loan at Mission Energy Holdings International, Inc. with the balance
retained for general corporate purposes. (See "MEHC: Liquidity --Key Financing Developments--EME Financing Developments.")
o EME entered into an agreement dated July 29, 2004 to sell its remaining international power generation portfolio, owned by a
wholly owned Dutch subsidiary, MEC International B.V., to a consortium comprised of International Power plc (70%) and Mitsui &
Co., Ltd. (30%). The purchase price is $2.3 billion, subject to certain purchase price adjustments prior to closing that are
expected to result in a net purchase price of approximately $2.2 billion. Closing of the BV transaction is subject to approval
by International Power's shareholders and to a number of regulatory approvals and project level consents. If certain project
level approvals and consents are not obtained, one or more projects may be excluded from the sale transaction and the purchase
price may be adjusted accordingly. EME's estimate of the after-tax gain on the sale of its international projects is
approximately $120 million. The sale is expected to close in the fourth quarter of 2004.
Together, these two transactions represent the sale of all of EME's interests in its international projects, except that EME will
retain its ownership of the Lakeland project and some inactive international subsidiaries. The estimated net gain on sale of
international projects, including recognition of a deferred tax benefit of $327 million during the third quarter of 2004, is
$573 million. See "Results of Operations--Earnings from Discontinued Operations" and "Acquisitions and Dispositions."
Accounting Presentation of Discontinued and Continuing Operations
Beginning in third quarter, all of EME's international operations are accounted for as discontinued operations in accordance with an
accounting standard related to the impairment and disposal of long-lived assets, and, accordingly, all prior periods have been
restated to reclassify the results of operations and assets and liabilities as discontinued operations. Continuing operations
include EME's Illinois plants and Homer City facilities, and equity investments in power projects primarily located in California.
Edison International financial statements and the segment discussion set forth herein have been adjusted to this format of reporting.
Dispositions of Investments in Other Energy Plants
On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held 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.
On March 31, 2004, EME completed the sale of 100% of its stock of Mission Energy New York, Inc., which in turn owned a 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
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pre-tax loss of approximately $4 million during the first quarter of 2004 due to changes in the terms of the sale.
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 PJM Interconnection, LLC (PJM)
effective May 1, 2004. EME had protested the integration of Commonwealth Edison into PJM before American Electric Power (AEP),
because Commonwealth Edison's service territory, independent of AEP, was only partially integrated into PJM via a limited
transmission pathway of 500 MW capability. This lack of interconnection capability limited Midwest Generation's access to the
broader PJM market. These concerns became moot on October 1, 2004, when AEP was integrated into PJM. As of October 1, 2004, Midwest
Generation had direct access to a fully interconnected market that covers twelve states and the District of Columbia, and serves a
peak load of over 107,000 MW over 49,300 miles of transmission lines. For further discussion, see "MEHC: Other Development--PJM
Regulatory Matters."
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SOUTHERN CALIFORNIA EDISON COMPANY
SCE: LIQUIDITY ISSUES
SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs, collateral and mark-to-market
requirements associated with purchase power contracts, and access to capital markets or external financings. At September 30, 2004,
SCE's credit and long-term issuer ratings from Standard & Poor's and Moody's Investors Service were BBB and Baa1, respectively. On
September 17, 2004, Moody's Investors Service assigned SCE a short-term credit rating of P2 in connection with SCE's launch of a new
$700 million commercial paper program. Standard and Poor's had previously issued SCE a short-term credit rating of A2. As of
September 30, 2004, SCE had no commercial paper outstanding.
At September 30, 2004, SCE had cash and equivalents of $188 million and long-term debt, including current maturities, of $5.4
billion. As of September 30, 2004, SCE posted approximately $42 million ($33 million in cash and $9 million in letters of credit) as
collateral to secure its obligations under power-purchase contracts and to transact through the California 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
has a $700 million credit facility that expires in December 2006. As of September 30, 2004, the credit facility was not utilized,
except for $9 million supporting letters of credit as mentioned above. SCE's 2004 estimated cash outflows consist of:
o $125 million of 5.875% bonds which were due and paid 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 "Acquisition and Dispositions");
o Dividend payments to SCE's parent company. SCE paid cash dividends of $300 million, $145 million and $150 million to Edison
International on March 30, 2004, May 21, 2004 and September 23, 2004, respectively;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations, including cash outflows for power-procurement 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.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In SCE's 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 September 30, 2004, SCE's
13-month weighted-average common equity component of total capitalization was 51%. At September 30, 2004, SCE had the capacity to
pay $230 million in additional dividends based on the 13-month weighted-average method. Based on recorded September 30, 2004
balances, SCE's common equity to total
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capitalization ratio, for rate-making purposes, was 50%. SCE had the capacity to pay $137 million of additional dividends to Edison
International based on September 30, 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 $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. Approximately $354 million of these pollution-control
bonds had been held by SCE since 2001 and the remaining $196 million were purchased and reoffered in 2004. 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'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. 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 submitted to the Governor of California Assembly Bill 2006, which was entitled the "Reliable Electric
Service Act." The bill proposed to affirm the obligation of utilities to plan and provide adequate, efficient, and cost-effective
supply and demand resources and would have required utilities to prepare a long-term resource plan to achieve a diversified portfolio
of cost-effective supply and demand resources. The Governor of California did not sign Assembly Bill 2006 into law. SCE will
continue to advocate steps to strengthen the regulatory framework to enhance assurance of utility cost recovery and to provide a fair
allocation of cost responsibility to all electricity consumers.
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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. The Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the United States Court of
Appeals for the Ninth Circuit seeking to overturn the stipulated judgment of the federal district court that approved the 2001 CPUC
settlement agreement. In September 2002, the Ninth Circuit Court 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 Court 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 Court. The matter was returned to the Ninth Circuit Court for final disposition, and in
December 2003, the Ninth Circuit Court unanimously affirmed the original stipulated judgment of the federal district court. In
January 2004, the Ninth Circuit Court 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.
2004 ERRA Forecast
SCE submitted an ERRA forecast application on October 3, 2003, in which it forecast 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 distribution services.
ERRA Reasonableness Reviews
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. Clarification is expected in a decision in the fourth quarter of 2004. 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.
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
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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 and reply
briefs, SCE urged the CPUC to reject 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; this
is, 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.
On September 27, 2004, the CPUC issued a proposed decision, adopting the SCE-ORA joint recommendation to adjust the ERRA downward by
approximately $3.6 million, and finding SCE's operations during the period from September 1, 2001 through June 30, 2003 reasonable in
all other respects. However, the proposed decision adopts ORA's position that the scope of the CPUC review of SCE's dispatch
operations should include a review of procurement transactions up to one year prior to the date of delivery. A decision on this
matter is expected in the fourth quarter of 2004.
On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find its
procurement-related operations during the period from July 1, 2003 through December 31, 2003, to be reasonable. In addition, SCE
requested recovery 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.
At hearings, the ORA recommended disallowances that totaled approximately $2.6 million based on its allegation that SCE should have
made additional surplus energy sales in the month-ahead market during October and November 2003. SCE contested ORA's disallowance
recommendation both on procedural grounds and on its merits. A final decision is expected in the first quarter of 2005.
2005 ERRA Forecast
SCE submitted an ERRA forecast application on August 2, 2004, in which it forecasted a procurement-related revenue requirement for
the 2005 calendar year of $3.0 billion, an increase of $733 million over 2004. The forecast increase is primarily due to a reduction
in expected power purchases by the California Department of Water Resources (CDWR). SCE proposed that the CPUC issue a final
decision on this matter in December 2004.
Generation Procurement Proceedings
SCE resumed power procurement responsibilities for its residual-net short position (the amount of energy needed to serve SCE's
customers from sources other than its own generating plants, power-purchase contracts and CDWR contracts) on January 1, 2003,
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. Currently, SCE is operating under this approved
short-term procurement plan. On July 9, 2004, SCE submitted minor revisions to this short-term procurement plan, as part of its
long-term resource plan filing, which is discussed below. The CPUC is expected to consider those modifications this fall and issue a
decision by the end of the year.
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Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related transactions associated
with serving the demands of its bundled electricity customers were in conformance with SCE's adopted short-term procurement plan.
SCE has submitted seven quarterly compliance filings covering the period from January 1, 2003 through September 30, 2004, including
its third quarter 2004 compliance filing on November 1, 2004 covering SCE's transactions for the period July 1, 2004 to September 30,
2004. To date, however, the CPUC has only issued one resolution approving SCE's first compliance report for the period January 1,
2003 to March 31, 2003. While SCE believes that all of its procurement transactions were in compliance with its adopted short-term
procurement plan, SCE cannot predict with certainty whether or not the CPUC will agree with SCE's interpretation regarding some
elements.
Long-Term Resource Plan
On April 15, 2003, SCE filed its long-term resource plan with the CPUC that included both a preferred plan and an interim plan. In
January 2004, the CPUC issued a decision that did not adopt any long-term resource plan, but adopted a framework for resource
planning which addressed short- and long-term resource planning, as well as the development of a resource adequacy requirement.
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 that will coordinate consideration of long-term resource plans.
On July 9, 2004, SCE filed testimony on its long-term resource plan, which includes a substantial commitment to cost-effective energy
efficiency and an advanced load-control program. The long-term resource plan presented four procurement plan scenarios: a
medium-load plan scenario, a high-load plan scenario, a low-load plan scenario, and a CDWR-variant scenario. Hearings on the
long-term procurement plans of SCE, Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E) were held
between August 30, 2004 and September 24, 2004. A decision is expected by year-end 2004.
On October 28, 2004, the CPUC issued a decision clarifying the January 2004 decision. The recent decision requires load serving
entities to ensure that adequate resources have been contracted for in order to meet that entity's peak forecasted energy resource
demand and an additional planning reserve margin of 15-17% of that peak load by June 1, 2006. Currently, the decision requires SCE
to demonstrate that it has contracted 90% of its May-September 2006 resource adequacy requirement by September 30, 2005. As the
May-September period approaches, SCE will be required to fill out the remaining 10% of its resource adequacy requirement one month in
advance of expected need. The October 28, 2004 decision also clarified that although the first compliance filing will only cover
May-September 2006, the 15-17% planning reserve margin is a year-round requirement. In its October decision, the CPUC also decided
that long-term CDWR contracts allocated to the investor-owned utilities during the 2001 energy crisis are to be fully counted for
resource adequacy purposes, and that any deliverability standards developed during subsequent phases will be applied to such
contracts. These deliverability standards, as well as a wide range of other issues, including scheduling, load forecasting and
deliverability generally, will be addressed in a separate phase of the proceeding which is expected to be completed by mid-2005. SCE
expects to meet its resource adequacy requirements by the deadlines set forth in the decision.
Procurement of Renewable Resources
As part of SCE's resumption of power procurement, and 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 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. In June 2004, the CPUC issued two decisions adopting additional rules
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on renewable procurement: a decision adopting standard contract terms and conditions and a decision adopting a market price
methodology. In July 2004, the CPUC issued a decision adopting criteria for the selection of least-cost and best-fit renewable
resources.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and is conducting
negotiations with a short list of bidders regarding potential procurement contracts. The procedures for measuring renewable
procurement are still being developed by the CPUC. Based upon the current regulatory framework, SCE anticipates that it will, even
without new renewable procurement contracts, comply with renewable procurement mandates through at least 2005. Beyond 2005, SCE will
either need to sign new contracts and/or extend existing renewable QF contracts.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order by the Governor of California, the CDWR began making emergency power purchases for SCE's
customers on January 17, 2001. The CDWR's total statewide power charge and bond charge revenue requirements are allocated by the
CPUC among the customers of SCE, PG&E and SDG&E. Amounts billed to and collected from SCE's customers for electric power purchased
and sold by the CDWR are remitted directly to the CDWR and are not recognized as revenue by SCE.
