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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 June 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 August 4, 2004
- ----------------------------------------------------- -------------------------------------------------------
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 Six Months
Ended June 30, 2004 and 2003 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2004 and 2003 2
Consolidated Balance Sheets - June 30, 2004
and December 31, 2003 3
Consolidated Statements of Cash Flows - Six Months
Ended June 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 29
Item 3. Quantitative and Qualitative Disclosures About Market Risk 83
Item 4. Controls and Procedures 83
Part II. Other Information:
Item 1. Legal Proceedings 84
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities 85
Item 4. Submission of Matters to a Vote of Security Holders 86
Item 6. Exhibits and Reports on Form 8-K 87
Signatures
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EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility $ 2,176 $ 2,386 $ 3,872 $ 4,200
Nonutility power generation 713 716 1,496 1,399
Financial services and other 30 23 61 48
- -------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,919 3,125 5,429 5,647
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Fuel 465 293 806 627
Purchased power 527 722 1,107 1,174
Provisions for regulatory adjustment clauses - net (33) 505 (51) 809
Other operation and maintenance 927 827 1,832 1,610
Asset impairment and loss on lease termination 954 251 954 251
Depreciation, decommissioning and amortization 302 252 598 539
Property and other taxes 57 51 107 102
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Total operating expenses 3,199 2,901 5,353 5,112
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Operating income (loss) (280) 224 76 535
Interest and dividend income 14 47 27 93
Equity in income from partnerships and
unconsolidated subsidiaries - net 51 60 115 120
Other nonoperating income 13 21 93 36
Interest expense - net of amounts capitalized (324) (290) (640) (589)
Other nonoperating deductions (21) (12) (37) (20)
Minority interest (63) (10) (76) (14)
Dividends on preferred securities
subject to mandatory redemption -- (28) -- (56)
Dividends on utility preferred stock
not subject to mandatory redemption (1) (1) (3) (3)
- -------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before tax (611) 11 (445) 102
Income tax (benefit) (237) (13) (170) 17
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Income (loss) from continuing operations (374) 24 (275) 85
Income from discontinued operations - net of tax -- -- -- 4
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Income (loss) before accounting change (374) 24 (275) 89
Cumulative effect of accounting change - net of tax -- -- (1) (9)
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Net income (loss) $ (374) $ 24 $ (276) $ 80
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Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings (loss) per share:
Continuing operations $ (1.15) $ 0.07 $ (0.85) $ 0.27
Discontinued operations -- -- -- 0.01
Cumulative effect of accounting change -- -- -- (0.03)
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Total $ (1.15) $ 0.07 $ (0.85) $ 0.25
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Weighted-average shares, including
effect of dilutive securities 326 329 326 329
Diluted earnings (loss) per share:
Continuing operations $ (1.15) $ 0.07 $ (0.85) $ 0.26
Discontinued operations -- -- -- 0.01
Cumulative effect of accounting change -- -- -- (0.03)
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Total $ (1.15) $ 0.07 $ (0.85) $ 0.24
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Dividends declared per common share $ 0.20 $ -- $ 0.40 $ --
The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
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(Unaudited)
Net income (loss) $ (374) $ 24 $ (276) $ 80
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Other comprehensive income (expense), net of tax:
Foreign currency translation adjustments (29) 42 (7) 63
Unrealized gain (loss) on investments - net 18 (2) 18 (2)
Unrealized gains (losses) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges - net (3) 25 (48) 22
Reclassification adjustment for gain (loss)
included in net income (loss) 22 (5) 43 (6)
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Other comprehensive income 8 60 6 77
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Comprehensive income (loss) $ (366) $ 84 $ (270) $ 157
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions 2004 2003
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(Unaudited)
ASSETS
Cash and equivalents $ 2,605 $ 2,198
Restricted cash 67 79
Receivables, less allowances of $40 and $37 for uncollectible
accounts at respective dates 1,221 1,200
Accrued unbilled revenue 555 408
Fuel inventory 91 92
Materials and supplies, at average cost 272 252
Accumulated deferred income taxes - net 725 563
Trading and price risk management assets 31 48
Prepayments 100 88
Other current assets 155 176
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Total current assets 5,822 5,104
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Nonutility property - less accumulated provision for
depreciation of $1,896 and $1,318 at respective dates 8,060 7,701
Nuclear decommissioning trusts 2,581 2,530
Investments in partnerships and unconsolidated subsidiaries 1,808 1,908
Investments in leveraged leases 2,395 2,361
Other investments 169 176
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Total investments and other assets 15,013 14,676
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Utility plant, at original cost:
Transmission and distribution 15,183 14,861
Generation 1,360 1,371
Accumulated provision for depreciation (4,507) (4,386)
Construction work in progress 734 600
Nuclear fuel, at amortized cost 143 141
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Total utility plant 12,913 12,587
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Goodwill 854 868
Restricted cash 286 339
Regulatory assets - net 369 510
Other deferred charges 965 916
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Total deferred charges 2,474 2,633
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Assets of discontinued operations 11 16
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Total assets $ 36,233 $ 35,016
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The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions, except share amounts 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 31 $ 252
Long-term debt due within one year 1,296 2,003
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,230 1,086
Accrued taxes 432 515
Trading and price risk management liabilities 221 168
Regulatory liabilities - net 256 361
Other current liabilities 1,590 1,827
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Total current liabilities 5,065 6,221
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Long-term debt 14,230 11,787
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Accumulated deferred income taxes - net 5,979 5,967
Accumulated deferred investment tax credits 144 149
Customer advances and other deferred credits 1,453 1,554
Power-purchase contracts 186 213
Preferred securities subject to mandatory redemption 298 305
Accumulated provision for pensions and benefits 486 425
Asset retirement obligations 2,150 2,106
Other long-term liabilities 259 247
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Total deferred credits and other liabilities 10,955 10,966
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Liabilities of discontinued operations 11 13
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Total liabilities 30,261 28,987
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Commitments and contingencies (Notes 2 and 4)
Minority interest 856 517
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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) 1,980 1,970
Accumulated other comprehensive loss (47) (53)
Retained earnings 3,054 3,466
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Total common shareholders' equity 4,987 5,383
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Total liabilities and shareholders' equity $ 36,233 $ 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
Six Months Ended
June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Income (loss) from continuing operations, after accounting change,
net of tax $ (276) $ 76
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax 1 9
Depreciation, decommissioning and amortization 598 539
Other amortization 49 54
Minority interest 76 14
Deferred income taxes and investment tax credits (156) (85)
Equity in income from partnerships and unconsolidated subsidiaries (115) (120)
Income from leveraged leases (44) (42)
Regulatory assets - long-term - net 152 147
Asset impairment -- 251
Gain on sale of assets (43) --
Levelized rent expense (54) (92)
Other assets (11) 38
Other liabilities 34 (169)
Changes in working capital net of effects from consolidation and
deconsolidation of variable interest entities:
Receivables and accrued unbilled revenue (160) (225)
Regulatory liabilities - short-term - net (105) 579
Prepayments and other current assets (16) 1
Accrued interest and taxes (34) 118
Accounts payable and other current liabilities (172) 193
Distributions and dividends from unconsolidated entities 54 65
Operating cash flows from discontinued operations (1) (9)
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Net cash provided (used) by operating activities (223) 1,342
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 3,327 214
Long-term debt repaid (1,698) (907)
Bonds remarketed - net 350 --
Redemption of preferred securities (2) (5)
Rate reduction notes repaid (115) (115)
Short-term debt financing - net (229) 303
Dividends to minority shareholders (37) (9)
Dividends paid (130) --
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Net cash provided (used) by financing activities 1,466 (519)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (768) (619)
Acquisition costs related to nonutility generation plant (285) --
Purchase of common stock of acquired companies -- (275)
Proceeds from sale of interests in projects 118 --
Contributions to nuclear decommissioning trusts - net (42) (1)
Distributions from (investments in) partnerships and
unconsolidated subsidiaries 24 (58)
Investments in other assets 63 19
Investing cash flows from discontinued operations 1 5
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Net cash used by investing activities (889) (929)
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Effect of exchange rate changes on cash 8 19
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Effect of consolidation of variable interest entities on cash 79 --
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Effect of deconsolidation of variable interest entities on cash (34) --
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents 407 (87)
Cash and equivalents, beginning of period 2,198 2,468
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Cash and equivalents, end of period, continuing operations $ 2,605 $ 2,381
- -------------------------------------------------------------------------------------------------------------------
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 June 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.
Certain prior-period amounts were reclassified to conform to the June 30, 2004 financial statement presentation.
Dividend Restriction
The California Public Utilities Commission (CPUC) regulates SCE's capital structure, limiting the dividends it
may pay Edison International. In its most recent cost of capital proceeding, the CPUC set an authorized capital
structure for SCE which included a common equity component of 48%. SCE determines compliance with this capital
structure based on a 13-month weighted-average calculation. At June 30, 2004, SCE's 13-month weighted-average
common equity component of total capitalization was 53%. At June 30, 2004, SCE had the capacity to pay
$462 million in additional dividends and continue
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to maintain its CPUC-authorized capital structure based on the 13-month weighted-average method. Based on
recorded June 30, 2004 balances, SCE's common equity to total capitalization ratio, for rate-making purposes, was
48%. SCE had the capacity to pay $28 million of additional dividends based on June 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 Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Basic weighted-average shares
of common stock outstanding 326 326 326 326
Stock-based compensation awards exercisable -- 3 -- 3
- -------------------------------------------------------------------------------------------------------------------
Dilutive weighted-average shares
of common stock outstanding 326 329 326 329
- -------------------------------------------------------------------------------------------------------------------
Goodwill
Goodwill represents the excess of cost incurred over the fair value of net assets acquired in a purchase
transaction. EME evaluates goodwill whenever indicators of impairment exist, but at least annually on October 1
of each year. EME's goodwill ($853 million at June 30, 2004 and $867 million at December 31, 2003) is primarily
related to the acquisitions of Contact Energy and First Hydro.
New Accounting Principles
In December 2003, the Financial Accounting Standards Board issued a revision to an accounting Interpretation
(originally issued in January 2003), Consolidation of Variable Interest Entities. The primary objective of the
Interpretation is to provide guidance on the identification of, and financial reporting for, VIEs, where control
may be achieved through means other than voting rights. Under the Interpretation, the enterprise that is
expected to absorb or receive the majority of a VIE's expected losses or residual returns, or both, must
consolidate the VIE, unless specific exceptions apply. This Interpretation is effective for special purpose
entities, as defined by accounting principles generally accepted in the United States, as of December 31, 2003,
and all other entities as of March 31, 2004. See Edison International's 2003 Annual Report for information on
special purpose entities deconsolidated as of December 31, 2003.
SCE has 273 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
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 22 contracts with
gas-fired cogeneration plants that contain variable pricing provisions based on the prices of natural gas. SCE
requested from the entities that hold these contracts the financial information necessary to determine whether
SCE must consolidate these projects. All 22 entities declined to provide SCE with the necessary financial
information. However, four of the 22 contracts are with entities 49%-50% owned by a related party, EME. EME is
an indirect wholly owned subsidiary of Edison International. Although the four related-party entities have
declined to provide their financial information to SCE, Edison International has access to such information and
has provided 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 18 projects in order to determine whether they should be consolidated by SCE.
The remaining 251 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. Additionally, SCE has six five-year power contracts
with non-QF generators. These contracts are not considered to be significant variable interests due to their
short duration.
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 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.
Nuclear
Effective January 1, 2004, San Onofre Nuclear Generation 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
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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 (loss) and earnings (loss) per share if Edison International had used the fair-value accounting method.
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income (loss), as reported $ (374) $ 24 $ (276) $ 80
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 3 2 7 4
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 3 2 6 5
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income (loss) $ (374) $ 24 $ (275) $ 79
- -------------------------------------------------------------------------------------------------------------------
Basic earnings (loss) per share:
As reported $ (1.15) $ 0.07 $ (0.85) $ 0.25
Pro forma $ (1.15) $ 0.07 $ (0.84) $ 0.24
Diluted earnings (loss) per share:
As reported $ (1.15) $ 0.07 $ (0.85) $ 0.24
Pro forma $ (1.15) $ 0.07 $ (0.84) $ 0.24
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Supplemental Cash Flows Information
Six Months Ended
June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Noncash investing and financing activities:
Details of assets acquired:
Fair value of assets acquired $ -- $ 333
Cash paid for acquisitions -- (275)
- -------------------------------------------------------------------------------------------------------------------
Liabilities assumed -- $ 58
- -------------------------------------------------------------------------------------------------------------------
Details of consolidation of variable interest entities:
Assets $ 625 --
Liabilities (704) --
Details of deconsolidation of variable interest entities:
Assets $ (220) --
Liabilities 254 --
Reoffering of pollution-control bonds $ 196 --
Details of pollution-control bond redemption:
Release of funds held in trust $ 20 --
Pollution-control bonds redeemed (20) --
Details of long-term debt exchange offer:
Variable rate notes redeemed -- $ (966)
First and refunding bonds issued -- 966
- -------------------------------------------------------------------------------------------------------------------
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 June 30,
2004 is $393 million ($896 million at original cost less $503 million in accumulated depreciation) and is
recorded in nonutility property.
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 June 30, 2004. Properties serving as
collateral for these loans had a carrying value of $50 million and are classified as nonutility property on the
June 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 following two projects effective March 31, 2004. Prior periods have not been restated.
EME recorded its interests in the Doga and Kwinana projects on the equity method beginning April 1, 2004.
Doga, a 180-MW gas-fired power plant in Turkey (of which EME owns 80%), has a power sales contract that is
considered a variable interest due to the energy price provisions that absorb the risk of changes in operating
costs and the transfer of ownership of the cogeneration plant to the energy purchaser at the end of the power
sales contract.