Currently, the CPUC is considering the appropriate methodology for allocating the CDWR's power charge revenue requirement for 2004
through 2013. PG&E, TURN, and SCE submitted a settlement agreement, which is supported by ORA, advocating that the costs of each of
the CDWR's long-term contracts be allocated directly to the investor-owned utility bearing operational responsibility for the
contract (a cost-follow-contracts allocation), with an annual adjustment to ensure that each investor-owned utility's customers bear
an equitable portion of the above-market costs burden of those contracts. The methodology proposed in the settlement agreement also
facilitates the appropriate incentives for operating and administering the contracts.
The CPUC issued four draft decisions that would reject the proposed settlement agreement. Two of those draft decisions would retain
the cost-follow-contracts allocation of the avoidable costs of CDWR contracts, but would allocate 43.75% of the unavoidable costs, as
opposed to the above-market burden, to the customers of PG&E, 43.75% to those of SCE, and 12.5% of the unavoidable costs to the
customers of SDG&E. While such an allocation would lower the portion of the total power charge revenue requirement that SCE's
customers would bear for the 10-year period, it would institute a methodology that SCE contends does not provide the appropriate
contract administration incentives to investor-owned utilities.
A third draft decision would also retain the cost-follow-contracts allocation of the avoidable costs of CDWR contracts, but would
allocate 42.2% of the unavoidable costs to the customers of PG&E, 47.5% to those of SCE, and only 10.3% of the unavoidable costs to
the customers of SDG&E.
Finally, a fourth draft decision, while rejecting the settlement agreement, would adopt some of its key attributes. It would adopt a
cost-follow-contracts allocation of the avoidable costs of CDWR contracts, and allocate the above-market costs associated with the
contracts: 44.8% to PG&E's customers, 45.3% to SCE's customers, and 9.9% to SDG&E's customers. PG&E, TURN and SCE have urged the
CPUC to adopt this final draft decision, modified to allocate a higher share to the customers of SDG&E.
A final decision on this matter is expected before year-end 2004.
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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. Until the post-2005 coal and water supply uncertainty
is resolved, SCE and other Mohave co-owners cannot determine whether it would be cost-effective to make the 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.
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 data are 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 three
years is likely.
On October 20, 2004, the CPUC issued a proposed decision which, among other things: (1) directed SCE to continue negotiations
regarding the post-2005 coal and water supply; (2) directed SCE to conduct a study of potential alternatives to Mohave including
solar generation and coal gasification; and (3) provided an opportunity for SCE to recover in future rates certain Mohave-related
costs that SCE has already incurred or is expected to incur by 2006, including certain preliminary engineering costs, water study
costs and the costs of the study of Mohave alternatives. A final decision is not expected before December 2004.
In parallel with the CPUC proceeding, negotiations have continued among the relevant parties in an effort to resolve the coal and
water supply issues. In September 2004, the parties reached agreement on certain "key principles" related to the study and possible
development of a potential alternative water supply, and the parties agreed to retain a professional mediator for further
negotiations, but no further resolution has been reached.
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.
The outcome of this matter is not expected to have a material impact on earnings.
San Onofre Nuclear Generating Station Proceedings and Related Matters
Steam Generator Proceedings
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 Nuclear Generating Station (San Onofre) Unit 2 and 3 steam generators and establishing appropriate ratemaking
for the replacement costs. In this filing, SCE also asked the CPUC for approval to establish a memorandum
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account for recovery of up to $50 million in costs to be incurred in connection with entering into contracts for steam generator
fabrication prior to the final CPUC decision. In June 2004, the CPUC established a schedule providing for a final CPUC decision in
September 2005. In July 2004, the CPUC denied SCE's request to establish the memorandum account.
On September 30, 2004, SCE entered into a contract for steam generator fabrication with Mitsubishi Heavy Industries America. By the
time of the CPUC's scheduled decision in September 2005, SCE anticipates that it will have committed approximately $50 million to
steam generator fabrication and associated project costs. SCE will seek recovery of these costs.
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. SCE has
declared an "operating impairment" in connection with the need for steam generator replacement. SDG&E and the City of Anaheim have
elected to reduce their respective 20% and 3.16% ownership shares rather than participate in the steam generator replacement
project. The other co-owner, the City of Riverside (which owns 1.79% of the units), has elected to participate in the project. If
steam generator replacement proceeds, upon completion, SDG&E's and the City of Anaheim's ownership shares of San Onofre Units 2 and 3
will be reduced in accordance with the formula set forth in the operating agreement. SCE and the City of Anaheim agree on
application of the formula. Utilizing the agreed-upon approach would reduce the City of Anaheim's share of San Onofre Units 2 and 3
to zero percent upon completion of the steam generator replacement. SCE and SDG&E do not agree on the application of the formula.
SCE believes SDG&E's ownership share would be reduced from 20% to zero percent. SDG&E's believes its ownership share would be
reduced from 20% to 14%. As a result, the application of the formula is subject to arbitration which SCE and SDG&E are attempting to
schedule for early 2005.
The transfer of all or any portion of SDG&E's and the City of Anaheim's respective ownership share as a result of their election not
to participate in steam generator replacement will require Nuclear Regulatory Commission approval. The transfer of all or any
portion of SDG&E's ownership share will require CPUC approval.
San Onofre Reactor Vessel Heads
During the ongoing San Onofre Unit 3 refueling outage that began on September 28, 2004, SCE conducted a planned inspection of the
Unit 3 reactor vessel head and found indications of degradation. Although the degradation is far below the level at which leakage
would occur, SCE plans to make repairs during the current outage using readily available tooling and a Nuclear Regulatory
Commission-approved repair technique. While this is San Onofre's first experience of this kind of degradation to the reactor vessel
head, the detection and repair of similar degradation is now common in the industry. SCE plans to replace the Unit 2 and 3 reactor
vessel heads during the planned refueling outages in 2009-2010.
San Onofre Pressurizer Heater Sleeve Replacement
San Onofre Units 2 and 3 each include a pressurizer tank that contains 30 heater penetrations fabricated from the same material used
in the steam generator tubes. These penetrations, also known as sleeves, are 13-inch long sections of pipe welded into the bottom of
the pressurizer. During the current Unit 3 outage, SCE performed inspections of two sleeves and found evidence of degradation.
Degradation of the pressurizer sleeves has been a concern in the nuclear industry for some time, and SCE had been planning to replace
all of the sleeves in both units during their next scheduled refueling outages in 2005 and 2006, respectively. With the discovery of
sleeve degradation, SCE has decided to move the planned replacement of all 30 of Unit 3's sleeves forward from 2006 into the current
outage. This extra work will lengthen the outage from 55 days to the range of 95 to 110 days. The unit is expected to return to
service
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in late December 2004 or January 2005. This additional repair work will cost approximately $9 million. The CPUC will review the
reasonableness of outage-related capital costs and replacement power costs in future rate-making proceedings. SCE believes the costs
are reasonable, recovery of the costs should be authorized, and the acceleration of the needed repairs should not impact earnings.
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 incremental cost incentive pricing (ICIP) rate-making mechanism at year-end
2003 and a forecast of increased sales.
The CPUC issued a final decision on SCE's 2003 GRC application on July 8, 2004, authorizing an annual increase of approximately
$73 million in base rates, retroactive to May 22, 2003 (the date a final CPUC decision was originally scheduled to be issued). The
decision also authorized a base rate revenue decrease of $49 million in 2004, and a subsequent increase of $84 million in 2005.
During the second quarter of 2004, SCE recorded pre-tax net regulatory adjustments of $180 million as a result of the implementation
of the 2003 GRC decision, primarily relating to the recognition of revenue from the rate recovery of pension contributions during the
time period that the pension plan was fully funded, the resolution of the allocation of costs between transmission and distribution
for 1998 through 2000, partially offset by the deferral of revenue previously collected during the ICIP mechanism for dry cask
storage. The adjustments were included in the caption "provisions for regulatory adjustment clauses--net" on the income statement.
See "Results of Operations and Historical Cash Flow Analysis--Results of Operations" for further discussion.
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 and the date a final decision was
adopted. In July 2004, SCE submitted an advice filing to record the amount in this memorandum account and recorded an approximate
$55 million pre-tax gain in the third quarter of 2004 included in the caption "electric utility revenue" on the income statement. In
addition, during the third quarter of 2004 SCE recorded approximately $48 million in pre-tax gains related to the 1997-1998
generation-related capital additions ($31 million, which is included in the caption "provisions for regulatory adjustment
clauses--net" on the income statement) and the related rate recovery ($17 million, which is included in the caption "electric utility
revenue" on the income statement). See "Results of Operations and Historical Cash Flow Analysis--Results of Operations" for further
discussion.
The amount recorded in the GRC memorandum account will be recovered in rates together with the 2004 revenue requirement authorized by
the CPUC in the GRC decision. The GRC rate increase was combined with other rate changes from pending rate proceedings and became
effective August 5, 2004.
2006 General Rate Case Proceeding
On August 20, 2004, SCE submitted a notice of intent to file an application for a 2006 GRC. SCE expects to ask the CPUC to authorize
a $396 million increase in base revenue requirement in 2006, primarily for capital expenditures to accommodate load growth and
replace aging distribution systems. SCE also expects to ask the CPUC to authorize continuation of SCE's existing post-test year
rate-making mechanism, which would result in base rate revenue increases of $157 million and $140 million in 2007 and 2008,
respectively. If the CPUC approves these requested increases and allocates them to ratepayer
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groups on a system average percentage change basis, the total increase over current base rates is estimated to be 10.8%. SCE
anticipates filing its 2006 GRC application in December 2004.
2005 Cost of Capital
SCE's annual cost of capital applications with the CPUC are required to be filed in May of each year, with decisions rendered in such
proceedings becoming effective January 1 of the following year. On May 10, 2004, SCE filed an application requesting the CPUC to
maintain for 2005 the currently authorized 11.60% return on common equity for SCE's CPUC-jurisdictional assets. SCE requested a
change in the authorized capital structure to reflect the debt equivalence of power-purchase agreements, and revised returns on
long-term debt and preferred stock. The request would result in a decrease in revenue requirement of approximately $28 million. A
final decision on this matter is expected in December 2004.
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.
In an April 22, 2004 decision, the CPUC imposed minor penalties ($656,000) related to SCE's overhead and underground electric line
maintenance practices for failing to make repairs within a reasonable amount of time. The decision provides SCE with more
flexibility in scheduling inspections, but 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. SCE has incurred approximately $85 million of these unrecovered
costs since 1998. 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 D.C. Circuit Court seeking voluntary remand to permit issuance of a further order. On
February 12, 2004, the D.C. Circuit 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. SCE and the other two California
utilities are pursuing the appeal before the D.C. Circuit Court, and filed their opening briefs with the D.C. Circuit Court on
October 12, 2004.
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) and 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
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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 (El Paso) 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
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 United States District Court has issued an order approving the
stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC decision, SCE will refund to customers
amounts received under the terms of the El Paso settlement (net of legal and consulting costs) through its ERRA mechanism. In June
2004, SCE received its first settlement payment of $76 million. Approximately $66 million of this amount was credited to purchased
power expense, and will be refunded to SCE's ratepayers through the ERRA over the next 12 months and the remaining $10 million was
used to offset SCE's incurred legal costs. Additional settlement payments totaling approximately $134 million are due from El Paso
over a 20-year period. Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement allocated to
SCE in proportion to SCE's share of the CDWR's power charge revenue requirement.
On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and 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. On August 2, 2004, SCE received its approximately $37 million share of the refunds and other
payments under the Williams settlement.
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. (collectively, Dynegy). The settlement terms provide for refunds and
other payments totaling $285 million, with a proposed allocation to SCE of approximately $40 million. The Dynegy settlement terms
were submitted to the FERC for its approval on June 28, 2004. The FERC is expected to act on the Dynegy settlement before year-end
2004.
On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy Corporation and a
number of its affiliates. The settlement terms agreed to with the Duke parties provide for refunds and other payments totaling in
excess of $200 million, with a proposed allocation to SCE of approximately $45 million. The Duke settlement was submitted to the
FERC for its approval on October 1, 2004.
The exact manner in which net settlement proceeds under the Duke, Williams and Dynegy settlements will be refunded to customers is
expected to be the subject of a future CPUC determination. Any settlement amounts received have been deferred, pending a final
decision.
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. As of September 30, 2004, the bark beetle CEMA had a balance of $106 million and the fire-related CEMA
had a balance of $11 million. SCE submitted an advice filing with the CPUC in June 2004 to recover approximately $18 million in bark
beetle-related
Page 49
costs incurred in 2003. On September 23, 2004, the CPUC issued a resolution on SCE's advice filing granting recovery of the majority
of the $18 million bark beetle related costs recorded in 2003. The CPUC disallowed approximately $500,000 in recorded costs based on
the assertion that such costs were already recovered in rates under SCE's routine line-clearing program. The CPUC also modified its
original authorization and now requires future bark beetle CEMA filings to be applications instead of advice letters. SCE estimates
that it will spend approximately $135 million on this project in 2004 and approximately $45 million in 2005. SCE will submit an
application to recover the 2004 costs in 2005. SCE expects to submit an application with the CPUC in the fourth quarter of 2004 to
seek recovery of the fire-related costs.
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 companies filed similar challenges, and all cases were transferred to the
First District Court of Appeal in San Francisco.
On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities' and their holding
companies' challenges to both CPUC decisions. The Court of Appeal held that the CPUC has limited jurisdiction to enforce in a CPUC
proceeding the conditions agreed to by holding companies incident to their being granted authority to assume ownership of a
CPUC-regulated utility. The Court of Appeal held that the CPUC's decision interpreting the first priority requirement was not
reviewable because the CPUC had not made any ruling that any holding company had violated the first priority requirement. However,
the Court of Appeal suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of violation and the
underlying interpretation of the first priority requirement itself. On June 30, 2004, Edison International and the other utility
holding companies filed with the California Supreme Court a petition for review of the Court of Appeal decision as to jurisdiction
over holding companies, but they and the utilities did not file a challenge to the decision as to the first priority issue. On
September 1, 2004, the California Supreme Court denied the petition for review. The Court of Appeal's decision, as to jurisdiction,
is now final.
The original order instituting the investigation into whether the utilities and their holding companies have complied with CPUC
decisions and applicable statutes remains in effect, and the CPUC could initiate
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further proceedings as to any of the issues mentioned in the first paragraph above. It is uncertain whether or when the CPUC would
do so.
Investigations Regarding Performance Incentive Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties based on its
performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system
reliability.
SCE has been conducting investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings
of misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own
proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer
satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose
additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of
refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 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 recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE
also anticipated that it could be eligible for customer satisfaction rewards of about $10 million for 2003.
SCE has been conducting an internal investigation and keeping the CPUC informed of its progress. On June 25, 2004, SCE submitted to
the CPUC a PBR customer satisfaction investigation report, which concluded that employees in the design organization of the
transmission and distribution business unit deliberately altered customer contact information in order to affect the results of
customer satisfaction surveys. At least 36 design organization personnel engaged in deliberate misconduct including alteration of
customer information before the data were transmitted to the independent survey company. Because of the apparent scope of the
misconduct, SCE proposed to refund to ratepayers all of the $12 million in PBR rewards that are attributable to the design
organization's portion of the customer satisfaction rewards for the entire PBR period (1997-2003). In addition, during its
investigation, SCE determined that it could not confirm the integrity of the method used for obtaining customer satisfaction survey
data for meter reading. Thus, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards
associated with meter reading. SCE expects that it would refund approximately half of the total of $14 million from customer
satisfaction rewards previously received. SCE believes it is likely that it could deal with the approximate remaining half by
adjustments to the pending and to-be-requested rewards noted above.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory
personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls
over data collection and processing.
The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data requests to SCE and has
requested an opportunity to interview a number of SCE employees in the design organization. SCE is in the process of responding to
those requests.
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Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting an investigation into the accuracy of
SCE's employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to
determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has
received $20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, may be entitled to an
additional $15 million for 2001 through 2003.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies
certain findings concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. Under the PBR
mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident rate, which included two equally
weighted measures: OSHA recordable incidents and first aid incidents. The major issue disclosed in the investigative findings to
the CPUC was that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid
incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these inaccuracies
did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism for any year before 2005,
and it return to ratepayers the $20 million it has already received. SCE has also proposed to withdraw the pending rewards for the
2001-2003 time frames.
SCE is taking other remedial action to address the issues identified, including revising its organizational structure and overall
program for environmental, health and safety compliance. Additional actions, including disciplinary action against specific
employees identified as having committed wrongdoing, may result once the entire investigation is completed, which is expected by the
end of November 2004.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation into the third PBR
metric, system reliability. Since the inception of PBR payments in 1997, SCE has received $8 million in rewards and has applied for
an additional $5 million reward based on frequency of outage data for 2001. For 2003, SCE's data would result in a penalty of
$5 million which has not yet been assessed.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC that overall, the reliability reporting
system is working well.
SCE: OTHER DEVELOPMENTS
Electric and Magnetic Fields
As discussed in the "Electric and Magnetic Fields" disclosure in the year-ended 2003 MD&A, certain issues have been raised regarding
electric and magnetic fields that naturally result from the generation, transmission, distribution and use of electricity. On
August 19, 2004, the CPUC issued an order instituting a rulemaking to update the CPUC's policies and procedures related to
electromagnetic fields emanating from regulated utility facilities. Comments to clarify the issues to be addressed in the proceeding
are due by December 31, 2004. SCE cannot predict with certainty the outcome of this proceeding.
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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 United States 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 D.C. District Court subsequently issued a scheduling order that imposed a
December 31, 2004 discovery cut-off. Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay of
the action to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave. The
facilitated negotiations are currently set to commence on November 8, 2004. The stay granted by the D.C. District Court is scheduled
to expire on February 5, 2005.
The United States Court of Appeals for the D.C. Circuit, 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 D.C. Circuit Court decision. Both petitions were denied on March 9, 2004. On
March 16, 2004, the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004. As a result of the status conference discussion, the Court of Federal Claims
has ordered the Navajo Nation and the Government to brief the remaining issues following remand. Peabody's motion to intervene as a
party in the remanded Court of Federal Claims case was denied.
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.
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MISSION ENERGY HOLDING COMPANY
MEHC: LIQUIDITY
Introduction
MEHC's liquidity discussion is organized in the following sections:
o MEHC (parent)'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 (parent)'s Liquidity
MEHC (parent)'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
Edison International. See "EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Agreement." Dividends from EME are
limited based on its earnings and cash flow, business and tax considerations and restrictions imposed by applicable law.
At September 30, 2004, MEHC (parent) had cash and cash equivalents of $5 million (excluding amounts held by EME and its
subsidiaries). On April 5, 2004, the lenders under MEHC (parent)'s $385 million term loan due in 2006 exercised their right to
require MEHC (parent) to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan
Put-Option"). The $100 million principal, plus interest, was paid on July 2, 2004.
Dividends to MEHC (parent)
In July and October 2004, EME made dividend payments of $69 million and $5 million, respectively, to MEHC. These payments were used
together with cash on hand to meet the Term Loan Put-Option payment discussed above.
EME amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were
implemented in early 2001 during the California energy crisis, which had included restrictions on dividends.
EME's Liquidity
At September 30, 2004, EME and its subsidiaries had cash and cash equivalents of $1.2 billion, including $739 million received from
the sale of Contact Energy, and EME had available the full amount of borrowing capacity under a $98 million corporate credit
facility. On October 5, 2004, EME repaid $600 million of the $800 million secured loan at Mission Energy Holdings International,
Inc. with the majority of the proceeds received from the sale of Contact Energy. EME's consolidated debt at September 30, 2004 was
$4.4 billion. In addition, EME's subsidiaries had $5.3 billion of long-term lease obligations that are due over periods ranging up
to 31 years.
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Key Financing Developments
EME Financing Developments
On April 27, 2004, EME replaced its $145 million corporate credit facility with a new $98 million secured corporate credit facility.
This credit facility matures on April 27, 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 distributions 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.
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, or Midwest Generation may
elect to repay, the notes on May 1, 2014 and on each one-year anniversary thereafter at 100% of their principal amount, plus accrued
and unpaid interest. Concurrent with the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority
senior secured term loan facility. The term loan has a final maturity of April 27, 2011 and bears interest at LIBOR plus 3.25% per
annum. Midwest Generation has agreed to repay $1,750,000 of the term loan on each quarterly payment date. Midwest Generation also
entered into a new five-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. As of September 30, 2004, Midwest Generation had no borrowings outstanding
under the working capital facility and had reimbursement obligations under a letter of credit for approximately $3 million that
expires in 2005. Midwest Generation used the proceeds of the notes issuance and the term loan to refinance $693 million of
indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been
guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease in
the amount of approximately $960 million.
Midwest Generation is permitted to use the new working capital facility and cash on hand to provide credit support (either through
loans or letters of credit) for forward contracts with third-party counterparties entered into by Edison Mission Marketing & Trading
on its behalf for capacity and energy generated from the Illinois plants. Utilization of this credit facility in support of such
forward contracts provides 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 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 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
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approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the
amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins
Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax)
due to termination of the lease and the planned decommissioning of the asset and disposition of excess inventory.
Following the termination of the Collins Station lease, Midwest Generation announced plans to permanently cease operations at the
Collins Station by December 31, 2004 and decommission the plant. On July 30, 2004, PJM accepted Midwest Generation's request to
cease operations at the Collins Station. PJM found that the decommissioning of the plant would not affect the operation or
reliability of the PJM markets. During the third quarter of 2004, EME reached an agreement with Exelon Generation Company LLC
(Exelon Generation)to terminate the power purchase agreement effective September 30, 2004 for the two units at the Collins Station
that remained under contract. As a result of the termination of the power purchase agreement, EME revised the estimated useful life
of the remaining plant assets to end on September 30, 2004 instead of December 31, 2004. Accordingly, EME recorded a pre-tax
impairment charge of $5 million during the third quarter of 2004. In October 2004, EME finalized plans to reduce the workforce in
Illinois and expects to recognize a $4 million pre-tax charge for exit costs during the fourth quarter of 2004.
In September 2004, EME completed an analysis of future competitiveness in the expanded PJM market place of its eight small peaking
units in Illinois. Based on this analysis, EME decided to decommission six of the eight small peaking units, subject to regulatory
review and approval. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less
than the book value of the units resulting in an impairment under an accounting standard for accounting for the impairment or the
disposal of long-lived assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million
(approximately $18 million after tax).
EME anticipates that the lease termination payment and decommissioning of the Collins Station and small peaking units will result in
substantial income tax deductions.