Kwinana, a 116-MW gas-fired power plant in Australia (of which EME owns 70%), has power sales contracts that are
considered variable interests due to the energy price provisions that absorb the risk of changes in operating
costs.
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant Variable Interests in Entities Not Consolidated
EME's
Variable EME's Ownership
Interest Investment at Interest at
Entity Location June 30, 2004 June 30, 2004 Description
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Paiton Indonesia $600 45% Coal-fired facility
EcoElectrica Puerto Rico 295 50% Liquefied natural gas
cogeneration facility
Sunrise California 84 50% Gas-fired facility
ISAB Italy 96 49% Gasification facility
CBK Philippines 82 50% Pumped-storage
hydroelectric facility
IVPC4 Srl Italy 42 50% Wind facilities
Doga Turkey 14 80% Gas-fired facility
Tri Energy Thailand 22 25% Gas-fired facility
- -------------------------------------------------------------------------------------------------------------------
EME's maximum exposure to loss is generally limited to its investment in these entities. EME's interest in the
Kwinana project is not a significant variable interest and, therefore, is not included in the table above.
Edison Capital's maximum exposure to loss from affordable housing investments in this category is generally
limited to its investment balance of $192 million and recapture of tax credits.
Entities with Unavailable Financial Information
SCE has 18 nonrelated-party contracts with certain QFs that contain variable pricing provisions based on the
price of natural gas. SCE might be considered to be the consolidating entity under the new accounting standard.
However, these entities are not legally obligated to provide the financial information to SCE that is necessary
to determine whether SCE must consolidate these entities. These 18 entities have declined to provide SCE with
the necessary financial information. SCE will continue to attempt to obtain information for these projects in
order to determine whether they should be consolidated by SCE. The aggregate capacity dedicated to SCE for these
projects is 471 MW. SCE paid $69 million and $118 million, respectively, for the three and six months ended June
30, 2004 and $61 million and $115 million, respectively, for the three and six months ended June 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.
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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 (Ninth Circuit) seeking to overturn the
stipulated judgment of the federal district court that approved the 2001 CPUC settlement agreement. In
September 2002, the Ninth Circuit issued its opinion affirming the federal district court on all claims, with the
exception of the challenges founded upon California state law, which the Ninth Circuit referred to the California
Supreme Court.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate
California law in any of the respects raised by the Ninth Circuit. The matter was returned to the Ninth Circuit
for final disposition and in December 2003, the Ninth Circuit unanimously affirmed the original stipulated
judgment of the federal district court. In January 2004, the Ninth Circuit issued its mandate, relinquishing
jurisdiction of the case and returning jurisdiction to the federal district court. No petitions were filed
within the 90-day period in which parties could seek discretionary review by the United States Supreme Court of
the federal district court's decision. Accordingly, the appeals of the stipulated judgment approving the 2001
CPUC settlement agreement have been resolved in SCE's favor.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation regarding SCE's overhead and underground
electric line maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection
and Safety Division, which alleged a pattern of noncompliance with the CPUC's general orders for the maintenance
of electric lines for 1998-2000.
In an April 22, 2004, CPUC 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.
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 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. As a result of the implementation of the 2003 GRC decision, SCE recorded pre-tax net
regulatory adjustments of $180 million as a credit to provision for regulatory adjustment clauses during the
second quarter of 2004.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. This will result in an approximate $55 million pre-tax gain in the third
quarter of 2004. In addition, SCE expects to record approximately $48 million in pre-tax gains related to the
rate recovery of the 1997-1998 generation-related capital additions and the related revenue requirement in the
third quarter of 2004, as a further result of the implementation of the 2003 GRC decision.
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. SCE has proposed that the GRC rate increase be combined
with other rate changes from pending rate proceedings and be 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 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 did not file a challenge to the decision as to the first
priority issue, so the first priority requirement is now final. The California Supreme Court has 60 days
(extendable to 90 days) within which to accept or reject the petition for review as to the jurisdiction issue.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in Edison International's 2003 Annual Report, in May 2002, SCE filed
an application with the CPUC to address certain issues (mainly coal and slurry-water supply issues) facing the
future extended operation of Mohave Generating Station (Mohave), which is partly owned by SCE. The uncertainty
over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from making approximately
$1.1 billion in Mohave-related investments (SCE's share is $605 million), including the installation of
pollution-control equipment that must be put in place in order for Mohave to continue to operate beyond 2005,
pursuant to a 1999 consent decree concerning air quality.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues,
but no resolution has been reached. SCE and other parties submitted further testimony and made various other
filings in 2003 in SCE's application proceeding. Pursuant to the assigned administrative law judge's March 9,
2004 ruling, on April 16, 2004 SCE updated its position and testimony on cost data and, where 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 approximately three years is likely. Evidentiary hearings took place in June and
July 2004, and a decision on this matter is not expected before November 2004. 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 an 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 any amounts
received under the terms of the El Paso 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. Additional settlement payments
totaling approximately $134 million are due from El Paso over a 20-year period. In addition, 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
approximately $37 million in 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 April 26, 2004 settlement terms
provide for refunds and other payments totaling $285 million, with a proposed allocation to SCE of approximately
$40 million. The 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 that is expected
to exceed $40 million. The Duke settlement remains subject to the approval of the FERC and the CPUC.
Additionally, 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.
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 June 30, 2004, $9 million in contributions have been made. Edison
International expects to contribute approximately $4 million to its foreign
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
pension plans in 2004. As of June 30, 2004, approximately $2 million in contributions have been made. Edison
International anticipates that its original expectations will be met by year-end 2004.
Expense components for United States plans are:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 27 $ 23 $ 53 $ 47
Interest cost 44 42 87 85
Expected return on plan assets (60) (47) (118) (95)
Net amortization and deferral 6 9 12 18
- -------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 17 27 34 55
Regulatory adjustment - deferred -- (11) -- (22)
- -------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 17 $ 16 $ 34 $ 33
- -------------------------------------------------------------------------------------------------------------------
Expense components for foreign plans are:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 1 $ 1 $ 2 $ 1
Interest cost 1 1 2 2
Expected return on plan assets (1) (1) (2) (2)
Curtailment/settlement -- -- -- 2
- -------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 1 $ 1 $ 2 $ 3
- -------------------------------------------------------------------------------------------------------------------
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 June 30, 2004, $12 million in contributions have
been made. Edison International anticipates that its original expectation will be met by year-end 2004.
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 will adopt this guidance in
third quarter 2004. If Edison International's retiree health care plans provide prescription drug benefits that
are deemed to be actuarially equivalent to Medicare benefits, Edison International will recognize the subsidy in
the measurement of its accumulated obligation and record an actuarial gain. Proposed federal regulations
defining actuarial equivalency are expected in third quarter 2004, with final regulations expected to be released
by year-end 2004. Until the proposed regulations are issued, Edison International is unable to predict the
effect of the new law on its postretirement health care costs and obligations.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 11 $ 11 $ 23 $ 22
Interest cost 33 31 67 62
Expected return on plan assets (27) (22) (55) (44)
Net amortization and deferral 8 10 15 20
- -------------------------------------------------------------------------------------------------------------------
Total expense $ 25 $ 30 $ 50 $ 60
- -------------------------------------------------------------------------------------------------------------------
Note 4. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and
regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary
course of business. Edison International believes the outcome of these other proceedings will not materially
affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has invested in three aircraft leased to American Airlines. The independent auditors' opinion on
the year-end 2003 financial statements of AMR Corporation, parent company of American Airlines, removed the
comment on AMR Corporation's ability to continue as a going concern from year-end 2002. However, while AMR
Corporation reports some improvement, uncertainty remains and if American Airlines defaults in making its lease
payments, the lenders with a security interest in the aircraft or leases may exercise remedies that could lead to
a loss of some or all of Edison Capital's investment in the aircraft plus any accrued interest. The total
maximum loss exposure to Edison Capital in 2004 is $46 million. A restructure of the lease could also result in
a loss of some or all of the investment. At June 30, 2004, American Airlines was current in its lease payments
to Edison Capital.
Employee Compensation and Benefit Plans
On July 31, 2003, a federal district court held that the formula used in a cash balance pension plan created by
International Business Machine Corporation (IBM) in 1999 violated the age discrimination provisions of the
Employee Retirement Income Security Act of 1974. In its decision, the federal district court set forth a
standard for cash balance pension plans. This decision, however, conflicts with the decisions from two other
federal district courts and with the proposed regulations for cash balance pension plans issued by the Internal
Revenue Service (IRS) in December 2002. On February 12, 2004, the same federal district court ruled that IBM
must make back payments to workers covered under this plan. IBM has indicated that it will appeal both decisions
to the United States Court of Appeals for the Seventh Circuit. The formula for Edison International's cash
balance pension plan does not meet the standard set forth in the federal district court's July 31, 2003
decision. Edison International cannot predict with certainty the effect of the two IBM decisions on Edison
International's cash balance pension plan.
Page 18
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur
substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove
the effect of past operations on the environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements;
however, possible future developments, such as the enactment of more stringent environmental laws and
regulations, could affect the costs and the manner in which business is conducted and could cause substantial
additional capital expenditures. There is no assurance that additional costs would be recovered from customers
or that Edison International's financial position and results of operations would not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International
reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of involvement and financial condition of
other potentially responsible parties. These estimates include costs for site investigations, remediation,
operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 33 identified sites at SCE
(26 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 $63 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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2004 were $16 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts
in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's
regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs
ultimately recorded will not materially affect its results of operations or financial position. There can be no
assurance, however, that future developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
In August 2002, Edison International received a notice from the IRS asserting deficiencies in federal corporate
income taxes for its 1994 to 1996 tax years. The vast majority of the asserted tax deficiencies are timing
differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would benefit
Edison International as future tax deductions. Edison International believes that it has meritorious legal
defenses to those deficiencies and believes that the ultimate outcome of this matter will not result in a
material impact on Edison International's consolidated results of operations or financial position.
Among the issues raised by the IRS in the 1994 to 1996 audit was Edison Capital's 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 expects the IRS to propose an adjustment 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
expected to be 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 may also propose 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 rate-making (PBR) mechanism to earn rewards or
penalties based on its performance in comparison to CPUC-approved standards of service reliability, customer
satisfaction, and employee safety. SCE received two letters over the last year from one or more anonymous
employees alleging that personnel in the service planning group of SCE's transmission and distribution business
unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by
an independent survey organization. The results of these surveys are used, along with other factors, to
determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer
satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and
2000. Potential customer satisfaction rewards aggregating $10 million for 2001 and 2002 are pending before the
CPUC and have not been recognized in income by SCE. SCE also had anticipated that it could be eligible for
customer satisfaction rewards of about $10 million for 2003.
SCE 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 widespread misconduct, SCE proposed to
refund to ratepayers all of the $12 million in PBR rewards that may be attributed 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 about $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 with respect to the customer satisfaction survey misconduct by severing the
employment of several supervisory personnel, updating system processes and related documentation for survey
reporting, and implementing additional supervisory controls over data collection and processing.
As mentioned above, SCE is also eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based
on its performance in comparison to CPUC-approved standards of service reliability and employee safety. In light
of the problems uncovered with the customer satisfaction surveys, SCE commenced investigations into the accuracy
and completeness of SCE's service reliability and employee safety reporting. While the safety and service
reliability investigations are not yet complete, SCE has preliminarily concluded that some of its data collection
procedures for recording employee injuries may have been inadequate and some misreporting may have occurred. SCE
has not reached any conclusions
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
as to the effect of those problems on the validity of safety incentive performance payments. SCE has advised the
CPUC staff of the existence of the safety and reliability investigations, promised to provide copies of the
investigative reports, and committed to return to ratepayers or forgo any PBR rewards that were earned based on
data shown to be inaccurate. Both the safety and the service reliability investigations are being pursued
aggressively and will be completed as soon as possible. Since the inception of PBR payments in 1997, SCE has
received $20 million in employee safety incentive performance payments and, based on SCE's records, may be
entitled to an additional $15 million. As for service reliability, since the inception of PBR payments in 1997,
SCE has received $8 million in rewards based on frequency of outage data and has applied for an additional
$5 million award based on frequency of outage data for 2001.
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, service reliability and/or employee
safety. 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.
Navajo Nation Litigation
In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of
Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt
River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for
Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and
Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less
than $1 billion, as well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation
lands should be terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition,
SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal, except
for Salt River Project Agricultural Improvement and Power District's motion for its separate dismissal from the lawsuit.
Some of the issues included in this case were addressed by the United States Supreme Court in a separate legal
proceeding filed by the Navajo Nation in the Court of Federal Claims against the United States Department of
Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning
negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody. On
March 4, 2003, the Supreme Court concluded, by majority decision, that 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 District Court
subsequently issued a scheduling order that imposes a December 31, 2004 discovery cut-off and sets a status
conference for January 21, 2005. No trial date was established in the scheduling order. The parties to the D.C.
District Court action are currently engaged in scheduling and completing the remaining discovery in the case.