2004 Capital Expenditures
The estimated capital and construction expenditures of EME's subsidiaries for the final quarter of 2004 are $12 million. These
expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations. During
the third quarter of 2004, Midwest Generation decided to return Will County Units 1 and 2 to service. Operations at these units were
suspended in 2002, pending recovery of market prices. As part of returning these units to service, Midwest Generation expects to
install environmental improvements of approximately $10 million by June 30, 2005. In addition, Homer City plans to spend
approximately $17 million related to environmental improvements prior to the summer of 2005.
Page 56
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 B1 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
- ----------------------------------------------------------------------------------
On August 6, 2004, Moody's raised EME's credit rating to B1 from B2. 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. 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.
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.
Edison Mission Marketing & Trading has provided credit for the benefit of counterparties in the form of cash and letters of credit
($93 million as of September 30, 2004) for EME's price risk management and domestic trading activities (including Midwest Generation
and Homer City) related to accounts payable and unrealized losses. 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)22 million
have been issued as of September 30, 2004.
With the remaining power purchase agreements with Exelon Generation expiring on December 31, 2004, EME expects to generate higher
merchant generation in 2005 which will increase the potential for margin and collateral requirements. Changes in forward market
prices and the strategies adopted for merchant generation could further increase the need for credit support for price risk
management activities related to these projects. EME estimates that total margin and collateral requirements to support price risk
management could increase to approximately $400 million if 50% of merchant generation from the Illinois plants and Homer City
facilities was sold forward for one year and power prices subsequently increased using common industry analytics. Midwest Generation
has cash on hand and a $200 million working capital facility that can be used to provide credit support for forward contracts entered
into on behalf of the Illinois plants. In addition, EME has cash on hand and a $98 million working capital facility that can be used
to provide credit support for its subsidiaries. See "--EME's Liquidity" for further discussion.
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
Page 57
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, through December 31, 2004. 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: Market Risk
Exposures--Commodity Price Risk-- Homer City Facilities."
EME's Liquidity as a Holding Company
Overview
At September 30, 2004, EME had corporate cash and cash equivalents of $84 million to meet liquidity needs. EME's corporate cash and
cash equivalents increased by $139 million subsequent to September 30, 2004 from the net cash received from the sale of Contact
Energy less the repayment of subsidiary indebtedness. See "--EME's Liquidity." EME had no borrowings outstanding or letters of
credit outstanding on the $98 million secured line of credit at September 30, 2004. 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 "--Intercompany Tax-Allocation Agreement."
EME's secured corporate credit facility provides credit available in the form of cash advances or letters of credit. 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). At September 30, 2004, EME met both these ratio tests.
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 distributions unless and until an event of default occurs under its corporate credit
facility.
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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 Nine Months Ended September 30, 2004 2003
-----------------------------------------------------------------------------------------------------------
Domestic Projects
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) $ 61 $ 102
Holding companies of other consolidated operating projects -- 1
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects) 80 74
Four Star Oil & Gas Company -- 15
Sunrise Power Company 5 66
Holding companies for Westside projects 13 20
Holding companies of other unconsolidated operating projects 1 5
-----------------------------------------------------------------------------------------------------------
Total Distributions from Domestic Projects $ 160 $ 283
International Projects (Mission Energy Holdings International)
Distributions from Consolidated Operating Projects:
First Hydro Holdings (First Hydro project) $ 29 $ 18
Loy Yang B 12 22
Doga -- 18
Contact Energy 50 16
Valley Power -- 8
Kwinana(1) 4 4
Holding companies of other consolidated operating projects 10 --
-----------------------------------------------------------------------------------------------------------
Distributions from Unconsolidated Operating Projects:
ISAB Energy 24 1
IVPC4 (Italian Wind project) 18 8
Derwent 1 1
Doga 15 --
EcoElectrica 9 --
Paiton -- 9
Tri Energy 2 --
Holding companies of other unconsolidated operating projects 4 2
-----------------------------------------------------------------------------------------------------------
Total Distributions from International Projects $ 178 $ 107
-----------------------------------------------------------------------------------------------------------
Total Distributions $ 338 $ 390
-----------------------------------------------------------------------------------------------------------
--------------
(1) Distributions for the nine months ended September 30, 2004 reflect distributions made during the first quarter of
2004. Effective March 31, 2004, the Kwinana project was deconsolidated due to the adoption of a new accounting
interpretation for variable interest entities.
Intercompany Tax-Allocation Agreement
MEHC (parent) 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. MEHC (parent) 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 (parent) have historically received tax-allocation payments related to domestic net operating losses
incurred by EME and MEHC (parent). The right of MEHC (parent) and EME to receive and the amount and timing of tax-allocation
payments is dependent on the inclusion of
Page 59
MEHC (parent) 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 (parent), EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures
regarding allocation of state taxes. MEHC (parent) 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 (parent)'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 (parent) and EME may be obligated during periods they generate taxable income to
make payments under the tax-allocation agreements.
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.
Key Ratios of EME's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EME's principal subsidiaries for the twelve months ended September 30, 2004:
Subsidiary Financial Ratio Covenant Actual
- --------------------------------------------------------------------------------------------------------------
Midwest Generation, LLC Interest Coverage Greater than or 2.39 to 1(1)
(Illinois plants) Ratio equal to 1.25 to 1
Midwest Generation, LLC Secured Leverage Less than or 5.94 to 1
(Illinois plants) Ratio equal to 8.75 to 1
EME Homer City Senior Rent Service Greater than 1.7 to 1 2.73 to 1
Generation L.P. Coverage Ratio
(Homer City facilities)
Edison Mission Energy Debt Service Greater than or 2.54 to 1
Funding Corp. Coverage Ratio equal to 1.25 to 1
(Big 4 Projects)
Mission Energy Holdings Interest Coverage Greater than or 3.92 to 1(2)
International Ratio equal to 1.3 to 1
- --------------------------------------------------------------------------------------------------------------
--------------
(1) Interest coverage ratio was computed on a pro forma basis assuming the credit facility had been
in existence for a twelve-month period.
(2) For more information about this interest coverage ratio, see "--Dividend Restrictions in Major Financings--Mission Energy
Holdings International Interest Coverage Ratio" below.
Page 60
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 "Dividend Restrictions
in Major Financings" in the year-ended 2003 MD&A.
Midwest Generation Financing Restrictions on Distributions
Midwest Generation is bound by the covenants in its credit facility and indenture as well as certain covenants under the
Powerton-Joliet lease documents with respect to Midwest Generation making payments under the leases. 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 Agreement
In order for Midwest Generation to make a distribution, it must be in compliance with covenants specified under its credit agreement.
Compliance with the covenants in its credit agreement 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).
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 since April 27, 2004 may not exceed the sum of (1) 75% of excess cash flow (as defined in the credit agreement) generated
since that date, plus (2) 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
(1) is available for such payments. With the remaining 25% of excess cash flow, Midwest Generation must offer to prepay the term
loan to the lenders. Each of the lenders may, at its option, decline such prepayment with respect to its pro rata share of the term
loan. If Midwest Generation is rated investment grade, the aggregate amount of distributions made by Midwest Generation may equal
but not exceed 100% of excess cash flow generated since becoming investment grade plus 75% of excess cash flow generated during the
period between April 27, 2004 and the date immediately prior to becoming investment grade.
Excess cash flow was $117 million for the period between April 27, 2004 and September 30, 2004. At September 30, 2004, Midwest
Generation met both of the covenant requirements described above under the credit agreement and made a distribution of $88 million in
October 2004. As required under the credit agreement, Midwest Generation made an offer to the lenders to prepay $29 million of the
term loan, of which $5 million was accepted by certain lenders and repaid on October 20, 2004. The
Page 61
remaining $24 million of excess cash flow not repaid will be retained by Midwest Generation as working capital or used to make a
voluntary prepayment at a later date, as provided under the credit agreement.
Covenants in Indenture
Midwest Generation's indenture contains restrictions on its ability to make a distribution substantially similar to those in the
credit agreement. Failure to achieve the conditions required for distributions will not result in a default under the indenture, 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 maintain a minimum interest
coverage ratio of 1.30 to 1 beginning March 2004 for the trailing twelve-month period.
The following table sets forth the major components of the interest coverage ratio for the twelve months ended September 30, 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:
September 30, 2004 December 31, 2003
Pro Forma Pro Pro Forma Pro
Actual Adjustment(1) Forma Actual Adjustment(1) Forma
- -------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations
Historical distributions from
international projects $ 237 $ -- $ 237 $ 158 $ -- $ 158
Other fees and cash payments
considered distributions under
the term loan 16 -- 16 20 -- 20
Administrative and general
expenses (2) -- (2) (2) -- (2)
- -------------------------------------------------------------------------------------------------------------------
Total Funds Flow from Operations $ 251 $ -- $ 251 $ 176 $ -- $ 176
- -------------------------------------------------------------------------------------------------------------------
Term Loan Interest Expense $ 48 $ 16 $ 64 $ 4 $ 60 $ 64
- -------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 3.92 2.75
- -------------------------------------------------------------------------------------------------------------------
--------------
(1) 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.
MEHC's Interest Coverage Ratio
The following details with respect to MEHC's interest coverage ratio are provided as an aid to understanding the computations set
forth in the indenture governing MEHC (parent)'s senior secured notes. This information is not intended to measure the financial
performance of MEHC and, accordingly, should not be read in lieu of the financial information set forth in Edison International's
consolidated
Page 62
financial statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture
and are not the same as would be determined in accordance with generally accepted accounting principles.
MEHC's interest coverage ratio is comprised of interest income and expense related to its holding company activities and the
consolidated financial information of EME. The following table sets forth MEHC's interest coverage ratio for the twelve months ended
September 30, 2004 and the year ended December 31, 2003:
September 30, December 31,
In millions 2004 2003
------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants(3) $ 236 $ 242
Homer City 104 153
First Hydro 55 (8)
Other consolidated operating projects 183 165
Price risk management and energy trading (14) 11
Distributions from unconsolidated Big 4 projects 104 98
Distributions from other unconsolidated operating
projects 142 178
Interest income 5 4
Interest expense at Mission Energy Holdings International (52) --
Operating expenses (163) (144)
------------------------------------------------------------------------------------------------------------------
Total EME funds flow from operations $ 600 $ 699
Operating cash flow from unrestricted subsidiaries -- (2)
Funds flow from operations of projects sold (57) (1)
MEHC (parent) 1 1
------------------------------------------------------------------------------------------------------------------
Total funds flow from operations $ 544 $ 697
Interest Expense:
EME $ 268 $ 286
EME - affiliate debt 1 1
MEHC (parent) interest expense 163 160
Interest savings on projects sold (54) --
------------------------------------------------------------------------------------------------------------------
Total interest expense $ 378 $ 447
------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 1.44 1.56
------------------------------------------------------------------------------------------------------------------
--------------
(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 or EME is not the primary beneficiary under a new
accounting interpretation for variable interest entities.
(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 on Distributions," for a description of
restrictions applicable to future periods.
Page 63
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC
(parent)'s senior secured notes and the credit agreement governing the term loan. The interest coverage ratio prohibits MEHC
(parent), 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.
MEHC: 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 "Current Developments--MEHC: Current Developments" and
"MEHC: Liquidity--EME's Credit Ratings" for 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 Interest Rate Risk
o Foreign Exchange Rate Risk
o Fair Value of Financial Instruments
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 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;
Page 64
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.
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 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, including PJM since May 1, 2004.
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
Status of the Exelon Generation Power Purchase Agreements
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. The power purchase agreement for the Collins Station was terminated effective
September 30, 2004; the other two contracts (for coal-fired generation and peaking units) expire in December 2004. The capacity
payments provide the units under contract with revenue for fixed charges, and the energy payments compensate those units for all, or
a portion of, variable costs of production.
Approximately 57% and 68% of the energy and capacity sales from the Illinois plants in the first nine months 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. For the
nine months ended September 30, 2004, 3,859 MW of Midwest Generation's generating capacity (2,383 MW related to its coal-fired
generation units, 1,084 MW related to its Collins Station, and 392 MW related to its peaking units) were subject to power purchase
agreements with Exelon Generation. Following the termination of the Collins Station power purchase agreement, 2,775 MW will be
subject to power purchase agreements with Exelon Generation during the fourth quarter of 2004. 2004 is the final contract year under
these power purchase agreements.
Merchant Sales
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 sales. These arrangements generally have a term of two years or less. Thus, EME is subject to
market
Page 65
risks related to the price of energy and capacity from those units. Capacity prices for merchant energy sales are, and are expected
in the near term to remain, substantially less than those Midwest Generation currently receives under the 1999 power-purchase
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. 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.
Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants
were direct "wholesale customers" and broker-arranged "over-the-counter customers." The most liquid over-the-counter markets in the
Midwest region have historically been for sales into the control area of 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 ComEd" and
"Into AEP" are bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic proximity,
"Into ComEd" was the primary market for Midwest Generation.
The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" for the first four months
of 2004.
Into ComEd*
---------------------------------------------------------
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr
-----------------------------------------------------------------------------------------
January $ 43.30 $ 15.18 $ 27.88
February 43.05 18.85 29.98
March 40.38 21.15 30.66
April 39.50 16.76 27.88
-----------------------------------------------------------------------------------------
Four-Month Average $ 41.56 $ 17.99 $ 29.10
-----------------------------------------------------------------------------------------
--------------
(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 "Into
ComEd" delivery points.
Following Commonwealth Edison's joining PJM on 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, into the expanded PJM, the primary
market currently available to Midwest Generation, replaced sales previously made as bilateral sales and spot sales "Into ComEd." See
"MEHC: Other Development--PJM Regulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth
Edison's joining 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.
Page 66
The following table depicts the historical average market prices for energy per megawatt-hour since joining PJM on May 1, 2004.
Northern
Historical Energy Prices Illinois Hub
----------------------------------------------------
May $ 34.05
June 28.58
July 30.92
August 26.31
September 27.98
----------------------------------------------------
Five-Month Average $ 29.57
----------------------------------------------------
--------------
* Energy prices calculated at the Northern Illinois Hub delivery point using
hourly real-time prices as published by PJM. There is no comparison for the
same months in 2003.
Forward market prices in the Northern Illinois Hub 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.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois
Hub at September 30, 2004:
24-Hour Northern
Illinois Hub
2004 Forward Energy Prices*
---------------------------------------------------------------------
October $ 25.86
November 27.52
December 30.49
2005 Calendar "strip"(1) $ 32.82
---------------------------------------------------------------------
--------------
(1) Market price for energy purchases for the entire calendar year, as quoted for sales into the
Northern Illinois Hub.
* Energy prices were determined by obtaining broker quotes and other public sources for the Northern
Illinois Hub delivery point.
Midwest Generation intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. The
following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at
September 30, 2004:
2004 2005 2006
---------------------------------------------------------------------------------
Megawatt hours 3,250,276 4,659,585 438,000
Average price/MWhr $ 27.87 $ 38.14 $ 31.50
---------------------------------------------------------------------------------
To the extent Midwest Generation does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and
benefits of spot market price movements. The extent to which Midwest Generation will hedge its market price risk through forward
over-the-counter sales depends on several factors. First, Midwest Generation will evaluate over-the-counter market prices to
determine whether
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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. Midwest Generation is permitted to use its new
working capital facility and cash on hand to provide credit support for forward contracts entered into by Edison Mission Marketing &
Trading for capacity and energy generation by Midwest Generation under an intercompany energy services agreement between Midwest
Generation and Edison Mission Marketing & Trading. Utilization of this credit facility in support of such forward contracts is
expected to provide additional liquidity support for implementation of Midwest Generation's contracting strategy for the Illinois
plants. 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
units released from contract by Exelon Generation 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.
Effective May 1, 2004, the transmission system of Commonwealth Edison became integrated into PJM. Over EME's and Midwest
Generation's objections, such integration was allowed to occur in advance of the integration of American Electric Power into PJM,
which had resulted in the creation of an islanded market within PJM limited to the service territory of Commonwealth Edison.
Concerns about the islanded market of Commonwealth Edison became moot on October 1, 2004, when American Electric Power was integrated
into PJM. In general, 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. Given the recent integration of American Electric Power into PJM, such changes, if any, are not
expected to have a material effect on Midwest Generation. See "--MEHC: Other Development--PJM Regulatory Matters" for further
discussion.
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.
EME is continuing to monitor the activities at the FERC related to the expansion of PJM and to advocate regulatory positions that
promote efficient and fair markets in which the Illinois plants compete.
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.
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The following table depicts the average market prices per megawatt-hour in PJM during the first nine months 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
April 43.01 35.35
May 44.68 32.29
June 36.72 27.26
July 40.09 36.55
August 34.76 39.27
September 40.62 28.71
----------------------------------------------------
Nine-Month Average $ 41.97 $ 36.55
----------------------------------------------------
--------------
* 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 nine
months of 2004 were higher than the average historical market prices during the first nine 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, can
cause the price of a specific delivery point to be raised or lowered relative to other locations depending on how the point is
impacted by transmission constraints. During the past 12 months, transmission congestion in PJM has resulted in prices at the PJM
West Hub (the primary trading hub in PJM) being higher than those at Homer City by an average of 3%.
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
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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 financial transmission rights in PJM, and may continue
to do so in the future. A financial 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 financial transmission
rights alone or in combination with forward contracts to manage the risks associated with changes in prices within the PJM market.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at
September 30, 2004:
24-Hour PJM West Hub
2004 Forward Energy Prices*
-------------------------------------------------------------
October 39.23
November 41.40
December 45.15
2005 Calendar "strip"(1) $ 46.19
-------------------------------------------------------------
--------------
(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 Hub are generally higher than the prices at the Homer City
busbar.
The following table summarizes Homer City's hedge position at September 30, 2004:
2004 2005
------------------------------------------------------------
Megawatt hours 2,287,200 6,336,000
Average price/MWhr $ 36.66 $ 44.48
------------------------------------------------------------
The average price/MWhr for Homer City's hedge position is based on PJM West Hub. Energy prices at the PJM West Hub have averaged 3%
higher than energy prices at Homer City during the past twelve months. A discussion of the basis risk between PJM West Hub and Homer
City is set forth above.
Market conditions for the sale of capacity and energy from the Homer City facilities affect the ability of EME's subsidiary, EME
Homer City, to meet its obligations under the Homer City sale-leaseback documents. 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
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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. 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 fell significantly between 2002 and 2003. The reduction was driven principally by surplus
generating capacity and increased competition. During 2003, prices were more volatile, and in the second half of 2004, prices for
baseload electricity have risen in line with increases in the cost of gas for generation. The increases have been accompanied during
2004 by a considerable narrowing in the peak/off peak differentials. 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.
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 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 nonperforming counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the
risk of nonpayment 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.
Page 71
EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (1) 60 days of accounts
receivable, (2) current fair value of open positions, and (3) 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 September 30, 2004, the credit ratings of EME's counterparties were as follows:
September 30,
In millions 2004
- -----------------------------------------------------------------------------
S&P Credit Rating
A or higher $ 49
A- 26
BBB+ 113
BBB 21
BBB- 10
Below investment grade 12
- -----------------------------------------------------------------------------
Total $ 231
- -----------------------------------------------------------------------------
Exelon Generation accounted for 41% and 46% of nonutility power generation revenue for the first nine months of 2004 and 2003,
respectively. The percentage is less in 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.
Approximately 15% of nonutility power generation revenue for the first nine months of 2004 were to BP Energy Company, a third-party
customer. (An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.)
Interest Rate Risk
MEHC (parent) mitigated the risk of interest rate fluctuations associated with the $385 million term loan ($100 million due July 2,
2004 and $285 million due 2006) by arranging for variable rate financing with interest rate swaps. MEHC (parent) entered into swaps
that covered interest accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to July 2, 2004. MEHC (parent) has not entered
into any new interest rate swaps associated with the $285 million portion of the term loan for periods beyond July 2, 2004.
Interest rate changes affect the cost of capital needed to operate EME's projects. EME has mitigated the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or
other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations
are subject to interest rate risk. The fair market value of MEHC's total long-term obligations (including current portion) was
$6.1 billion at September 30, 2004, compared to the carrying value of $5.5 billion. The fair market value of MEHC (parent)'s total
long-term obligations was $1.3 billion at September 30, 2004, compared to the carrying value of $1.1 billion.
Page 72
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. As
discussed in "Current Developments--MEHC: Current Developments," EME entered into sales agreements for its international operations.
Fair Value of Financial Instruments
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used in MEHC's continuing operations
for purposes other than trading by risk category and instrument type:
September 30, December 31,
In millions 2004 2003
-----------------------------------------------------------------------
Commodity price:
Electricity $ (49) $ (7)
Interest rate:
Interest rate swaps $ -- $ (5)
-----------------------------------------------------------------------
In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions
based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts
takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The
following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management
assets and liabilities as of September 30, 2004:
Total Maturity Maturity Maturity Maturity
Fair Less than 1 to 3 4 to 5 Greater than
In millions Value 1 year years years 5 years
-----------------------------------------------------------------------------------------------------
Prices actively quoted $ (49) $ (58) $ 9 $ -- $ --
-----------------------------------------------------------------------------------------------------
MEHC: OTHER DEVELOPMENT
PJM Regulatory Matters
Commonwealth Edison's application to join PJM was approved by the FERC on April 27, 2004, with an effective date of May 1, 2004. EME
had protested such action before the FERC because the integration of Commonwealth Edison into PJM in advance of American Electric
Power (AEP) created an isolated
Page 73
market within PJM limited to the service territory of Commonwealth Edison. The integration of AEP into PJM had been delayed by the
actions of state regulatory authorities in Virginia and Kentucky. However, the issues raised in the Kentucky proceedings were
resolved in June 2004 and the Virginia case was settled in August 2004, which permitted the integration of AEP to take place without
incident on October 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 AEP) and the Midwest Independent System Operator (MISO). The effect of this order was that the so-called
rate pancaking was not eliminated prior to the integration of Commonwealth Edison and AEP 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. 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.
The transmission owners and other stakeholder interests in the region met on several occasions from June through early September
2004, attempting to reach consensus on an acceptable long-term rate structure for the combined PJM/MISO footprint. A consensus among
all affected parties could not be reached; however, two competing proposals for a long-term rate structure have emerged from such
discussions and both were filed with the FERC on October 1, 2004. Neither of those plans would impose transmission costs on system
users other than load-serving entities. However, the FERC has also initiated an investigation under Section 206 of the Federal Power
Act, which would permit the agency to adopt a structure different from those which have been proposed by the parties. In its order
initiating the investigation, the FERC reiterated its previous statement that it would act on such a structure by December 1, 2004.
Until through and out rates are eliminated, EME will continue to have to pay transmission charges for power sold for delivery to
customers within the MISO. In addition, sales to customers outside of the MISO and PJM will continue to be subject to the through
and out rates applicable to such transactions.
On July 27, 2004, AEP reached a settlement with staff of the Virginia State Corporation Commission that allowed AEP to transfer
control of its transmission lines in the state to PJM. The settlement eliminated the need for the FERC to act to ensure that AEP was
able to enter PJM on October 1, 2004, the target date set by both AEP and PJM. Such integration took place on October 1, 2004, as
previously noted.