The Federal Circuit Court of Appeals, acting on a suggestion on remand filed by the Navajo Nation, held in a
October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on three
Page 22
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
specific statutes or regulations and therefore did not address the question of whether a network of other
statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during
the time period in question. The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 Court of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the
Court of Appeals issued an order remanding the case against the Government to the Federal Court of Claims, 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 in the remanded Court of Federal Claims case as a party 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 the
San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance
available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred
premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States
results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre
Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is
$101 million per reactor, but not more than $10 million per reactor may be charged in any one year for each
incident. Based on its ownership interests, SCE could be required to pay a maximum of $199 million per nuclear
incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts
include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to
adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible additional assessment on all licensed
reactor 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 has the
obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. However, the DOE did not
meet its obligation. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or
other nuclear power plants. Extended delays by the
Page 23
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DOE have led to the construction of costly alternatives, including siting and environmental issues. SCE has paid
the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983
(approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1(cent)-per-kWh
of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a
complaint against the DOE in the Federal Court of Claims seeking damages for DOE's failure to meet its obligation
to begin accepting spent nuclear fuel from San Onofre.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent
nuclear fuel is stored in the San Onofre Units 1, 2 and 3 spent fuel pools and the San Onofre independent spent
fuel storage installation. Movement of Unit 1 spent fuel from the Unit 3 spent fuel pool to the independent
spent fuel storage installation was completed in late 2003. Movement of Unit 1 spent fuel from the Unit 1 spent
fuel pool to the independent spent fuel storage installation is scheduled to be completed by late 2004 and from
the Unit 2 spent fuel pool to the independent spent fuel storage installation by 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 early 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a
dry cask storage facility. Arizona Public Service, as operating agent, plans to continually load casks on a
schedule to maintain full core off-load capability for all three units.
Storm Lake
As of June 30, 2004, Edison Capital had an investment of approximately $71 million in Storm Lake Power, a project
developed by Enron Wind, a subsidiary of Enron Corporation. As of June 30, 2004, Storm Lake had outstanding
loans of approximately $55 million. The lenders claim that Enron's bankruptcy, among other things, is an event
of default under the loan agreement and as a result, the debt has been reclassified to long-term debt due within
one year. However, the lenders are currently discussing resolution of the defaults with Storm Lake and are not
actively pursuing remedies.
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. See further discussion in
"Basis of Presentation" in Note 1.
Page 24
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information for the three and six months ended June 30, 2004 and 2003 was:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 2,176 $ 2,386 $ 3,872 $ 4,200
Nonutility power generation 713 716 1,496 1,399
Financial services 27 22 56 44
Corporate and other 3 1 5 4
- -------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,919 $ 3,125 $ 5,429 $ 5,647
- -------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 242 $ 225 $ 341 $ 327
Nonutility power generation(2) (610) (191) (603) (232)
Financial services(3) 11 12 21 27
Corporate and other (17) (22) (35) (42)
- -------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ (374) $ 24 $ (276) $ 80
- -------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock. Includes earnings from discontinued operations of $3 million and
$6 million, respectively, for the three and six months ended June 30, 2003.
(2) Includes a loss of $9 million from the cumulative effect of an accounting change for the six months
ended June 30, 2003. Also, included losses from discontinued operations of $2 million for both the
three and six months ended June 30, 2003.
(3) Includes a loss of $1 million from the cumulative effect of an accounting change for the six months
ended June 30, 2004.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.
Total segment assets as of June 30, 2004 were: electric utility, $19 billion; nonutility power generation,
$14 billion; and, financial services, $4 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 2006. The construction work in progress for this project is recorded in nonutility
property on Edison International's June 30, 2004 balance sheet.
Page 25
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Dispositions
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 BV, 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. The sale is expected to close in the fourth quarter of 2004.
On July 20, 2004, EME entered into an agreement to sell its 51% interest in Contact Energy to Origin Energy
Limited for total consideration of NZ$1.7 billion (approximately $1.1 billion), which includes the assumption of
NZ$535 million of debt. Completion of the sale, currently expected in the fourth quarter of 2004, is subject to
closing conditions, including action by the New Zealand Takeovers Panel. EME has entered into a foreign currency
hedge in order to protect against a depreciation in the value of the New Zealand dollar (in which the sales price
is denominated) versus United States dollar.
Together, these two transactions represent the sale of all of EME's interests in its international projects. Net
proceeds from these two transactions are expected to be approximately $2.5 billion to EME after taxes and
transaction expenses and purchase price adjustments. EME's initial estimate of the after-tax gain on sale of its
international projects is approximately $550 million. Net proceeds from the sale will be used to repay the
$800 million secured loan at Mission Energy Holdings International, Inc. and other indebtedness. EME will retain
its ownership of the Lakeland project and some inactive subsidiaries.
The following table presents the condensed financial position of MEC International BV on a stand-alone basis and
does not include intercompany eliminations.
June 30,
In millions 2004
- -------------------------------------------------------------------------------------------------
(Unaudited)
Cash and equivalents $ 198
Nonutility property 4,128
Other assets 2,392
- -------------------------------------------------------------------------------------------------
Total assets $ 6,718
- -------------------------------------------------------------------------------------------------
Accounts payable $ 158
Debt 2,840
Accumulated deferred taxes - net 596
Other liabilities 914
Minority interest 733
Shareholder's equity 1,477
- -------------------------------------------------------------------------------------------------
Total liabilities and shareholder's equity $ 6,718
- -------------------------------------------------------------------------------------------------
Beginning in the third quarter of 2004, EME will report its international operations as discontinued operations.
Page 26
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 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, 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
$954 million (approximately $586 million after tax) during the second quarter ended June 30, 2004, due to
termination of the lease and the planned decommissioning of the asset.
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. As
a result of the change in useful life, EME changed the estimated useful life of the remaining plant assets to the
end of 2004. Accordingly, EME plans to depreciate $20 million of plant assets over the period May through
December 2004. At June 30, 2004, EME had not accrued for exit costs related to the expected reduction in
personnel as such amounts were not determinable at that time.
EME anticipates that the termination payment and decommissioning will result in a substantial income tax
deduction, thereby providing additional tax-allocation payments through the income tax-allocation agreement when
such loss can be used by Edison International in its consolidated and combined income tax returns. 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 small peaking plants in Illinois due to a number of factors, including the effect
of higher long-term natural gas prices on the competitiveness of these units and the current oversupply of
generation. Since capacity value represents a key revenue component for these small peaking plants, the revised
outlook resulted in a write-down of the book value of these assets from $286 million to their estimated fair
market value of $41 million. The estimated fair value was determined based on discounting estimated future cash
flows using a 17.5% discount rate. In addition,
Page 27
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2003 consolidated statements of income.
Note 8. Discontinued Operations
On July 10, 2003, the CPUC approved SCE's sale of certain oil storage and pipeline facilities to Pacific
Terminals LLC for $158 million. In third quarter 2003, SCE recorded a $44 million after-tax gain to
shareholders. In accordance with an accounting standard related to the impairment and disposal of long-lived
assets, this oil storage and pipeline facilities unit's results have been accounted for as a discontinued
operation in the financial statements for the three and six months ended June 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 June 30, 2004 and 2003, revenue from discontinued operations was zero and $8 million,
respectively, and pre-tax income was zero and $3 million, respectively. For the six months ended June 30, 2004
and 2003, revenue from discontinued operations was zero and $18 million, respectively, and pre-tax income was
zero and $9 million, respectively.
The discontinued operations balance sheet at June 30, 2004 and December 31, 2003 is comprised of current assets
of $1 million and $5 million, respectively, other noncurrent assets of $10 million and $11 million, respectively,
current liabilities of $1 million and $3 million, respectively, and noncurrent liabilities of $10 million and
$10 million, respectively.
Page 28
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 six-month periods ended June 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 six-month periods ended June 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 (parent) has a 100% ownership interest
in EME. Beginning in the second quarter of 2004, Mission Energy Holding Company (parent) and EME will be
presented as one business segment on a consolidated basis, and references to MEHC will represent the consolidated
entity. This change is due primarily to the elimination of EME's so-called ring fencing provisions in EME's
Certificate of Incorporation and credit agreement discussed below under "Current Developments--MEHC: Current
Developments." 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 and 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 29
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 31
SCE 33
MEHC 45
Edison Capital 67
Edison International (Parent) 68
Results of Operations and Historical Cash Flow Analysis 70
Acquisition and Dispositions 77
Critical Accounting Policies 78
New Accounting Principles 79
Commitments and Guarantees 80
Other Developments 80
Page 30
CURRENT DEVELOPMENTS
SCE: CURRENT DEVELOPMENT
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, authorizing an annual increase of approximately $73 million in base rates. As a
result of the implementation of the 2003 GRC decision, SCE recorded pre-tax net regulatory adjustments of
$180 million during the second quarter of 2004. 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. This will result in an approximate $55 million pre-tax gain in
the third quarter of 2004. In addition, SCE expects to record approximately $48 million in pre-tax gains related
to the rate recovery of 1997-1998 generation-related capital additions and the related revenue requirement in the
third quarter of 2004, as a further result of the implementation of the 2003 GRC decision. See "SCE: Regulatory
Matters--Transmission and Distribution--2003 General Rate Case Proceeding" for further details.
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 2004, EME made dividend payments totaling $69 million 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. 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.
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. Subsequent to June 30, 2004, EME announced the following:
o On July 20, 2004, EME entered into an agreement to sell its 51% interest in Contact Energy to Origin
Energy Limited for total consideration of approximately NZ$1.7 billion (approximately $1.1 billion), which
includes the assumption of NZ$535 million of debt. Completion of the sale, currently expected in the fourth
quarter of 2004, is subject to closing conditions and action by the New Zealand Takeovers Panel.
Page 31
o 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 BV, 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. 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. Net
proceeds from these two transactions are expected to be approximately $2.5 billion to EME after taxes,
transaction expenses and purchase price adjustments. EME's initial estimate of the after-tax gain on sale of its
international projects is approximately $550 million. Net proceeds from the sale will be used to repay the
$800 million secured loan at Mission Energy Holdings International, Inc. and other indebtedness. EME will retain
its ownership of the Lakeland project (see "Results of Operations and Historical Cash Flow Analysis--Results of
Operations--Earnings (Loss) from Discontinued Operations") and some inactive international subsidiaries.
Completion of Midwest Generation Refinancing
On April 27, 2004, Midwest Generation completed the issuance of $1 billion aggregate principal amount of its
8.75% second priority senior secured notes and entered into a new credit agreement, which includes a
$700 million, first priority senior secured term loan facility and a $200 million, first priority senior secured
working capital facility. Proceeds from these transactions were used to refinance $693 million of indebtedness
(plus accrued interest and fees) and to make termination payments under the Collins Station lease in the amount
of approximately $960 million. The new working capital facility replaced an existing working capital facility.
Completion of these financings was a major goal for 2004. See "MEHC: Liquidity--Key Financing
Developments--Midwest Generation Financing Developments" for further details related to these financings. The 2004
results include a $954 million (pre-tax) loss on lease termination related to the Collins Station lease.
Management does not believe the Collins Station is economically competitive in the current marketplace given the
current generation overcapacity in the MAIN region. In light of this, management terminated the Collins lease
and plans to cease operations of the Collins Station by December 31, 2004. Also, see "MEHC:
Liquidity--Termination of the Collins Station Lease" for details related to termination of the Collins Station
lease.
EME Financing Developments
On April 27, 2004, EME replaced its $145 million corporate credit facility with a new three-year $98 million
secured corporate credit facility. In addition, EME repaid the remaining $28 million due under the Coal and
Capex facility (guaranteed by EME) in April 2004. Accordingly, this credit agreement has been terminated and EME
no longer has a contingent liability related to this credit agreement.
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. For further discussion see "MEHC: Other Development--PJM
Regulatory Matters."
Page 32
SOUTHERN CALIFORNIA EDISON COMPANY
SCE: Liquidity Issues
SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs and access to
capital markets or external financings. At June 30, 2004, SCE's credit and long-term issuer ratings from
Standard & Poor's and Moody's Investors Service were BBB and Baa3, respectively. On March 22, 2004, Moody's
Investors Service placed SCE's credit rating under review for possible upgrade.
At June 30, 2004, SCE had cash and equivalents of $401 million and long-term debt, including current maturities,
of $5.6 billion. SCE has a $700 million credit facility that expires in December 2006. As of June 30, 2004, the
credit facility was not utilized, except for $2 million supporting letters of credit. SCE's 2004 estimated cash
outflows consist of:
o $125 million of 5.875% bonds due in September 2004;
o Approximately $246 million of rate reduction notes that are due at various times in 2004, but which have
a separate cost recovery mechanism approved by state legislation and CPUC decisions;
o Projected capital expenditures of $1.9 billion, including the investment in the Mountainview project and
related capital expenditures (see "Acquisition and Dispositions");
o Dividend payments to SCE's parent company;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations and cash outflows for undercollections (if incurred) through cash
and equivalents on hand, operating cash flows and short-term borrowings, when necessary. Projected capital
expenditures are expected to be financed through cash flows and the issuance of long-term debt.
On March 30, 2004, SCE transferred, through a dividend to Edison International, $300 million of common equity.
The purpose of this dividend was to continue to rebalance SCE's capital structure in accordance with CPUC
requirements. On May 21, 2004, SCE paid a $145 million dividend to Edison International.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In its most
recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common
equity component of 48%. SCE determines compliance with this capital structure based on a 13-month
weighted-average calculation. At June 30, 2004, SCE's 13-month weighted-average common equity component of total
capitalization was 53%. At June 30, 2004, SCE had the capacity to pay $462 million in additional dividends and
continue to maintain its CPUC-authorized capital structure based on the 13-month weighted-average method. Based
on recorded June 30, 2004 balances, SCE's common equity to total capitalization ratio, for rate-making purposes,
was 48%. SCE had the capacity to pay $28 million of additional dividends based on June 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
Page 33
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, of which approximately
$196 million of these pollution-control bonds were reoffered. In March 2004, SCE issued $300 million of 4.65%
first and refunding mortgage bonds due in 2015 and $350 million of 5.75% first and refunding mortgage bonds due
in 2035. A portion of the proceeds from the March 2004 first and refunding mortgage bond issuances were used to
fund the acquisition and construction of the Mountainview project, with the remainder of the proceeds to be used
for ongoing capital expenditures for generation, transmission and distribution facilities, and for general
corporate purposes.