Given the removal of the uncertainties regarding the market structure issues discussed previously, the direct impact on Midwest
Generation of the above-described matters will 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 prior to the anticipated elimination of such rates
between PJM and the MISO on December 1, 2004.
Page 74
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. At September 30, 2004, Edison Capital had cash and cash equivalents of
$278 million. This 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. During the third
quarter, Edison Capital reached agreements to place investments in a series of wind farms located in Minnesota. To the extent that
certain funding conditions are satisfied, Edison Capital has unfunded current and long-term commitments of $84 million for energy and
infrastructure investments as of September 30, 2004. Edison Capital also repurchased the limited partnership interests of seven
previously syndicated affordable housing projects for approximately $27 million of funded and unfunded commitments. Edison Capital
is evaluating its capital structure, the potential for additional borrowings and potentially making dividend payments to Edison
International.
At September 30, 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 Agreement
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:
Liquidity--EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Agreement" for additional information regarding these
arrangements. Edison Capital received $9 million in tax-allocation payments from Edison International during the first nine months
of 2004. The amount received is net of payments made to Edison International. (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.
EDISON CAPITAL: OTHER DEVELOPMENT
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. Among the issues raised by the IRS was Edison Capital's deferral of income
taxes associated with the EPZ and Dutch electric locomotive leases. In addition, the IRS is examining the tax returns for Edison
International, which include Edison Capital, for the years 1997 through 1999. In conjunction with this examination, Edison Capital
has received notices of proposed adjustments to Edison International's tax liability. See "Other Developments--Federal Income Taxes"
for further discussion of these matters.
Page 75
EDISON INTERNATIONAL (PARENT)
EDISON INTERNATIONAL (PARENT): LIQUIDITY ISSUES
The parent company's liquidity and its ability to pay interest, dividends to common shareholders, debt principal, and operating
expenses 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 $325 million of EIX Trust II 8.6% quarterly income preferred securities, Series B, to be redeemed November 30, 2004. Edison
International's management has also stated that it is considering redeeming the remaining quarterly income preferred securities
outstanding by the end of 2004, however a final decision has not yet been made;
o $618 million of 6-7/8% notes due September 15, 2004, of which approximately $47 million was repurchased during January
through April 2004, and the remaining balance of $571 million was paid in September 2004;
o Dividends to common shareholders. The Board of Directors of Edison International declared 20(cent)-per-share common stock
dividends in the first, second and third quarters of 2004. Dividend payments of $65 million were made on each of April 30, 2004,
August 2, 2004, and November 1, 2004, respectively. Edison International's management has announced that it intends to recommend
to its Board of Directors an increase in the annual dividend from $0.80 per share in 2004 to $1.00 per share in 2005;
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); and
o General operating expenses.
Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand and dividends from
its subsidiaries. At September 30, 2004, Edison International (parent) had approximately $784 million 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. SCE paid cash dividends of $300 million, $145 million, and $150 million to Edison International on
March 30, 2004, May 21, 2004, and September 23, 2004, respectively.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At September 30, 2004, its interest
coverage ratio was 1.44 to 1. See "MEHC: Liquidity--MEHC's Interest
Page 76
Coverage Ratio." In addition, MEHC's certificate of incorporation, senior secured note indenture, and term loan credit agreement
contain restrictions on MEHC's ability to declare or pay dividends or distributions (other than dividends payable solely in MEHC's
common stock). These restrictions require the unanimous approval of MEHC's Board of Directors, including its independent director,
before it can declare or pay dividends or distributions, as long as any indebtedness is outstanding under the indenture or credit
agreement. MEHC has not declared or paid a dividend in 2004 to Edison International. MEHC's ability to pay dividends is dependent
on EME's ability to pay dividends to MEHC (parent). EME and its subsidiaries have certain dividend restrictions as discussed in the
"MEHC: Liquidity" section. In July and October 2004, EME made dividend payments of $69 million and $5 million, respectively, to MEHC
(parent).
Edison International's investment in MEHC, through a wholly owned subsidiary, as of September 30, 2004, was $827 million. MEHC's
(parent) investment in EME, as of September 30, 2004, was approximately $1.9 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
at that time about Edison Mission Midwest Holdings' ability to repay or refinance Edison Mission Midwest Holdings' $693 million of
debt due in December 2004 raised 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. See
"MEHC: Liquidity--Key Financing Developments" and "Current Development--MEHC: Current Developments--Disposition of EME's International
Operations" 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 $160 million. Edison Capital has not declared or paid a
dividend to Edison International in 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.
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. Among the issues raised by the IRS was Edison Capital's deferral of income taxes associated with the EPZ and
Dutch electric locomotive leases. In addition, the IRS is examining the tax returns for Edison International, which include Edison
Capital, for the years 1997 through 1999. In conjunction with this examination, Edison Capital has received notices of proposed
adjustments to Edison International's tax liability. See "Other Developments--Federal Income Taxes" for further discussion of these
matters.
Page 77
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 acquisition and
dispositions, critical accounting policies, new accounting principles, commitments and guarantees, 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
Edison International recorded consolidated earnings of $813 million or $2.49 per share for the three-month period ended September 30,
2004, compared with consolidated earnings of $544 million or $1.67 per share for the three-month period ended September 30, 2003.
The increase is primarily due to net benefits related to the sale of MEHC's interest in Contact Energy and the planned sale of its
international projects, partially offset by reduced earnings from MEHC's Illinois and Homer City projects and lower net regulatory
items at SCE in 2004. Beginning in the third quarter of 2004, MEHC reclassified the results of its international projects to
discontinued operations. This reclassification included a $126 million after-tax net gain on the sale of its interest in Contact
Energy and a deferred tax benefit of $327 million related to the planned sale of its remaining international projects. The deferred
tax benefit was recorded to recognize the higher tax basis of MEC International B.V. over the related book basis, as required by
accounting rules applicable to discontinued operations.
Edison International recorded consolidated earnings of $537 million, or $1.65 per share, for the nine-month period ending September
30, 2004, compared with $624 million, or $1.92 per share, for the same period last year.
Edison International's 2004 earnings included 48(cent)per share at SCE from regulatory items primarily related to its 2003 GRC decision,
a $1.00 per share deferred tax benefit at MEHC related to the planned sale of its remaining international projects, the net gain on
the sale of MEHC's interest in Contact Energy of 39(cent)per share, a charge of $1.81 per share related to the termination of the Collins
Facility lease, asset impairment charges totaling 5(cent)per share for MEHC's Midwest Generation peaking units, and the gain on the sale
of MEHC's interest in Four Star Oil & Gas Company of 9(cent)per share. Edison International's 2003 earnings include 58(cent)per share at SCE
from various positive regulatory items, discontinued operations along with a gain on sale from SCE's pipeline business of 15(cent) per
share, a charge of 47(cent)per share at MEHC related to the impairment of eight small peaking plants in Illinois and the Gordonsville
facility, and a 3(cent)-per-share charge for a change in accounting principles at MEHC related to asset retirement obligations.
Excluding the above items, Edison International's earnings were $1.55 per share for the nine-month period ending September 30, 2004
compared with $1.69 per share for the same period last year. Most of the decrease reflects the expiration of SCE's incentive
mechanism for the San Onofre nuclear plant, lower earnings at MEHC's Homer City facility, and the absence of earnings from MEHC's
interest in the Four Star Oil & Gas Company, which was sold in the first quarter of 2004. The decrease was partially offset by
higher authorized revenue at SCE and improved operating performance at MEHC's international projects.
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The table below presents Edison International's earnings (loss) and earnings (loss) per share for the three- and nine-month periods
ended September 30, 2004 and 2003, and the relative contributions by its subsidiaries.
In millions, except per share amounts Earnings (Loss) Earnings (Loss) per Share
- -------------------------------------------------------------------------------------------------------------------
Three-Month Period Ended September 30, 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 259 $ 329 $ 0.79 $ 1.01
MEHC 59 136 0.18 0.42
Edison Capital 12 14 0.04 0.04
Edison International (parent) and other (17) (19) (0.05) (0.06)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 313 460 0.96 1.41
- -------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations - SCE -- 45 -- 0.14
Earnings from Discontinued Operations - MEHC 500 39 1.53 0.12
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 813 $ 544 $ 2.49 $ 1.67
- -------------------------------------------------------------------------------------------------------------------
In millions, except per share amounts Earnings (Loss) Earnings (Loss) per Share
- -------------------------------------------------------------------------------------------------------------------
Nine-Month Period Ended September 30, 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 600 $ 650 $ 1.84 $ 2.00
MEHC (623) (114) (1.91) (0.35)
Edison Capital 34 41 0.11 0.13
Edison International (parent) and other (52) (60) (0.17) (0.19)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings (Loss)
from Continuing Operations (41) 517 (0.13) 1.59
- -------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations - SCE -- 50 -- 0.15
Earnings from Discontinued Operations - MEHC 579 66 1.78 0.21
- -------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (1) (9) -- (0.03)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 537 $ 624 $ 1.65 $ 1.92
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
SCE's earnings from continuing operations were $259 million and $600 million for the three and nine months ended September 30, 2004,
respectively, compared with $329 million and $650 million for the three and nine months ended September 30, 2003, respectively. The
decrease in third quarter earnings primarily reflects a $79 million reduction in regulatory items. After adjusting for regulatory
items, higher revenue authorized in the utility's 2003 GRC for 2004 more than offset the expiration of the incentive mechanism for
the San Onofre nuclear plant and higher operating and maintenance expense. SCE's 2004 third quarter earnings included two positive
regulatory items totaling $64 million resulting from the implementation of the 2003 GRC decision that were partially offset by $14
million for the anticipated refund of employee safety awards previously recognized. Positive regulatory items that occurred in the
third quarter of 2003 included $79 million related to the CPUC decision on cost allocation and $50 million for the disposition of the
PROACT account. The decrease for the nine months ended September 30, 2004, compared with the year-earlier period, primarily reflects
the expiration of the incentive mechanism for San Onofre and the net effect of several regulatory items partially offset by higher
authorized revenue.
MEHC's income from continuing operations was $59 million in the third quarter of 2004 compared with $136 million in the third quarter
of 2003. The decrease was primarily due to Midwest Generation's lower capacity payments received under the Exelon power purchase
agreements, an $18 million impairment charge related to Midwest Generation's small peaking plants and reduced earnings from the Homer
City facilities due to lower generation and higher fuel costs related to the cost of emission
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allowances. The decrease in earnings was also due to the absence of earnings from Four Star Oil & Gas Company, compared with the
third quarter of 2003, due to the sale of MEHC's interest in that project in the first quarter of 2004. On an annual basis, MEHC's
earnings are seasonal with higher earnings expected during the summer months. MEHC had a loss from continuing operations of $623
million for the nine months ended September 30, 2004, compared with a loss of $114 million in the same period last year, primarily
due to the $608 million in charges for both the termination of the Collins lease and impairment of Illinois small peaking plants,
partially offset by the 2003 asset impairment charge of $150 million related to the Illinois small peaking plants.
Earnings in the third quarter of 2004 for Edison Capital were substantially unchanged from the same period last year. Edison
Capital's earnings for the nine-months ended September 30, 2004 were $34 million, down $7 million from the same period last year.
This decrease is primarily due to its maturing lease and housing portfolios which produce lower income.
The loss for Edison International (parent) and other decreased by $2 million and $8 million for the three and nine months ended
September 30, 2004, respectively, compared with the year-earlier periods, primarily due to lower net interest expense.