As of June 30, 2004, SCE posted approximately $24 million ($22 million in cash and $2 million in letters of
credit) as collateral to secure its obligations under power-purchase contracts and to transact through the
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's liquidity may be affected by, among other things, matters described in "SCE: Regulatory Matters."
SCE: MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, generating fuel commodity prices and volume
and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. However,
fluctuations in fuel prices and volumes and counterparty credit losses temporarily affect cash flows, but should
not affect earnings. See "SCE: Market Risk Exposures" in the year-ended 2003 MD&A for a complete discussion of
SCE's market risk exposures.
SCE: REGULATORY MATTERS
This section of the MD&A describes SCE's regulatory matters in three main subsections:
o generation and power procurement;
o transmission and distribution; and
o other regulatory matters.
Generation and Power Procurement
Proposed Legislation
The California legislature is currently considering a bill that is intended to create a durable regulatory
framework to stimulate investment in generation resources. The latest publicly available version of Assembly
Bill 2006, which is entitled the "Reliable Electric Service Act," proposes to affirm the obligation of utilities
to plan and provide adequate, efficient, and cost-effective supply and demand resources and requires utilities to
prepare a long-term resource plan to achieve a diversified portfolio of cost-effective supply and demand
resources. The proposed bill also states that the CPUC must establish and maintain rates that ensure the full
recovery of reasonable investments made by utilities, and the full cost of contracting for nonutility
generation. Because the bill continues to be debated and amended in the California legislature, SCE cannot
predict with certainty what effects the bill will have on SCE if it is enacted into law.
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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 Ninth Circuit seeking to overturn the stipulated judgment of the federal
district court that approved the 2001 CPUC settlement agreement. In September 2002, the Ninth Circuit issued its
opinion affirming the federal district court on all claims, with the exception of the challenges founded upon
California state law, which the Ninth Circuit referred to the California Supreme Court.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate
California law in any of the respects raised by the Ninth Circuit. The matter was returned to the Ninth Circuit
for final disposition, and in December 2003, the Ninth Circuit unanimously affirmed the original stipulated
judgment of the federal district court. In January 2004, the Ninth Circuit issued its mandate, relinquishing
jurisdiction of the case and returning jurisdiction to the federal district court. No petitions were filed
within the 90-day period in which parties could seek discretionary review by the United States Supreme Court of
the federal district court's decision. Accordingly, the appeals of the stipulated judgment approving the 2001
CPUC settlement agreement have been resolved in SCE's favor.
Energy Resource Recovery Account Proceedings
As discussed in the "Energy Resource Recovery Account Proceedings" disclosure in the year-ended 2003 MD&A, the
CPUC established the Energy Resource Recovery Account (ERRA) as the rate-making mechanism to track and recover
SCE's generation-related costs.
SCE submitted 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.
On October 3, 2003, SCE submitted its first ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from September 1, 2001 through June 30, 2003 to be
reasonable. Because this is the first annual review of this activity, pursuant to new California state law, the
CPUC's interpretation and application of California state law is uncertain. Pursuant to the assigned
commissioner's scoping memo issued on December 9, 2003, the CPUC's Office of Ratepayer Advocates (ORA) was allowed
to review the accounting calculations used in the Procurement-Related Obligations Account (PROACT) mechanism.
The ORA testimony, filed on March 19, 2004, included an audit of these accounting calculations, in which ORA
recommended disallowances that totaled approximately $14 million of costs recovered through the PROACT mechanism
during the period from September 1, 2001 through June 30, 2003. In April 2004, SCE reached an agreement with the
ORA (subject to CPUC approval) to reduce the PROACT disallowances to approximately $3.6 million. The total
amount recovered through PROACT was $3.6 billion. 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 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
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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. A decision on ERRA operations through
June 30, 2003 is expected in the third quarter of 2004.
On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find
that 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. A decision on this application is expected by the end of 2004.
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 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 (the amount of energy needed to serve
SCE's customers from sources other than its own generating plants, power-purchase contracts and California
Department of Water Resources (CDWR) contracts) position on January 1, 2003, pursuant to CPUC orders and
California statutes passed in 2002. The current regulatory and statutory framework requires SCE to assume
limited responsibilities for CDWR contracts allocated by the CPUC, and provide full power procurement
responsibilities on the basis of annual short-term procurement plans, long-term resource plans and increased
procurement of renewable resources. See "Generation Procurement Proceedings" disclosure in the year-ended 2003
MD&A for further discussion of the matters discussed below.
Short-Term Procurement Plan
In December 2003, the CPUC adopted a 2004 short-term procurement plan for SCE. SCE is currently 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.
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. 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's,
Pacific Gas and Electric's (PG&E) and San Diego Gas & Electric Co.'s (SDG&E) are set to begin August 30, 2004. A
decision is expected by year-end 2004.
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Resource adequacy issues are being addressed in this proceeding on a parallel track, including a proposal to
accelerate the phase-in of the resource adequacy requirement from January 2008 to June 2006. SCE expects a CPUC
decision on resource adequacy issues in September 2004.
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 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.
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. In February 2001, a California law was enacted which
authorized the CDWR to: (1) enter into contracts to purchase electric power and sell power at cost directly to
SCE's retail bundled customers; and (2) issue bonds to finance those electricity purchases. 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.
The CPUC is currently considering the appropriate methodology for allocating CDWR's power charge revenue
requirement for 2004 through 2013. PG&E, TURN, and SCE submitted a settlement agreement advocating that the costs
of CDWR's long-term contracts be allocated on a cost-follow-contracts basis, 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. On July 20, 2004, the CPUC issued two draft decisions that would
reject the proposed settlement agreement. Instead, the 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 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 ten-year period, it would institute a methodology that does not provide the appropriate
contract administration incentives to investor-owned utilities. A final decision on this matter is expected in
the third quarter of 2004.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2003 MD&A,
on May 17, 2002, SCE filed an application with the CPUC to address certain issues (mainly coal and slurry-water
supply issues) facing the future extended operation of Mohave Generating Station (Mohave), which is partly owned
by SCE. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from
making approximately $1.1 billion in Mohave-related investments (SCE's share is $605 million), including the
installation of pollution-control
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equipment that must be put in place in order for Mohave to continue to operate beyond 2005, pursuant to a 1999
consent decree concerning air quality.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues,
but no resolution has been reached. SCE and other parties submitted further testimony and made various other
filings in 2003 in SCE's application proceeding. Pursuant to the assigned administrative law judge's March 9,
2004 ruling, on April 16, 2004 SCE updated its position and testimony on cost data and, where data are
unavailable, cost estimates for Mohave on the following options: (1) the cost of permanent shutdown; (2) cost of
installation of required pollution controls and related capital improvements to allow the facility to continue as
a coal-fired plant beyond 2005; (3) if option 2 is undertaken, cost of temporary shutdown for complete
installation of pollution controls, and any costs related to restarting the facility; and (4) other alternatives
and their costs. SCE's testimony presented a summary of work performed to date and provided an update on the
status of the coal and water supply issues. The testimony also stated that SCE does not now have detailed cost
projections for any of the cost categories identified in the March 9, 2004 ruling due to the uncertainties
remaining on these issues. The testimony reiterated SCE's belief that, even if the coal and water supply issues
can be satisfactorily resolved in the near future, thereby avoiding a permanent shutdown, a temporary shutdown of
at least approximately three years is likely. Evidentiary hearings took place in June and July of 2004, and a
decision on this matter is not expected before November 2004. 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 an impact on earnings.
San Onofre Steam Generators
As discussed in the "San Onofre Steam Generators" disclosure in the year-ended 2003 MD&A, on February 27, 2004,
SCE filed an application with the CPUC in which it asked the CPUC to issue a decision by July 2005 finding that
it is reasonable for SCE to replace the San Onofre Unit 2 and 3 steam generators and establishing appropriate
ratemaking for the replacement costs. In this filing, SCE also asked the CPUC for approval to establish a
memorandum 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. SCE has not determined whether it will enter into contracts for steam
generator fabrication in the absence of CPUC approval of this memorandum account. If not, completion of steam
generator replacement would likely be delayed beyond the previously planned 2009 completion date. SCE is
evaluating the impact of a delay.
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 and, in July 2004, amended its application to the CPUC to reflect the fact that co-owner
approval is not required to proceed with steam generator replacement. SDG&E has elected to reduce its 20%
ownership share rather than participate in the steam generator replacement project. The other two co-owners, the
cities of Riverside and Anaheim (who collectively own approximately 5% of the units), have not yet made an
election. The period during which such election can be made expires in October 2004. If steam generator
replacement proceeds, upon completion, SDG&E's ownership share of San Onofre Units 2 and 3, and the ownership
shares of the cities if they elect to opt out, would be reduced in accordance with the formula set forth in the
operating agreement. If the parties do not agree on the application of the formula, it will be subject to
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arbitration. The transfer of all or any portion of SDG&E's ownership share to SCE as a result of SDG&E's
election not to participate in steam generator replacement would require CPUC approval.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its application for a 2003 GRC, requesting an increase of $286 million in SCE's base
rate revenue requirement, which was subsequently revised to an increase of $251 million. The application also
proposed an estimated base rate revenue decrease of $78 million in 2004, and a subsequent increase of $116
million in 2005. The forecast reduction in 2004 was largely attributable to the expiration of the San Onofre
Nuclear Generating Station (San Onofre) incremental cost incentive pricing (ICIP) rate-making mechanism at
year-end 2003 and a forecast of increased sales.
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. As a result of the implementation of the 2003 GRC decision, SCE recorded pre-tax net
regulatory adjustments of $180 million as a credit to provision for regulatory adjustment clauses during the
second quarter of 2004. 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. This will result in an approximate $55 million pre-tax gain in the third
quarter of 2004. In addition, SCE expects to record approximately $48 million in pre-tax gains related to the
rate recovery of 1997-1998 generation-related capital additions and the related revenue requirement in the third
quarter of 2004, as a further result of the implementation of the 2003 GRC decision.
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. SCE has proposed that the GRC rate increase be combined
with other rate changes from pending rate proceedings and be effective August 5, 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 decision
on this matter is expected in the fourth quarter of 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.
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In an April 22, 2004 CPUC 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 currently pursuing the appeal before the D.C. Circuit Court.
Wholesale Electricity and Natural Gas Markets
In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of
electricity in the California Power Exchange (PX)/ISO markets. On March 26, 2003, the FERC staff issued a report
concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas
markets in California and on the west coast during 2000-2001 and describing many of the techniques and effects of
that market manipulation. SCE is participating in several related proceedings seeking recovery of refunds from
sellers of electricity and natural gas who manipulated the electric and natural gas markets. Under the 2001 CPUC
settlement agreement, mentioned in "--Generation and Power Procurement--CPUC Litigation Settlement Agreement," 90%
of any refunds actually realized by SCE will be refunded to customers, except for the El Paso Natural Gas Company
settlement agreement discussed below.
El Paso Natural Gas Company (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 any 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. Additional settlement payments totaling approximately $134 million are due from El Paso
over a 20-year period. In addition, 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
approximately $37 million in refunds and other payments
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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 April 26, 2004 settlement terms provide for refunds and other payments totaling $285
million, with a proposed allocation to SCE of approximately $40 million. The 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 that is expected
to exceed $40 million. The Duke settlement remains subject to the approval of the FERC and the CPUC.
Additionally, 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.
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 June 30, 2004, the bark beetle CEMA had a balance of $91 million and the fire-related CEMA had a balance of
$10 million. SCE submitted an advice filing with the CPUC in June 2004 to recover approximately $18 million in
bark beetle-related costs incurred in 2003. SCE estimates that it will spend up to $135 million on this project
in 2004, and will submit an advice filing to recover these costs in 2005. SCE expects to submit an application
with the CPUC in the third 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
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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 did not file a challenge to
the decision as to the first priority issue, so the first priority requirement is now final. The California
Supreme Court has 60 days (extendable to 90 days) within which to accept or reject the petition for review as to
the jurisdiction issue.
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 service reliability, customer satisfaction,
and employee safety. SCE received two letters over the last year from one or more anonymous employees alleging
that personnel in the service planning group of SCE's transmission and distribution business unit altered or
omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent
survey organization. The results of these surveys are used, along with other factors, to determine the amounts
of any incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer
satisfaction rewards aggregating $10 million for 2001 and 2002 are pending before the CPUC and have not been
recognized in income by SCE. SCE also had anticipated that it could be eligible for customer satisfaction
rewards of about $10 million for 2003.
SCE 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 widespread misconduct, SCE proposed to
refund to ratepayers all of the $12 million in PBR rewards that may be attributed 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 about $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 with respect to the customer satisfaction survey misconduct by severing the
employment of several supervisory personnel, updating system processes and related documentation
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for survey reporting, and implementing additional supervisory controls over data collection and processing.
As mentioned above, SCE is also eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based
on its performance in comparison to CPUC-approved standards of service reliability and employee safety. In light
of the problems uncovered with the customer satisfaction surveys, SCE commenced investigations into the accuracy
and completeness of SCE's service reliability and employee safety reporting. While the safety and service
reliability investigations are not yet complete, SCE has preliminarily concluded that some of its data collection
procedures for recording employee injuries may have been inadequate and some misreporting may have occurred. SCE
has not reached any conclusions as to the effect of those problems on the validity of safety incentive
performance payments. SCE has advised the CPUC staff of the existence of the safety and reliability
investigations, promised to provide copies of the investigative reports, and committed to return to ratepayers or
forgo any PBR rewards that were earned based on data shown to be inaccurate. Both the safety and the service
reliability investigations are being pursued aggressively and will be completed as soon as possible. Since the
inception of PBR payments in 1997, SCE has received $20 million in employee safety incentive performance payments
and, based on SCE's records, may be entitled to an additional $15 million. As for service reliability, since the
inception of PBR payments in 1997, SCE has received $8 million in rewards based on frequency of outage data and
has applied for an additional $5 million award based on frequency of outage data for 2001.
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, service reliability and/or employee
safety. 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.
SCE: OTHER DEVELOPMENT
Navajo Nation Litigation
In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of
Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt
River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for
Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and
Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less
than $1 billion, as well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation
lands should be terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition,
SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal,
except for Salt River Project Agricultural Improvement and Power District's motion for its separate dismissal
from the lawsuit.
Some of the issues included in this case were addressed by the United States Supreme Court in a separate legal
proceeding filed by the Navajo Nation in the Court of Federal Claims against the United States Department of
Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning
negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody. On
March 4, 2003, the Supreme Court concluded, by majority decision, that 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,
Page 43
the D.C. District Court denied SCE's and Peabody's April 2003 motions to dismiss or, in the alternative, for
summary judgment. The District Court subsequently issued a scheduling order that imposes a December 31, 2004
discovery cut-off and sets a status conference for January 21, 2005. No trial date was established in the
scheduling order. The parties to the D.C. District Court action are currently engaged in scheduling and
completing the remaining discovery in the case.
The Federal Circuit Court of Appeals, acting on a suggestion on remand filed by the Navajo Nation, held in a
October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on three specific statutes
or regulations and therefore did not address the question of whether a network of other statutes, treaties and
regulations imposed judicially enforceable fiduciary duties on the United States during the time period in
question. The Government and the Navajo Nation both filed petitions for rehearing of the October 24, 2003 Court
of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the Court of Appeals
issued an order remanding the case against the Government to the Federal Court of Claims, 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 in the remanded Court of Federal Claims case as a party 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.
Page 44
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
its 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 June 30, 2004, MEHC (parent) had cash and cash equivalents of $98 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 2004, EME made dividend payments totaling $69 million to MEHC (parent). These payments were used
together with cash on hand to meet the Term Loan Put-Option payment as 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. The ring-fencing provisions
were implemented to protect EME's credit rating from the negative events then affecting Edison International and
its subsidiary, SCE. Despite the ring-fencing provisions, EME's Standard & Poor's credit rating fell to "B" and
therefore, EME's management believed that the provisions, which included dividend restrictions and a requirement
to maintain an independent director, were no longer necessary.
EME's Liquidity
At June 30, 2004, EME and its subsidiaries had cash and cash equivalents of $468 million and EME had available
the full amount of borrowing capacity under a $98 million corporate credit facility. EME's consolidated debt at
June 30, 2004 was $6.9 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.
Page 45
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 June 30, 2004, Midwest
Generation had borrowed $40 million under the working capital facility and had reimbursement obligation 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 was guaranteed by Midwest Generation and had
been 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
Page 46
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, which is scheduled to expire at the end of
2004. EME recorded a pre-tax loss of approximately $954 million (approximately $586 million after tax) during
the second quarter ended June 30, 2004, due to termination of the lease and the planned decommissioning of the
asset. Included in the pre-tax loss is a $3 million inventory reserve for excess spare parts at the Collins
Station.
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. As a result of
the change in useful life, EME changed the estimated useful life of the remaining plant assets to the end of
2004. Accordingly, EME plans to depreciate $20 million of plant assets over the period May through December
2004. At June 30, 2004, EME had not accrued for exit costs related to the expected reduction in personnel as
such amounts were not determinable at that time.
EME anticipates that the termination payment and decommissioning will result in a substantial income tax
deduction, thereby providing additional tax-allocation payments through the income tax-allocation agreement when
such loss can be used by Edison International in its consolidated and combined income tax returns. EME's
receivable to be realized under the tax-allocation agreement was $494 million at June 30, 2004, approximately
$370 million of which is attributable to the Collins Station lease termination and decommissioning. 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 "Commitments and Guarantees--EME's Guarantees
and Indemnities" in the year-ended 2003 MD&A further discussion of this tax indemnity agreement.
2004 Capital Expenditures
The estimated capital and construction expenditures of EME's subsidiaries for the final two quarters of 2004 are
$35 million. These expenditures are planned to be financed by existing subsidiary credit agreements and cash
generated from their operations.
EME's Credit Ratings
Overview
Credit ratings for EME and its subsidiaries, Midwest Generation, LLC and Edison Mission Marketing & Trading, are
as follows:
Moody's Rating S&P Rating
- ----------------------------------------------------------------- -------------------- ----------------
EME B2 B
Midwest Generation, LLC:
First priority senior secured rating Ba3 B+
Second priority senior secured rating B1 B-
Edison Mission Marketing & Trading Not Rated B
- ----------------------------------------------------------------- -------------------- ----------------
EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will
remain in effect for any given period of time or that one or more of these ratings will not be lowered. On
August 2, 2004, following EME's announcements related to the sale of its international project portfolio,
Page 47
Standard & Poor's placed the credit ratings on CreditWatch with positive implications. 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 ($94 million as of June 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.
Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support
for forward contracts entered into by Edison Mission Marketing & Trading on its behalf. In that regard, as of
June 30, 2004, Midwest Generation has provided Edison Mission Marketing & Trading $44 million, which Edison
Mission Marketing & Trading has used to provide a portion of the credit for counterparties noted above. 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)18 million have been issued as of
June 30, 2004.
EME anticipates that sales of power from its Illinois plants, Homer City facilities and First Hydro plants in the
United Kingdom may require additional credit support, depending upon market conditions and the strategies adopted
for the sale of this power. Changes in forward market prices and margining requirements could further increase
the need for credit support for the price risk management and trading activities related to these projects. EME
currently projects potential working capital required to support price risk management and trading activity to be
between $100 million and $200 million from time to time.
Credit Rating of Edison Mission Marketing & Trading
Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission
Marketing & Trading restricts the ability of EME Homer City Generation L.P. to enter into permitted trading
activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of
the Homer City facilities. These documents include a requirement that the counterparty to such transactions, and
EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all
of the output from the Homer City facilities through Edison Mission Marketing & Trading, which has a below
investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell
forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback
owner participant to permit EME Homer City to sell directly into the market or through Edison Mission Marketing &
Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance consistent with the
requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner
participant that will allow EME Homer City to enter into such sales, under specified conditions, 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."
Pagr 48
EME's Liquidity as a Holding Company
Overview
At June 30, 2004, EME had corporate cash and cash equivalents of $114 million to meet liquidity needs. EME had no
borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at June 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 "--EME's Liquidity as a Holding Company--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 June 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.
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 Six Months Ended June 30, 2004 2003
------------------------------------------------------------------------------ -------------- ---------------
Domestic Projects
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) $ 49 $ 127
Holding companies of other consolidated operating projects -- 1
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects) 21 20
Sunrise Power Company 5 --
Holding companies for Westside projects 7 13
Holding companies of other unconsolidated operating projects 1 4
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions from Domestic Projects $ 83 $ 165
Page 49
In millions Six Months Ended June 30, 2004 2003
------------------------------------------------------------------------------ ------------- ----------------
International Projects (Mission Energy Holdings International)
Distributions from Consolidated Operating Projects:
First Hydro Holdings (First Hydro project) $ 29 $ 18
Loy Yang B 3 12
Contact Energy 27 16
Valley Power -- 5
Kwinana(1) 4 2
Holding companies of other consolidated operating projects 8 --
------------------------------------------------------------------------------ -------------- ---------------
Distributions from Unconsolidated Operating Projects:
ISAB Energy -- 1
IVPC4 (Italian Wind project) 1 3
Derwent 1 --
Doga 15 --
Paiton -- 9
Tri Energy 2 --
Holding companies of other unconsolidated operating projects 7 --
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions from International Projects $ 97 $ 66
------------------------------------------------------------------------------ -------------- ---------------
Total Distributions $ 180 $ 231
------------------------------------------------------------------------------ -------------- ---------------
--------------
(1) Distributions for the six months ended June 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 are
dependent on the inclusion of 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's (parent) 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
Page 50
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 June 30, 2004:
Subsidiary Financial Ratio Covenant Actual
---------------------------------- ---------------------------- -------------------------- -----------------
Midwest Generation, LLC Interest Coverage Ratio Greater than or 2.76 to
(Illinois plants) equal to 1.25 to 1 1(1)
Midwest Generation, LLC Secured Leverage Ratio Less than or 5.31 to 1
(Illinois plants) equal to 8.75 to 1
EME Homer City Generation L.P. Senior Rent Service Greater than 1.7 to 1 2.78 to 1
(Homer City facilities) Coverage Ratio
Edison Mission Energy Funding Debt Service Coverage Greater than or 2.53 to 1
Corp. Ratio equal to 1.25 to 1
(Big 4 Projects)
Mission Energy Holdings Interest Coverage Ratio Greater than or 3.38 to
International equal to 1.3 to 1 1(2)
---------------------------------- ---------------------------- -------------------------- -----------------
--------------
(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.
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 new 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.
Page 51
Covenants in Credit Facility
In order for Midwest Generation to make a distribution, it must be in compliance with covenants specified under
its new credit facility. Compliance with the covenants in its credit facility includes maintaining the following
two financial performance requirements:
o At the end of each fiscal quarter, Midwest Generation's consolidated interest coverage ratio for the
immediately preceding four consecutive fiscal quarters must be at least 1.25 to 1. The consolidated
interest coverage ratio is defined as the ratio of consolidated net income (plus or minus specified amounts
as set forth in the credit agreement), to consolidated interest expense (as more specifically defined in the
credit agreement).
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 facility) 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.
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.
Covenants in Indenture
Midwest Generation's new indenture contains restrictions on its ability to make a distribution substantially
similar to those in the credit facility. However, the indenture does not provide the ability to distribute 100%
of excess cash flow upon the occurrence of certain events. Under the indenture, however, failure to achieve the
conditions required for distributions will not result in a default, nor does the indenture contain any other
financial performance requirements.
Mission Energy Holdings International Interest Coverage Ratio
Under the credit agreement governing its term loan, Mission Energy Holdings International has agreed to maintain
a minimum interest coverage ratio of 1.30 to 1 beginning March 2004 for the trailing twelve-month period.
Page 52
The following table sets forth the major components of the interest coverage ratio for the twelve months ended
June 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:
June 30, 2004 December 31, 2003
----------------------------------- -----------------------------------
In millions Pro Forma Pro Pro Forma Pro
Actual Adjustment Forma Actual Adjustment Forma
---------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations
Historical distributions from
international projects(1) $ 201 $ -- $ 201 $ 158 $ -- $ 158
Other fees and cash payments
considered distributions under the
term loan 16 -- 16 20 -- 20
Administrative and general expenses (1) -- (1) (2) -- (2)
---------------------------------------------------------------------------------------------------------------------
Total Funds Flow from Operations $ 216 $ -- $ 216 $ 176 $ -- $ 176
---------------------------------------------------------------------------------------------------------------------
Term Loan Interest Expense $ 33 $ 31 $ 64 $ 4 $ 60 $ 64
---------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 3.38 2.75
---------------------------------------------------------------------------------------------------------------------
--------------
(1) See "--EME's Liquidity as a Holding Company--Historical Distributions Received By EME."
(2) The pro forma adjustment assumes that the $800 million loan was outstanding at the beginning of 2003.
Pro forma interest expense was calculated using the interest rate floor of 7% plus amortization of deferred
financing costs.
The above details of Mission Energy Holdings International's interest coverage ratio are provided as an aid to
understanding the components of the computations that are set forth in the term loan credit agreement. The terms
Funds Flow from Operations and Interest Expense are as defined in the term loan and are not the same as would be
determined in accordance with generally accepted accounting principles.
MEHC's Interest Coverage Ratio
The following details of MEHC's interest coverage ratio are provided as an aid to understanding the computations
set forth in the indenture governing MEHC's (parent) senior secured notes. This information is not intended to
measure the financial performance of MEHC and, accordingly, should not be used in lieu of the financial
information set forth in Edison International's consolidated financial statements. The terms Funds Flow from
Operations, Operating Cash Flow and Interest Expense are as defined in the indenture and are not the same as
would be determined in accordance with generally accepted accounting principles.
Page 53
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 June 30, 2004 and the year-ended December 31, 2003:
June 30, December 31,
In millions 2004 2003
--------------------------------------------------------------------- --------------------- --------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants(3) $ 281 $ 242
Homer City 138 153
First Hydro 16 (8)
Other consolidated operating projects 218 165
Price risk management and energy trading (12) 11
Distributions from unconsolidated Big 4 projects 99 98
Distributions from other unconsolidated operating
projects 182 178
Interest income 5 4
Interest expense at Mission Energy Holdings International (36) --
Operating expenses (160) (144)
--------------------------------------------------------------------- --------------------- --------------------
Total EME funds flow from operations $ 731 $ 699
Operating cash flow from unrestricted subsidiaries (1) (2)
Funds flow from operations of projects sold (22) (1)
MEHC (parent) 1 1
--------------------------------------------------------------------- --------------------- --------------------
Total funds flow from operations $ 709 $ 697
Interest Expense:
EME $ 277 $ 286
EME - affiliate debt 1 1
MEHC (parent) interest expense 161 160
Interest savings on projects sold (5) --
--------------------------------------------------------------------- --------------------- --------------------
Total interest expense $ 434 $ 447
--------------------------------------------------------------------- --------------------- --------------------
Interest Coverage Ratio 1.63 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.