Operating Revenue
SCE's retail sales represented approximately 88% and 86% of electric utility revenue for the three- and nine-month periods ended
September 30, 2004, respectively, and approximately 93% for both the three- and nine-month periods ended September 30, 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 for both the three- and nine-month periods ended September 30, 2004, compared to the same periods
in 2003. The decreases were mainly due to the implementation of a CPUC-approved customer rate reduction plan effective August 1,
2003, 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) and the recognition of revenue in 2003 from a CPUC-authorized surcharge collected in 2002 used to
recover costs incurred in 2003. There was no surcharge revenue recognized in 2004. The three- and nine-month period decreases were
partially offset by the recognition of revenue resulting from the consolidation of SCE's variable interest entities on March 31, 2004
(see "Critical Accounting Policies" and "New Accounting Principles"), higher resale sales revenue due to a greater amount of excess
energy in 2004, as compared to 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. In addition, the decreases were partially offset by regulatory
adjustments resulting from the implementation of the 2003 GRC decision (see "SCE: Regulatory Matters--Transmission and
Distribution--2003 General Rate Case Proceeding" for further discussion). The nine-month period decrease was also partially offset by
an allocation adjustment for the CDWR energy purchases recorded in 2003.
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 $693 million and $1.9 billion for the three- and
nine-month periods ended September 30, 2004, compared to $541 million and $1.4 billion for the same periods in 2003.
Nonutility power generation revenue decreased in both the three- and nine-month periods ended September 30, 2004. The decreases were
mainly due to lower capacity revenue at EME's Illinois plants
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resulting from the reduction in megawatts contracted under power-purchase agreements, as well as reduced generation during off-peak
periods at EME's Homer City facilities resulting from temporary interruptions in coal deliveries under contracts with four fuel
suppliers. EME is currently seeking to secure the delivery of the coal shortfall under existing contracts with these fuel suppliers
and is reviewing these contracts to determine what further course of action, if any, should be undertaken. The nine-month period
decrease was also due to an unplanned outage at EME's Homer City facilities, partially offset by higher energy revenue at EME's
Illinois plants resulting from increased merchant generation at the coal plants released from their power-purchase agreement with
Exelon Generation and higher merchant energy prices.
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.
Financial services and other revenue increased in the nine-month period ended September 30, 2004, as compared to the same period in
2003, mainly due to the recognition of revenue resulting from the consolidation of Edison Capital's variable interest entities (see
"Critical Accounting Policies" and "New Accounting Principles").
Operating Expenses
Fuel expense increased in both the three- and nine-month periods ended September 30, 2004, as compared to the same periods in 2003,
primarily due to the consolidation of SCE's variable interest entities. The increases also reflect higher coal expense at EME's
Homer City facilities resulting from temporary interruptions in coal deliveries during the third quarter which caused EME to purchase
coal from alternative suppliers at spot prices which were substantially higher than the contract prices and higher fuel costs due to
higher sulfur emission costs. Partially offsetting the increases were lower fuel costs at EME's Collins Station. The nine-month
period increase also reflects increased coal expense at SCE's Mohave coal facility due increased generation in the second quarter of
2004, as compared to the same period in 2003, resulting from a planned outage and maintenance repairs in the second quarter of 2003,
offset by lower coal expense during the first quarter of 2004 at SCE resulting from a scheduled major overhaul at SCE's Four Corners
coal facility in 2004, as well as lower fuel costs at EME's Illinois plants.
Purchased-power expense decreased in both the three- and nine-month periods ended September 30, 2004, as compared to the same periods
in 2003. The decrease was mainly due to the consolidation of SCE's variable interest entities The decrease was partially offset by
an increase in ISO-related costs, higher expenses related to power purchased by SCE from qualifying facilities (QFs), as discussed
below, higher expenses resulting from an increase in the number of gas bilateral contracts in 2004, as compared to 2003, and higher
unrealized losses associated with hedging instruments in 2004, as compared to 2003. The nine-month period increase was also
partially offset by the receipt of a settlement agreement payment between SCE and El Paso Natural Gas Company (see "SCE: Regulatory
Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas Markets").
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments
to gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002, energy payments for most renewable QFs were
converted to a fixed price of 5.37(cent)-per-kWh. Average spot natural gas prices were higher during the three- and nine-month periods
ended September 30, 2004, compared to the same periods in 2003.
Provisions for regulatory adjustment clauses - net decreased in both the three- and nine-month periods ended September 30, 2004,
mainly due to the collection of the PROACT balance and the implementation of the CPUC-authorized rate-reduction plan in the summer of
2003. This resulted in decreases of
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approximately $425 million and $735 million for the three- and nine-month periods, respectively. The decreases also reflect a net
effect of approximately $40 million and $220 million of regulatory adjustments, for the three- and nine-month periods, respectively,
related to the implementation of SCE's 2003 GRC decision (see "SCE: Regulatory Matters--Transmission and Distribution--2003 General
Rate Case Proceeding") and the deferral of costs for future recovery in the amount of approximately $34 million and $102 million
associated with the bark beetle infestation for the three- and nine-month periods ended September 30, 2004, respectively (see "SCE:
Regulatory Matters--Other Regulatory Matters--Catastrophic Event Memorandum Account"). The decreases also reflect the mark-to-market
of hedging instruments, including the recovery of approximately $115 million (for the nine months ended September 30, 2004) of gas
hedging costs through regulatory mechanisms in the first quarter of 2003. The decreases were partially offset by the favorable
resolution of certain regulatory cases recorded in the third quarter of 2003 and the anticipated refund of employee injury and
illness performance incentive rewards previously earned (see "SCE: Regulatory Matters--Other Regulatory Matters--Investigations
Regarding Performance Incentive Rewards"). The nine-month period decrease was also partially offset by the El Paso settlement
payment received, of which $66 million was refunded to customers through the ERRA account, as well as an allocation adjustment of
approximately $110 million for CDWR energy purchases recorded in 2003.
Other operation and maintenance expense increased in both the three- and nine-month periods ended September 30, 2004, compared to the
same periods in 2003, mainly due to increases at SCE. SCE's other operating and maintenance expense increases were mainly due to
costs incurred in 2004 related to the removal of 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, and operating and maintenance expense related to the consolidation of SCE's
variable interest entities. These increases were partially offset by a decrease in postretirement benefits other than pensions,
including the effects of adopting the Medicare Prescription Drug, Improvement and Modernization Act of 2003 in the third quarter of
2004 (see "New Accounting Principles" for further discussion) and lower worker's compensation claims in 2004. The nine-month
increase was also due to higher operation and maintenance costs related to a scheduled major overhaul at SCE's Four Corners coal
facility and additional costs for 2003 incentive compensation due to upward revisions in the computation in 2004.
Asset impairment and loss on lease termination in 2004 consist of a $954 million loss recorded in the second quarter of 2004 and a
$7 million loss recorded in the third quarter of 2004 related to the termination of EME's Collins Station lease (see "MEHC:
Liquidity--Termination of the Collins Station Lease" for further discussion), asset impairment, and related inventory reserves. In
addition, in the third quarter of 2004, a $29 million charge related to the impairment of six of EME's eight small peaking units in
Illinois. Asset impairment and loss on lease termination in 2003 primarily consisted of a $245 million charge related to the
impairment of EME's eight small peaking units in Illinois.
Depreciation, decommissioning and amortization expense decreased in the three-month period ended September 30, 2004, and increased in
the nine-month period ended September 30, 2004, as compared to the same periods in 2003. The three- and nine-month variances were
mainly due to the impact of the expiration of the Palo Verde and San Onofre ICIP mechanisms in 2004, an increase in SCE's
depreciation expense associated with additions to transmission and distribution assets, and the consolidation of SCE's variable
interest entities. Contributing to the nine-month increase was an increase in SCE's nuclear decommissioning expense.
Other Income and Deductions
Interest and dividend income decreased in both the three- and nine-month periods ended September 30, 2004, as compared to the same
periods in 2003, due to the absence of interest income on the PROACT
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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.
Equity in income from partnerships and unconsolidated subsidiaries - net decreased in both the three- and nine-month periods ended
September 30, 2003, as compared to the same periods in 2003, due to the effects of accounting for SCE's variable interest entities
consolidated upon adoption of a new accounting pronouncement in second quarter 2004 and the sale of EME's ownership interest in Four
Star Oil & Gas on January 7, 2004. EME's third quarter equity in income from its domestic energy projects is materially higher than
equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's
domestic energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer
months.
Other nonoperating income decreased for the three-month period ended September 30, 2004 and increased in the nine-month period ended
September 30, 2004. The three-month period decrease was mainly due to SCE's recognition of 2000 performance rewards related to Palo
Verde approved by the CPUC and recorded in the third quarter of 2003. The nine-month period increase reflects a gain related to the
sale of EME's interest in Edison Mission Energy Oil & Gas (see "Acquisition and Dispositions" for further details).
Minority interest represents SCE's variable interest entities consolidated upon adoption of a new accounting pronouncement in second
quarter 2004 (see "Critical Accounting Policies" and "New Accounting Principles").
Income Taxes
Income tax decreased for both the three- and nine-month periods ended September 30, 2004, compared to the same periods in 2003,
primarily due to a decrease in pre-tax income. The nine-month period decrease was also due to changes in property-related
flow-through taxes at SCE, partially offset by a reduction in SCE's tax expense in 2003 related to the favorable resolution of a FERC
rate case and the sale of SCE's fuel oil pipeline and storage business, as well as an adjustment to state taxes at EME.
Edison International's composite federal and state statutory rate was approximately 40% for both periods presented. The lower
effective tax expense rate of 37% and higher effective tax benefit rate of 48% realized in the three- and nine-month periods ended
September 30, 2004, respectively, was primarily due to low-income housing and production tax credits at Edison Capital and resumption
of the dividend payment to the employee stock ownership plan at SCE.
Earnings from Discontinued Operations
Beginning in the third quarter of 2004, MEHC reclassified the results of its international projects to discontinued operations for
all periods presented due to completion of the sale of its interest in Contact Energy and its agreement to sell the remaining
international projects. The financial results for the third quarter of 2004 include a net after-tax gain on sale of Contact Energy
of $126 million, which includes a $141 million gain on sale partially offset by a $15 million cost on a foreign exchange option. In
addition, MEHC recorded a deferred tax benefit of $327 million to recognize the higher tax basis of MEC International B.V. over its
book basis as required by accounting rules applicable to discontinued operations. The sale of the remaining international projects
is structured as a sale of the stock of MEC International B.V., which held the international assets of MEHC. The taxable income from
the sale of MEHC's interest in Contact Energy increased the stock basis of MEC International B.V., resulting in a reduction to the
projected tax on the sale of the remaining projects and recognition under accounting rules of this deferred tax benefit.
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Excluding these items, the earnings from discontinued operations were $47 million and $126 million for the three and nine months
ended September 30, 2004, respectively, compared with $39 million and $66 million for the three and nine months ended September 30,
2003, respectively. The increase in earnings was due to improved performance at Loy Yang B and First Hydro offset by interest costs
related to the $800 million bridge loan completed in December 2003. The third-quarter 2003 financial results also include a gain on
sale of $44 million from SCE's pipeline business. At MEHC, in addition to the net gain on the sale of its interest in Contact Energy
and the deferred tax benefit discussed above, earnings from discontinued operations for the nine months ended September 30, 2004
increased primarily due to the improved performance of First Hydro, Contact Energy, Loy Yang B and Paiton partially offset by higher
interest costs on the $800 million bridge loan completed in December 2003.