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond
indenture governing MEHC's (parent) senior secured notes and the credit agreement governing the term loan. The
interest coverage ratio prohibits MEHC (parent), EME and its subsidiaries from incurring
Page 54
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.
Summarized combined financial information (unaudited) of Mission Energy Holdings International, Inc. and it
subsidiaries and Edison Mission Project Co. is set forth below:
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------
Revenue $ 353 $ 362 $ 775 $ 674
Expenses 315 361 689 655
- --------------------------------------------------------------------------------------------------------------
Net income $ 38 $ 1 $ 86 $ 19
- --------------------------------------------------------------------------------------------------------------
June 30, December 31,
In millions 2004 2003
- --------------------------------------------------------------------------------------------------------------
Current assets $ 501 $ 628
Noncurrent assets 6,319 6,723
- --------------------------------------------------------------------------------------------------------------
Total assets $ 6,820 $ 7,351
- --------------------------------------------------------------------------------------------------------------
Current liabilities $ 425 $ 587
Noncurrent liabilities 4,529 4,994
Minority interest 733 746
Equity 1,133 1,024
- --------------------------------------------------------------------------------------------------------------
Total liabilities and equity $ 6,820 $ 7,351
- --------------------------------------------------------------------------------------------------------------
The majority of noncurrent liabilities are comprised of project financing arrangements that are nonrecourse to
EME.
MEHC: MARKET RISK EXPOSURES
Introduction
MEHC's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel
for its uncontracted generating plants. These market risks arise from fluctuations in electricity and fuel
prices, emission allowances, transmission rights, interest rates and foreign currency exchange rates. EME
manages these risks in part by using derivative financial instruments in accordance with established policies and
procedures. See "MEHC: 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
For a complete discussion of these issues, read this quarterly report in conjunction with the year-ended 2003
MD&A.
Page 55
Commodity Price Risk
General Overview
EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price
risks are actively monitored by a risk management committee to ensure compliance with EME's risk management
policies. Policies are in place which define risk tolerances for each EME regional business unit. Procedures
exist which allow for monitoring of all commitments and positions with regular reviews by the risk management
committee. In order to provide more predictable earnings and cash flow, EME may hedge a portion of its plant
fuel requirements and/or the electric output of its merchant plants, the output of which is not committed to be
sold under long-term contracts. When appropriate, EME manages the spread between electric prices and fuel
prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is
no assurance that contracts to hedge changes in market prices will be effective.
EME's revenue and results of operations of its merchant power plants will depend upon prevailing market prices
for capacity, energy, ancillary services, fuel oil, coal and natural gas and associated transportation costs and
emission credits in the market areas where EME's merchant plants are located. Among the factors that influence
the price of power in these markets are:
o prevailing market prices for fuel oil, coal and natural gas and associated transportation costs;
o the extent of additional supplies of capacity, energy and ancillary services from current competitors or
new market entrants, including the development of new generation facilities;
o transmission congestion in and to each market area;
o the market structure rules to be established for each market area;
o the cost of emission credits or allowances;
o the availability, reliability and operation of nuclear generating plants, where applicable, and the
extended operation of nuclear generating plants beyond their presently expected dates of decommissioning;
o weather conditions prevailing in surrounding areas from time to time; and
o the rate of electricity usage as a result of factors such as regional economic conditions and the
implementation of conservation programs.
Introduction
Electric power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with
utilities and power marketers under short-term transactions with terms of two years or less or, as has been the
case for the Homer City facilities, to the PJM and/or the New York Independent System Operator (NYISO) markets.
As discussed further below, beginning in 2003, EME has been selling a significant portion of the power generated
from its Illinois plants into wholesale power markets, including PJM on 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
Page 56
policies. Policies are in place which define the risk tolerance for EME's merchant activities. Procedures exist
which allow for monitoring of all commitments and positions with regular reviews by the risk management
committee. Despite this, there can be no assurance that all risks have been accurately identified, measured
and/or mitigated.
Illinois Plants
Energy generated at the Illinois plants has historically been sold under three power-purchase agreements between
EME's wholly owned subsidiary, Midwest Generation, and Exelon Generation Company, under which Exelon Generation
is obligated to make capacity payments for the plants under contract and energy payments for the energy produced
by these plants and taken by Exelon Generation. The power-purchase agreements began on December 15, 1999 and
expire in December 2004. The capacity payments provide 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 49% and 64% of the energy and capacity sales from the Illinois plants in the first six 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. As discussed in detail below, 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) remains subject to power-purchase agreements with Exelon
Generation in 2004. 2004 is the final contract year under these power-purchase agreements.
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 risks related to the price of energy
and capacity from those units. EME expects that capacity prices for merchant energy sales will, in the near
term, be substantially less than those Midwest Generation currently receives under its existing agreements with
Exelon Generation. EME further expects that the lower revenue resulting from this difference will be offset in
part by energy prices, which EME believes will, in the near term, be higher for merchant energy sales than those
Midwest Generation currently receives under its existing agreements. 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 (AEP), 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.
Page 57
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.
The average market prices at the Northern Illinois Hub delivery point during the months of May and June of 2004
were $34.05 per MWh and $28.58 per MWh, respectively. Energy prices were 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.
Page 58
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into
the Northern Illinois Hub at June 30, 2004:
24-Hour Northern
Illinois Hub
2004 Forward Energy Prices*
------------------------------------------------------------------------------
July $ 37.25
August 40.26
September 30.16
October 27.66
November 27.94
December 31.72
2005 Calendar "strip"(1) $ 33.09
------------------------------------------------------------------------------
--------------
(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. To the extent it does not do so, the unhedged portion will be subject to the risks and benefits of spot
market price movements. The extent to which Midwest Generation will hedge its market price risk through forward
over-the-counter sales depends on several factors. First, Midwest Generation will evaluate over-the-counter
market prices to determine whether sales at forward market prices are sufficiently attractive compared to
assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging
transactions will depend upon its and 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 released units will be affected by the cost of production, including costs incurred to
comply with environmental regulations. The costs of production of the released units vary and, accordingly,
depending on market conditions, the amount of generation that will be sold from the released units is expected to
vary from unit to unit. In this regard, Midwest Generation suspended operations of Will County Units 1 and 2 at
the end of 2002 pending improvement in market conditions.
Under PJM's proposed revisions to the PJM tariff, the integration of Commonwealth Edison into PJM, which was
implemented on May 1, 2004, could result in market power mitigation measures being imposed on future power sales
by Midwest Generation in the Northern Illinois Control Area (NICA) energy and capacity markets. In addition,
power produced by Midwest Generation not under contract with Exelon Generation has been sold in the past using
transmission obtained from Commonwealth Edison under its open-access tariff filed with the FERC, and the
application of the PJM tariff to Commonwealth Edison's transmission system could also affect the rates, terms and
conditions of transmission service received by Midwest Generation. EME and Midwest Generation continue to oppose
the imposition of market power mitigation measures proposed by PJM for the NICA energy and capacity
Page 59
markets. EME is unable to predict the outcome of these efforts, the effect of integration of Commonwealth Edison
into PJM on an "islanded" basis, the timing or effect of integration of AEP into PJM, or any final integration
configuration for PJM on the markets into which Midwest Generation sells its power. See "--MEHC: Other
Development--PJM Regulatory Matters."
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 in Illinois 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.
The following table depicts the average market prices per megawatt-hour in PJM during the first six 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
------------------------------------------------------------------------------------------
Six-Month Average $ 43.71 $ 37.41
------------------------------------------------------------------------------------------
--------------
* 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 six months of 2004 were higher than the average historical market prices during the first six
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
Page 60
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 includes:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot
prices at the Homer City busbar, plus,
o sales to third parties under such forward contracts at designated delivery points (generally the PJM
West Hub) less the cost of purchasing power at spot prices at the same designated delivery points to fulfill
obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly
prices at specific locations throughout PJM by considering factors including generator bids, load requirements,
transmission congestion and losses, has the effect of raising prices at those delivery points affected by
transmission congestion. During the past 12 months, an increase in transmission congestion at delivery points
east of the Homer City facilities has resulted in prices at the PJM West Hub (which includes delivery points east
of the Homer City facilities) being higher than those at the Homer City busbar on an average of two percent.
By entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk,"
which occurs when forward contracts are executed on a different basis (in this case PJM West Hub) than the actual
point of delivery (Homer City busbar). In order to mitigate basis risk resulting from forward contracts using
PJM West Hub as the delivery point, EME has participated in purchasing 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 June 30, 2004:
24-Hour PJM West
2004 Forward Energy Prices*
-------------------------------------------------------------------------------
July $ 50.29
August 52.62
September 42.04
October 41.26
November 40.97
December 42.28
2005 Calendar "strip"(1) $ 44.40
-------------------------------------------------------------------------------
--------------
(1) Market price for energy purchases for the entire calendar year, as quoted for
sales into the PJM West Hub.
* Energy prices were determined by obtaining broker quotes and other public sources
for the PJM West Hub delivery point. Forward prices at PJM West are generally
higher than the prices at the Homer City busbar.
The ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part
of the sale-leaseback transaction depends on revenue generated by the Homer City facilities, which depend in part
on the market conditions for the sale of capacity and energy. These market conditions are beyond EME's control.
Page 61
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 one hour prior to the delivery or receipt of power. In the final hour after the notification of all
contracts, the system operator can accept bids and offers in the Balancing Mechanism to balance generation and
demand and resolve any transmission constraints. There is a mandatory settlement process for recovering
imbalances between contracted and metered volumes with strong incentives for being in balance, and a Balancing
and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also
purchase system reserve and response services to maintain the quality of the electrical supply directly from
generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for up to
a year and can consist of both fixed amounts and variable amounts represented by prices for services that are
only paid for when actually called upon by the grid operator. A key feature of the trading arrangements is the
requirement for firm physical delivery, which means that a generator must deliver, and a consumer must take
delivery of, its net contracted positions or pay for any energy imbalance at the imbalance prices calculated by
the system operator based on the prices of bids and offers accepted in the Balancing Mechanism. This provides an
incentive for parties to contract in advance and for the development of forwards and futures markets. Under
these arrangements, there has been an increased emphasis on credit quality, including the need for parent company
guarantees or letters of credit for companies below investment grade.
The wholesale price of electricity has decreased significantly in recent years. The reduction has been driven
principally by surplus generating capacity and increased competition. During 2003, prices were more volatile.
There was further downward pressure on wholesale prices in the first part of the year followed by some recovery
during the summer in prices and in the peak/off peak differentials for the 2003-2004 winter period. That
recovery tailed off towards the end of the year with a considerable narrowing in the peak/off peak differentials
which has continued during the first half of 2004. Compliance with First Hydro's bond financing documents is
subject to market conditions for electric energy and ancillary services, which are beyond First Hydro's control.
New Zealand
Contact Energy generates about 30% of New Zealand's electricity and is one of the largest retailer of natural gas
and electricity in New Zealand. A substantial portion of Contact Energy's generation output is matched with the
demand of its retail electricity customers or sold through forward contracts with other wholesale electricity
counterparties. The forward contracts and/or option contracts have varying terms that expire on various dates
through March 31, 2007, although the majority of the forward contracts are short term (less than two years).
The New Zealand government has recently established a new governance body to be known as the Electricity
Commission along with a set of rules to govern the market. The Electricity Governance Regulations and Rules were
finalized in 2003. The Regulations came into force on January 16, 2004, and the Rules came into force during
February and March of 2004. Among other things, the Electricity Commission has been given:
o responsibility for managing dry year reserve, which it is undertaking through the procurement of reserve
capacity; and
Page 62
o additional reserve powers ranging from information disclosure to imposing hedge obligations on major
users and generators.
The New Zealand government announced in July 2003 that it would purchase a new 155 MW power plant before winter
2004 to increase electricity security. The plant is situated at Whirinaki, Hawkes Bay. The Electricity
Commission will include this plant in its portfolio of reserve energy. The Whirinaki plant is located on a site
leased to the government from Contact Energy and is operated under contract by Contact Energy. The plant was
officially opened on June 1, 2004 and is now operational.
Contact Energy has begun retailing electricity in Victoria, Australia under the Red Energy brand. Contact has
entered into arrangements with an Australian-based generation company to mitigate exposure to wholesale power
prices.
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 63
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 June 30, 2004, the credit ratings of EME's counterparties were as follows:
In millions June 30, 2004
- ------------------------------------------------------------------------------------------------
S&P Credit Rating
A or higher $ 27
A- 6
BBB+ 55
BBB 13
BBB- --
Below investment grade 6
- ------------------------------------------------------------------------------------------------
Total $ 107
- ------------------------------------------------------------------------------------------------
Exelon Generation accounted for 16% and 21% of nonutility power generation revenue for the first half of 2004
and 2003, respectively. The percentage is less in the first half of 2004 because a smaller number of plants are
subject to contracts with Exelon Generation. See "--Commodity Price Risk-- Illinois Plants." Any failure of
Exelon Generation to make payments under the power-purchase agreements could adversely affect EME's results of
operations and financial condition.
EME's contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest
sell power under long-term power-purchase agreements. Generally, each plant sells its output to one
counterparty. Accordingly, a default by a counterparty under a long-term power-purchase agreement, including a
default as a result of a bankruptcy, would likely have a material adverse affect on the operations of such power
plant.
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. Interest
expense included $17 million and $23 million of additional interest expense for the six months ended June 30,
2004 and 2003, respectively, as a result of interest rate hedging mechanisms. EME has entered into several
interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of
the underlying debt.
EME had short-term obligations of $31 million at June 30, 2004, consisting of promissory notes related to Contact
Energy. The fair values of these obligations approximated their carrying values at June 30, 2004, and would not
have been materially affected by changes in market interest rates. The fair market values of long-term fixed
interest rate obligations are subject to interest rate risk. The fair market value and carrying value of MEHC's
total long-term obligations (including current portion) was $8.1 billion at
Page 64
June 30, 2004. The fair market value and carrying value of MEHC's parent only total long-term obligations was
$1.2 billion at June 30, 2004.
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. The sales price for Contact Energy is
denominated in New Zealand dollars. EME has entered into a foreign currency hedge to protect against a
depreciation in the value of the New Zealand dollar versus the United States dollar for this sales agreement.
The remaining sales agreement is denominated in United States dollars.
During the first six months of 2004, foreign currencies in Australia and New Zealand decreased in value compared
to the United States dollar by 8% and 4%, respectively (determined by the change in the exchange rates from
December 31, 2003 to June 30, 2004). The decrease in value of these currencies was the primary reason for the
foreign currency translation loss of $7 million during the first six months of 2004. Included in the foreign
currency translation loss was a foreign currency translation gain of approximately $8 million related to the
translation of an intercompany loan with a foreign affiliate denominated in Euro. During the first six months of
2004, the Euro increased in value by 4% (determined by the change in the exchange rate from December 31, 2003 to
June 30, 2004).
Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency
commitments associated with transactions in the ordinary course of business. The contracts are primarily in
Australian, New Zealand and United States dollars with varying maturities through February 2006. At June 30,
2004, the outstanding notional amount of the contracts totaled $36 million and the fair value of the contracts
totaled $(1) million.
In addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of
business. These cross currency swap contracts involve swapping fixed and floating-rate United States and
Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018.
EME will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of
hedging strategies in the future.
Page 65
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.
On March 19, 2004, in a separate but related matter, the FERC issued an order having the effect of postponing to
December 1, 2004 the effective date for elimination of regional through and out rates in the region encompassed
by PJM (as expanded by the addition of Commonwealth Edison and as to be further expanded by the addition of AEP)
and the Midwest Independent System Operator (MISO). The effect of this order is that the so-called rate
pancaking was not eliminated prior to Commonwealth Edison's integration into PJM, nor will it be eliminated prior
to AEP's scheduled date for integration into PJM. Rate pancaking occurs when energy must move through multiple,
separately priced transmission systems to travel from its point of production to its point of delivery, and each
transmission owner along the line charges separately for the use of its system. 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 have met on several occasions, attempting to
create an acceptable long-term rate structure for the combined PJM/MISO footprint. Those discussions are taking
place pursuant to settlement procedures and a schedule administered by a FERC administrative law judge and are
expected to continue through September 2004. It is not possible at this time to predict the outcome of such
discussions. Until through and out rates are eliminated, EME will continue to have to pay transmission charges
for power sold for delivery outside of Commonwealth Edison's former control area, now known under PJM as NICA.
On March 24, 2004, the FERC, in another order, rejected a proposal by PJM for certain market mitigation
procedures to be applied to the new NICA. On April 23, 2004, PJM filed a request for rehearing of one aspect of
the March 24 order and an "Explanation" relating to another aspect of such order, and supplemented its filing on
April 26, 2004. EME and Midwest Generation filed a motion for a procedural schedule allowing 30 days for EME and
Midwest Generation to prepare and submit analyses responding to PJM's filings, which was granted by the FERC.
Following such submissions, PJM filed additional material purporting to support its requested mitigation
mechanisms, and EME and Midwest Generation responded to each of those submissions. The issues remain pending for
decision by the FERC. It is not possible at this time to predict the outcome of this matter or the impact of the
market monitor's proposed mitigation measures should they or some form of them be adopted.
On July 27, 2004, AEP reached a settlement with staff of the Virginia State Corporation Commission (VSCC) that
would allow AEP to transfer control of its transmission lines in the state to PJM. The settlement eliminates the
need for the FERC to act to ensure that AEP is able to enter PJM on October 1, 2004, the target date set by both
AEP and PJM. The settlement, if approved by the VSCC, will end the battle between FERC and Virginia over state
and federal rights governing regional transmission organization (RTO) membership and will help facilitate AEP's
entry into PJM by October 1, 2004. The parties to the settlement requested VSCC to act on it within 15 days.
Apart from the uncertainties regarding the market mitigation issues discussed previously, the direct impact on
Midwest Generation of the above-described matters will for the most part be limited to the delay in the
elimination of regional through and out rates. This is not expected to have a material effect on Midwest
Generation's financial results with respect to the period between the May 1, 2004 integration of Commonwealth
Edison and the mandated elimination of the through and out rates on December 1, 2004. The impact on power prices
in the new NICA and in the surrounding bilateral markets by reason of the islanded integration of Commonwealth
Edison is difficult to predict, but it is not currently anticipated that it will have a material effect upon
Midwest Generation's financial results in the period prior to the integration of AEP into PJM, currently
scheduled for October 1, 2004.
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EDISON CAPITAL
EDISON CAPITAL: LIQUIDITY
Since 2001, as a result of the California energy crisis, Edison Capital reduced debt and accumulated cash, which
resulted in a significant de-leveraging of Edison Capital. In light of Edison Capital's improved liquidity,
Edison Capital made a $225 million dividend payment to Edison International in 2003 while maintaining a cash and
cash equivalent balance of $328 million at June 30, 2004. The improvement in liquidity is primarily from Edison
International's utilization of tax benefits that had been delayed in previous years because of the California
energy crisis. Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation
payments from the parent company and expected cash flow from operating activities. To the extent that certain
funding conditions are satisfied, Edison Capital has unfunded current and long-term commitments of $100 million
for energy and infrastructure investments as of June 30, 2004. During the second quarter, Edison Capital
repurchased the limited partnership interests of three previously syndicated affordable housing projects for
approximately $20 million of funded and unfunded commitments and is anticipating repurchasing the limited
partnership interests of up to four additional properties for up to $8 million. Edison Capital is evaluating its
capital structure, the potential for additional borrowings and potentially making dividend payments to Edison
International.
At June 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 paid $4
million in tax-allocation payments to Edison International during the first six months of 2004. The amount paid
is net of payments received from 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.
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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 $618 million of 6-7/8% notes due September 15, 2004. During January through April 2004, Edison
International repurchased approximately $47 million of these notes, leaving a remaining balance of $571
million of notes due in September 2004;
o Dividends to common shareholders. The Board of Directors of Edison International declared a
20(cent)-per-share common stock dividend in both the first and second quarters of 2004. The $65 million in
dividend payments were made on April 30, 2004 and August 2, 2004, respectively.
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 June 30, 2004, Edison International (parent) had approximately $1.3
billion of cash and cash equivalents on hand. The ability of subsidiaries to make dividend payments to Edison
International is dependent on various factors as described below.
The CPUC regulates SCE's capital structure by requiring that SCE maintain prescribed percentages of common
equity, preferred stock and long-term debt in the utility's capital structure. SCE may not make any
distributions to Edison International that would reduce the common equity component of SCE's capital structure
below the prescribed level. The CPUC also requires that SCE establish its dividend policy as though it were a
comparable stand-alone utility company and give first priority to the capital requirements of the utility as
necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing
of dividend payments by SCE to Edison International include, among other things, SCE's cash requirements, SCE's
access to capital markets, and actions by the CPUC. SCE paid cash dividends of $300 million and $145 million to
Edison International on March 30, 2004 and May 21, 2004, respectively.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At June 30, 2004, its
interest coverage ratio was 1.63 to 1. See "MEHC: Liquidity--MEHC's Interest Coverage Ratio." 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 2004, EME paid a dividend to MEHC (parent) of $69 million.
Edison International's investment in MEHC, through a wholly owned subsidiary, as of June 30, 2004, was $272
million. MEHC's (parent) investment in EME, as of June 30, 2004, was approximately $1.4 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
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financial statements have been prepared on the basis that EME will continue as a going concern and that the
uncertainty about Edison Mission Midwest Holdings' ability to repay or refinance Edison Mission Midwest Holdings'
$693 million of debt due in December 2004 raises substantial doubt about EME's ability to continue as a going
concern. In April 2004, all of the outstanding debt of Edison Mission Midwest holdings was repaid in full through
new financings obtained by Midwest Generation. 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--Midwest Generation 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 $300 million.
Edison Capital did not declare or pay 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.
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EDISON INTERNATIONAL (CONSOLIDATED)
The following sections of the MD&A are on a consolidated basis. The section begins with a discussion of Edison
International's consolidated results of operations and historical cash flow analysis. This is followed by
discussions of 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 a consolidated loss of $374 million or $1.15 per share for the three-month period
ended June 30, 2004, compared to consolidated earnings of $24 million or 7(cent)per share for the three-month period
ended June 30, 2003. The decrease was primarily due to a 2004 lease termination, partially offset by a 2003
asset impairment and the net effect of regulatory adjustments that occurred in 2003 and 2004. Excluding these
items, earnings decreased 5(cent)per share primarily due to the expiration of the San Onofre Nuclear Generating
Station incentive mechanism at SCE, partially offset by improved operating results at several of MEHC's projects.
Edison International recorded a consolidated loss of $276 million or 85(cent)per share for the six-month period ended
June 30, 2004, compared to consolidated earnings of $80 million or 25(cent)per share for the six-month period ended
June 30, 2003. The 2004 results include a charge at MEHC related to the termination of the Collins Station lease
and earnings at SCE from regulatory adjustments related to the implementation of SCE's 2003 GRC decision. The
2003 results include a charge at MEHC related to the impairment of eight small peaking plants in Illinois and
earnings at SCE from various positive regulatory adjustments. Excluding these items, earnings increased 5(cent)per
share, primarily from favorable operating results at several of MEHC's operating plants, offset by lower earnings
at SCE primarily from the expiration of the San Onofre Nuclear Generating Station incentive mechanism.
The table below presents Edison International's earnings (loss) and earnings (loss) per share for the three- and
six-month periods ended June 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 June 30, 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 242 $ 223 $ 0.74 $ 0.68
MEHC (610) (189) (1.88) (0.58)
Edison Capital 11 12 0.04 0.04
Edison International (parent) and other (17) (22) (0.05) (0.07)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings (Loss)
from Continuing Operations (374) 24 (1.15) 0.07
- -------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations - SCE -- 2 -- 0.01
Loss from Discontinued Operations - MEHC -- (2) -- (0.01)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ (374) $ 24 $ (1.15) $ 0.07
- -------------------------------------------------------------------------------------------------------------------
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In millions, except per share amounts Earnings (Loss) Earnings (Loss) per Share
- -------------------------------------------------------------------------------------------------------------------
Six-Month Period Ended June 30, 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 341 $ 321 $ 1.05 $ 0.98
MEHC (603) (222) (1.85) (0.67)
Edison Capital 22 27 0.07 0.08
Edison International (parent) and other (35) (41) (0.12) (0.12)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings (Loss)
from Continuing Operations (275) 85 (0.85) 0.27
- -------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations -- 4 -- 0.01
- -------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (1) (9) -- (0.03)
- -------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ (276) $ 80 $ (0.85) $ 0.25
- -------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
SCE earnings from continuing operations were $242 million and $341 million in the three- and six-month periods
ended June 30, 2004, respectively, compared to $223 million and $321 million in the same periods in 2003. The
expiration of the ICIP mechanism at San Onofre Nuclear Generating Station resulted in a decrease in earnings of
$47 million. This decrease was more than offset by a quarter-over-quarter benefit in regulatory adjustments of
$55 million and improved operating results. The earnings impacts of these positive regulatory items in the
second quarter of 2004 ($107 million) from the implementation of the 2003 GRC decision were partially offset by
positive regulatory items that occurred in the second quarter of 2003 ($52 million) which included the tax
impacts of a FERC rate case and prior-period Palo Verde incentive awards. The reasons for the six-month period
increase are the same as the three-month period reasons discussed above.
MEHC had a loss from continuing operations of $610 million and $603 million in the three- and six-month periods
ended June 30, 2004, respectively, compared to a loss of $189 million and $222 million in the same periods in
2003. The three-month period increased loss was primarily due to the charge related to the termination of the
lease of the 2,698-MW gas-fired Collins Station held by Midwest Generation, the absence of earnings from the Four
Star Oil & Gas project as compared to 2003 due to the sale of EME's interest in that project in the first quarter
of 2004, and higher interest expense from $800 million in new debt at Mission Energy Holdings International. The
decreases were partially offset by the 2003 charge related to the impairment of Midwest Generation's small
peaking plants and improved operating results at ISAB, Contact Energy, First Hydro and Homer City. The six-month
period increased loss was also due to outages in 2004 at the Homer City project, partially offset by higher
revenue at MEHC's Illinois plants due to higher energy prices and increased generation, and the gain on the sale
of EME's interest in the Four Star Oil & Gas project. On an annual basis, MEHC's earnings are seasonal with
higher earnings expected during the summer months.
Earnings in the second quarter of 2004 for Edison Capital were substantially unchanged from the results in the
same period last year. Earnings for the six-month period ended June 30, 2004 decreased primarily due to a
maturing lease portfolio which produces lower income.
The loss for Edison International (parent) and other during both the three- and six-month periods was primarily
due to lower net interest expense.
Operating Revenue
SCE's retail sales represented approximately 83% and 85% of electric utility revenue for the three- and six-month
periods ended June 30, 2004, respectively, and approximately 91% and 92% for the three- and six-month periods
ended June 30, 2003, respectively. Due to warmer weather during the summer
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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 six-month periods ended June 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 and used to recover costs incurred in 2003.