Discontinued operations in 2003 include a gain on sale of $44 million from SCE's fuel oil pipeline and storage business, which was
sold in the third quarter of 2003, and a loss of $2 million resulting from adjustments related to EME's sale of the Fiddler's Ferry
and Ferrybridge and Lakeland projects.
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 and receives recovery of these costs through rates, 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 Nine Months Ended September 30, 2004 2003
---------------------------------------------------------------------------------------------
Continuing operations $ 400 $ 2,750
---------------------------------------------------------------------------------------------
The change in cash provided by operating activities was mainly due to a $960 million lease termination payment in 2004 related to
EME's Collins Station lease and overcollections in 2003 used to recover PROACT. In addition, the change reflects the timing of cash
receipts and disbursements related to working capital items.
Cash Flows from Financing Activities
Net cash provided (used) by financing activities:
In millions Nine Months Ended September 30, 2004 2003
----------------------------------------------------------------------------------------------
Continuing operations $ 439 $ (1,110)
----------------------------------------------------------------------------------------------
Cash used by financing activities from continuing operations in 2004 mainly consisted of long-term and short-term debt payments at
SCE and EME.
Page 84
During January through April 2004, Edison International (parent) repurchased approximately $47 million of its $618 million 6-7/8%
notes due September 2004 and paid the remaining balance in September 2004. SCE financing activities include the issuance of $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 during the
first quarter of 2004. 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. In
addition, during the first quarter of 2004, SCE paid the $200 million outstanding balance of its credit facility, as well as
remarketed approximately $550 million of pollution-control bonds with varying maturity dates ranging from 2008 to 2040.
Approximately $354 million of these pollution-control bonds had been held by SCE since 2001 and the remaining $196 million were
purchased and reoffered in 2004. 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. During the third
quarter, SCE paid $125 million of 5.875% bonds due in September 2004. EME's financing activities included the $1 billion secured
notes and $700 million term loan facility received by Midwest Generation in April 2004, the repayment of $695 million related to
Edison Mission Midwest Holdings' credit facility, $28 million related to the EME's Coal and Capex facility in April 2004, and $100
million related to MEHC's $385 million term loan in July 2004. Financing activities in 2004 also included dividend payments of $595
million paid by Edison International to its shareholders.
Cash flows from financing activities during the nine months ended September 30, 2003, mainly reflect activity at Edison International
(parent) and SCE. During the first quarter of 2003, Edison International (parent) repurchased approximately $132 million of the
outstanding $750 million of its 6-7/8% notes due September 2004. During the nine-month period ended September 30, 2003, SCE repaid
$300 million of a one-year term loan due March 3, 2003, and $300 million on its revolving line of credit, both of which were part of
the $1.6 billion financing that took place in the first quarter of 2002. In addition, SCE repaid $125 million of its 6.25% first and
refunding mortgage bonds.
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Nine Months Ended September 30, 2004 2003
-------------------------------------------------------------------------------------
Continuing operations $ (585) $ (865)
-------------------------------------------------------------------------------------
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.
Investing activities in 2004 reflect $1.1 billion in additions to SCE's property and plant, primarily for transmission and
distribution assets and $39 million in capital additions at EME. In addition, investing activities include $285 million of
acquisition costs related to the Mountainview project at SCE, $118 million in 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,
and $739 million in proceeds received in 2004 at EME from the sale of its interest in Contact Energy.
Additions to SCE's property and plant for the nine-month period ended September 30, 2003, were approximately $820 million, primarily
for transmission and distribution assets. EME's capital additions
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for the nine-month period ended September 30, 2003 were $71 million primarily for new plant and equipment related to EME's Illinois
plants and its Homer City facilities.
ACQUISITION AND DISPOSITIONS
On September 30, 2004, EME completed the sale of its 51% interest in Contact Energy to Origin Energy New Zealand Limited.
Consideration for the sale was NZ$1.6 billion (approximately $1.1 billion), which includes NZ$535 million of debt assumed by the
purchaser. The after-tax gain on the sale of Contact Energy was $141 million and is included in income from discontinued operations
(net of tax) on the consolidated income statement for the three and nine months ended September 30, 2004.
On July 29, 2004, EME entered into an agreement to sell its remaining international power generation portfolio, owned by a wholly
owned Dutch subsidiary, MEC International B.V., to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd.
(30%). The purchase price is $2.3 billion, subject to certain purchase price adjustments prior to closing that are expected to
result in a net purchase price of approximately $2.2 billion. Closing of the BV transaction is subject to approval by International
Power's shareholders and to a number of regulatory approvals and project level consents. If certain project level approvals and
consents are not obtained, one or more projects may be excluded from the sale transaction and the purchase price may be adjusted
accordingly. The sale is expected to close in the fourth quarter of 2004. EME's estimate of the after-tax gain on the sale of its
international projects is approximately $120 million. Net proceeds from the sale will be used to repay the remaining $200 million
due from the $800 million secured loan at Mission Energy Holdings International, Inc., other indebtedness and for general corporate
purposes. EME will retain its ownership of the subsidiaries associated with the Lakeland project and some inactive subsidiaries.
Together, these two transactions represent the sale of all of EME's interests in its international projects, except that EME will
retain its ownership of the Lakeland project and some inactive international subsidiaries. In accordance with an accounting
standard related to the impairment and disposal of long-lived assets, EME's remaining international power generation projects'
results have been accounted for as discontinued operations in the financial statements for the three and nine months ended
September 30, 2004 and 2003. See "Results of Operations--Earnings from Discontinued Operations."
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 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 early 2006.
The construction work in progress for this project is recorded in nonutility property on Edison International's September 30, 2004
balance sheet. 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 held 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.
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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 transfer sufficient risk to the purchaser to be considered a variable interest. A
contract with a non-natural-gas-fired plant that is based on the price of natural gas 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 272 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 under terms and pricing
controlled by the CPUC. SCE conducted a review of its QF contracts and determined that SCE has variable interests in 17 contracts
with gas-fired cogeneration plants that are potential VIEs and that contain variable pricing provisions based on the prices of
natural gas and for which SCE does not have sufficient information to determine if the projects qualify for a scope exception. SCE
requested from the entities that hold these contracts the financial information necessary to determine whether SCE must consolidate
these projects. All 17 entities declined to provide SCE with the necessary financial information. However, four of the 17 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 combined financial statements to SCE. 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 13 projects in order to determine whether they should be consolidated by SCE. The remaining 255 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.
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. EME deconsolidated the Doga and Kwinana projects
effective March 31, 2004 and recorded its interests in these projects on the equity method beginning April 1, 2004. These two
projects are part of EME's sale of international operations and, accordingly, are included in discontinued operations. 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.
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See the year-ended 2003 MD&A for a complete discussion of Edison International's other critical accounting policies.
NEW ACCOUNTING PRINCIPLES
In May 2004, the Financial Accounting Standards Board issued accounting guidance related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003. Edison International adopted this guidance effective July 1, 2004, which resulted in a
decrease of $83 million to Edison International's accumulated benefit obligation for postretirement benefits other than pensions.
Edison International's third quarter 2004 expense decreased approximately $5 million as a result of the subsidy. According to
proposed federal regulations, Edison International's retiree health care plans provide prescription drug benefits that are deemed to
be actuarially equivalent to Medicare benefits. Accordingly, Edison International recognized the subsidy in the measurement of its
accumulated obligation and recorded an actuarial gain.
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 deconsolidated as of
December 31, 2003.
On March 31, 2004, 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 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
September 30, 2004 are: 2005 - $985 million; 2006 - $1.3 billion; 2007 - $1.5 billion; 2008 - $1.3 billion; 2009 - $832 million; and
thereafter - $6.2 billion. These amounts have been updated to reflect financing activities during the nine months ended
September 30, 2004 and EME's pending sale of its international portfolio.
EME's Midwest Generation and Homer City have entered into additional fuel purchase agreements with various third-party suppliers
during the first nine months of 2004. EME's Midwest Generation and Homer City's fuel purchase commitments under these agreements are
currently estimated to be $22 million for 2004, $63 million for 2005, $97 million for 2006, $101 million for 2007, and $57 million
for 2008.
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OTHER DEVELOPMENTS
Employee Compensation and Benefit Plans
In April 1999, Edison International adopted a cash balance feature for its pension plan. 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 (including a post-IBM decision issued in June 2004) and with the proposed regulations for cash balance
pension plans issued by the 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. On September 15 and September 29, 2004, IBM announced settlements of some of the claims, but stated
the company would continue to appeal the two claims relating to age discrimination. The settlements also cap the potential damages
IBM will face if it loses its appeal on the age discrimination issues. 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 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 31 identified sites at SCE (24 sites) and EME (7 sites)
is $90 million, $88 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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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 $131 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 $30 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 $61 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 September 30, 2004
were $17 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
Edison International has reached a tentative settlement with the IRS on tax issues and pending affirmative claims relating to its
1991 to 1993 tax years currently under appeal. This settlement, which will be finalized in 2005, is expected to result in a net
earnings benefit for Edison International of approximately $50 million, most of which relates to SCE.
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 these
matters 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 deferral of income taxes associated with the EPZ
and Dutch electric locomotive leases. The IRS has also given notice that it will assert the same arguments for the 1997 to 1999
audit 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
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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. In
conjunction with this examination, Edison Capital received notices of proposed adjustments to Edison International's tax liability
which, if upheld, would accelerate the payment of taxes that were deferred as a result of several of its other leveraged leases
entered into in 1997 and 1998. The proposed adjustment is based on revenue rulings issued by the IRS in 1999 and 2002 in connection
with the IRS' industry-wide challenge mounted against a specific type of leveraged lease (termed a lease in/lease out or LILO
transaction). The estimated federal and state income taxes deferred from these leases was $558 million in the 1997-1999 audit period
and $565 million in subsequent years through 2003. The IRS has also proposed interest and penalties. Edison International believes
that the positions described in the revenue rulings are incorrectly applied to Edison Capital's transactions and that its leveraged
leases are factually and legally distinguishable in material respects from that position. Edison International 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 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 described by the IRS as a contingent liability company. 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.
Page 91
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: 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)
or 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.
Internal Control Over Financial Reporting
There were no changes in Edison International's internal control over financial reporting (as such term is defined in Rules 13a-15(f)
or 15d-15(f) under the Exchange Act) 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.
Page 92
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. Information about the Navajo Nation Litigation was previously reported in Part I, Item 3 of Edison
International's Annual Report on Form 10-K for the year ended December 31, 2003, Part II, Item 1 of Edison International's Quarterly
Report on Form 10-Q for the period ending March 31, 2004, and in Part II, Item 1 of Edison International's Quarterly Report on Form
10-Q for the period ending June 30, 2004.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers
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(a)(3) under the Exchange 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
Period Purchased 1 Share (or Unit)1 Programs Programs
- --------------------------------------------------------------------------------------------------------------------
July 1, 2004 to 3,403,364 $25.79 -- --
July 31, 2004
August 1, 2004 to 4,187,212 $26.88 -- --
August 31, 2004
September 1, 2004 to 2,472,574 $26.69 -- --
September 30, 2004
- -------------------------------------------------------------------------------------------------------------------
Total 10,063,150 $26.46 -- --
- ---------------------------- ---------------------- ---------------------------------------------------------------
-------------------
1 The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants 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. The shares were never registered in Edison International's
name and none of the shares purchased were retired as a result of the transactions.
Page 94
Item 6. 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 May 20, 2004 (File No.
1-9936, Edison International Form 8-K, dated May 21, 2004)*
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.
Page 95
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By /s/ THOMAS M. NOONAN
---------------------------------
THOMAS M. NOONAN
Vice President and Controller
By /s/ KENNETH S. STEWART
---------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
Dated: November 8, 2004