There was no surcharge revenue recognized in 2004. The three- and six-month period decreases were partially
offset by the recognition of three months of revenue resulting from the consolidation of SCE's variable interest
entities on March 31, 2004 (see "Critical Accounting Policies" and "New Accounting Principles") and 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. The six-month period decrease was 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 $546 million and $1.2 billion for the three- and six month periods ended June 30, 2004, compared to
$421 million and $845 million for the same periods in 2003.
Nonutility power generation revenue decreased in the three-month period ended June 30, 2004, and increased in the
six-month period ended June 30, 2004. The three-month period decrease was mainly due to lower net gains from
price risk management and energy trading activities in 2004, as compared to 2003, and the deconsolidation of two
of EME's variable interest entities (see "Critical Accounting Policies" and "New Accounting Principles"). The
decrease was partially offset by increased electric revenue from EME's Contact Energy mostly due to increased
retail revenue and an increase in the value of the New Zealand dollar compared to the United States dollar. In
addition, nonutility power generation revenue increased due to higher electric revenue from EME's Homer City due
to increased generation attributable to higher planned outages in 2003 and higher energy prices. The six-month
period increase was primarily due to strengthening of foreign currencies in New Zealand, Australia and United
Kingdom, increased electric revenue from EME's Contact Energy as described above and EME's Loy Yang B due to
higher generation. In addition, electric revenue increased due to higher revenue from EME's Illinois plants due
to higher generation and energy prices and higher revenue from the First Hydro plant. Partially offsetting these
increases were no second quarter 2004 revenue from the deconsolidated variable interest entities on March 31,
2004.
Nonutility power generation revenue during the third quarter is materially higher than revenue related to other
quarters of the year because warmer weather during the summer months results in higher revenue from EME's Homer
City facilities and Illinois plants. By contrast, EME's First Hydro plants have higher revenue during their
winter months.
Financial services and other revenue increased in both the three- and six-month periods ended June 30, 2004, as
compared to the same periods 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").
Page 72
Operating Expenses
Fuel expense increased in both the three- and six-month periods ended June 30, 2004, as compared to the same
periods in 2003, primarily due to the consolidation of SCE's variable interest entities, increased coal expense
at SCE's Mohave coal facility due increased generation in 2004, as compared to 2003, resulting from a planned
outage and maintenance repairs in the second quarter of 2003, and increased fuel costs from EME's Homer City
facilities primarily due to higher sulfur-dioxide emission prices. The increases were partially offset by a
decrease in fuel costs at EME due to the deconsolidation of EME's variable interest entities and decreased fuel
costs from EME's Contact Energy primarily due to lower wholesale electricity and gas sales. The six-month
increase was also due to purchased-power costs from EME's First Hydro plant, partially offset by lower coal
expense at SCE resulting from a first quarter 2004 scheduled major overhaul at SCE's Four Corners coal facility.
Purchased-power expense decreased in both the three- and six-month periods ended June 30, 2004, as compared to
the same periods in 2003. The decreases were mainly due to the consolidation of SCE's variable interest entities
and 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"). The decreases
were partially offset by an increase in ISO-related costs, higher expenses resulting from an increase in the
number of gas bilateral contracts in 2004, as compared to 2003, and higher costs associated with gas hedging
activities resulting from higher realized and unrealized gains in 2003, as compared to 2004 mainly due to the
expiration of significant gas hedging instruments in 2003. The quarterly decrease was also partially offset by
higher expenses related to power purchased by SCE from qualifying facilities (QFs), as discussed below.
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. During the second
quarter of 2004, spot natural gas prices were higher compared to the same period in 2003.
Provisions for regulatory adjustment clauses - net decreased in both the three- and six-month periods ended
June 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 approximately $240 million for both the
three- and six-month periods. The decreases also reflect a net effect of approximately $180 million of
regulatory adjustments 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 $50 million and $70 million associated with the bark beetle infestation
for the three- and six-month periods ended June 30, 2004, respectively (see "SCE: Regulatory Matters--Other
Regulatory Matters--Catastrophic Event Memorandum Account"). SCE's 2003 GRC regulatory adjustments primarily
relate to recognition of revenue from the rate recovery of pension contributions during the time period that the
pension plan was fully funded, the resolution over 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 three- and six-month period decreases were partially offset by the El Paso settlement
payment received, of which $66 million was refunded to customers through the ERRA account. The six-month period
decrease was also due to the recovery of approximately $115 million of gas hedging costs through regulatory
mechanisms in 2003, 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 six-month periods ended June 30, 2004,
compared to the same periods in 2003, mainly due to increases at SCE. SCE's other operating and maintenance
expense increase in both the three- and six-month periods ended June 30, 2004, as compared to the same periods in
2003 was mainly due to costs incurred in 2004 related to the removal of trees and
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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 general expenses, primarily
due to lower worker's compensation claims in 2004. The six-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 primarily consisted of a $951 million loss 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 loss on lease termination in 2003 primarily consisted of a $245
million charge related to the impairment of eight small peaking plants owned by Midwest Generation resulting from
a revised long-term outlook for capacity revenue from the peaking plants. The lower capacity revenue outlook is
the result of a number of factors, including higher long-term natural gas prices and the current generation
overcapacity in the MAIN (Mid-America Interconnected Network) region market.
Depreciation, decommissioning and amortization expense increased in both the three- and six-month periods ended
June 30, 2004, as compared to the same periods in 2003, due to an increase in SCE's nuclear decommissioning
expense and an increase in SCE's depreciation expense associated with additions to transmission and distribution
assets.
Other Income and Deductions
Interest and dividend income decreased in both the three- and six-month periods ended June 30, 2004, as compared
to the same periods in 2003, due to the absence of interest income on the PROACT balance at SCE in 2004, as
compared to 2003. At July 31, 2003 the PROACT balance was overcollected, and was transferred to the ERRA on
August 1, 2003.
Other nonoperating income decreased for the three-month period ended June 30, 2004 and increased in the six-month
period ended June 30, 2004. The three-month period decrease was mainly due to the timing of recording Palo Verde
nuclear incentives. During the second quarter of 2003, SCE recorded 1999, 2000 and 2001 Palo Verde nuclear
incentives approved by the CPUC. During the first quarter of 2004, SCE recorded 2001 and 2002 Palo Verde nuclear
incentives approved by the CPUC. The six-month period increase reflects higher Palo Verde nuclear incentives at
SCE in 2004, as compared to 2003, and a gain related to the sale of EME's interest in Edison Mission Energy Oil &
Gas (see "Acquisition and Dispositions" for further details).
Interest expense - net of amounts capitalized increased in the three- and six-month periods ended June 30, 2004.
The increases were due to the issuance of the $800 million secured loan received by EME's indirect subsidiary,
Mission Energy Holdings International in December 2003 and a change in classification of dividend payments on
preferred securities to interest expense from dividends on preferred securities subject to mandatory redemption
effective July 1, 2003. The increases were partially offset by lower interest expense at SCE due to lower
long-term debt balances outstanding in 2004, as compared to 2003. The three-month period increase was also due
to the issuance of $1.7 billion in new debt at EME's Midwest Generation in April 2004, which was mostly offset by
lower interest expense at Midwest Generation due to a reduction of approximately $1.7 billion in debt partially
from the proceed of such transactions.
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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") and the
49% ownership of Contact Energy by the public of New Zealand.
Income Taxes
Income tax benefit increased for both the three- and six-month periods ended June 30, 2004, compared to the same
periods in 2003, primarily due to a decrease in pre-tax income, primarily from the write-off of the Collins
Station lease, changes in property-related flow-through taxes at SCE and changes in foreign taxes at EME. The
decreases were partially offset by a reduction in SCE's tax expense in 2003 related to the favorable resolution
of a FERC rate case.
Edison International's composite federal and state statutory rate was approximately 40% for both periods
presented. The lower effective tax rate of 39% and 38% realized in the three- and six-month periods ended June
30, 2004, respectively, was due to low-income housing and production tax credits at Edison Capital and dividend
payment to the employee stock ownership plan and property-related flow-through taxes at SCE. The rate decrease
was partially offset by cumulative adjustments to deferred tax balances at EME and Edison Capital.
Earnings (Loss) from Discontinued Operations
Discontinued operations in 2003 reflect earnings 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, 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 (used) provided by operating activities:
In millions Six Months Ended June 30, 2004 2003
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ (222) $ 1,351
Discontinued operations (1) (9)
- ----------------------------------------------------------------------------------------------------------
$ (223) $ 1,342
- ----------------------------------------------------------------------------------------------------------
The change in cash (used) 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.
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Cash Flows from Financing Activities
Net cash provided (used) by financing activities:
In millions Six Months Ended June 30, 2004 2003
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ 1,466 $ (519)
- ----------------------------------------------------------------------------------------------------------
$ 1,466 $ (519)
- ----------------------------------------------------------------------------------------------------------
Cash used by financing activities from continuing operations in 2004 mainly consisted of long-term and short-term
debt payments at SCE and EME.
During the first quarter of 2004, SCE issued $300 million of 5% bonds due in 2014, $525 million of 6% bonds due
in 2034 and $150 million of floating rate bonds due in 2006. The proceeds from these issuances were used to
redeem $300 million of 7.25% first and refunding mortgage bonds due March 2026, $225 million of 7.125% first and
refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding mortgage bonds due October 2018,
and $100 million of junior subordinated deferrable interest debentures due June 2044. In 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, of which
approximately $196 million of these pollution-control bonds were reoffered. In March 2004, SCE issued $300
million of 4.65% first and refunding mortgage bonds due in 2015 and $350 million of 5.75% first and refunding
mortgage bonds due in 2035. A portion of the proceeds from the March 2004 first and refunding mortgage bond
issuances were used to fund the acquisition and construction of the Mountainview project. 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 and $28 million related to the EME's Coal and Capex facility in April 2004. Financing activities in
2004 also included dividend payments of $130 million paid by Edison International to its shareholders.
During the first quarter of 2003, Edison International (parent only) repurchased approximately $132 million of
the outstanding $750 million of its 6-7/8% notes due September 2004. No repurchases were made during the second
quarter of 2003. During the six-month period ended June 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. EME's financing activity in the six-month period ended June 30, 2003
consisted of net borrowings of $275 million on EME's $487 million corporate credit facility, $275 million in
borrowings by Contact Energy, EME's 51% owned subsidiary, used to finance Contact Energy's acquisition of the
Taranaki Combined Cycle power station, and a debt service payment of $23 million made in March 2003 related to
one of EME's subsidiaries.
Page 76
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Six Months Ended June 30, 2004 2003
- ----------------------------------------------------------------------------------------------------------
Continuing operations $ (890) $ (934)
Discontinued operations 1 5
- ----------------------------------------------------------------------------------------------------------
$ (889) $ (929)
- ----------------------------------------------------------------------------------------------------------
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 $721 million in additions to SCE's property and plant, primarily for
transmission and distribution assets and $47 million in capital additions at EME. In addition, investing
activities include $285 million of acquisition costs related to the Mountainview project at SCE, and $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.
Additions to SCE's property and plant for the six-month period ended June 30, 2003, were approximately $540
million, primarily for transmission and distribution assets. EME's capital additions for the six-month period
ended June 30, 2003 were $79 million primarily for new plant and equipment related to EME's Illinois plants, its
Homer City facilities, and Contact Energy. EME's year-to-date 2003 investing activity also included $275 million
paid by Contact Energy for the acquisition of Taranaki Combined Cycle power station, and $39 million in equity
contribution to EME's Sunrise and CBK projects.
ACQUISITION AND DISPOSITIONS
On July 30, 2004, EME entered into an agreement to sell its remaining international power generation portfolio,
owned by a wholly owned Dutch subsidiary, MEC International BV, 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 resulting in an expected 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. The sale is expected to close in the fourth quarter of 2004.
On July 20, 2004, EME entered into an agreement to sell its 51% interest in Contact Energy to Origin Energy
Limited for total consideration of NZ$1.7 billion (approximately $1.1 billion), which includes the assumption of
NZ$535 million of debt. Completion of the sale, currently expected in the fourth quarter of 2004, is subject to
closing conditions, including action by the New Zealand Takeovers Panel. EME has entered into a foreign currency
hedge in order to protect against fluctuations in the exchange rate between United States and New Zealand
dollars, in which the sales price is denominated.
Together, these two transactions mentioned above represent the sale of all of EME's interests in its
international projects. Net proceeds from these two transactions are expected to be approximately $2.5 billion
to EME after taxes and transaction expenses and purchase price adjustments. EME's initial estimate of the
after-tax gain on sale of its international projects is approximately $550 million. Net proceeds from the sale
will be used to repay the $800 million secured loan at Mission Energy Holdings International, Inc. and other
indebtedness. EME will retain its ownership of the Lakeland project and some inactive subsidiaries.
Page 77
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 2006. The construction work in progress for this project is recorded in nonutility
property on Edison International's June 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.
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 273 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 22 contracts with gas-fired cogeneration plants that contain
variable pricing provisions based on the prices of natural gas. SCE requested from the entities that hold these
contracts the financial information necessary to determine whether SCE must consolidate these projects. All 22
entities declined to provide SCE with the necessary financial information. However, four of the 22 contracts are
with entities 49%-50% owned by 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 18
projects in order to determine whether they should be consolidated by SCE. The remaining 251 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.
Page 78
EME reviewed all of its power projects to determine whether they are variable interest entities and, if so,
whether EME is the consolidating entity. EME has four equity-method partnerships that sell power to SCE. EME
will continue to use the equity method for these projects, which have been consolidated by SCE effective
March 31, 2004. Doga, a 180-MW gas-fired power plant in Turkey (of which EME owns 80%), has a power sales
contract that is considered a variable interest due to the energy price provisions that absorb the risk of
changes in fuel costs and the transfer of ownership of the cogeneration plant to the energy purchaser at the end
of the power sales contract. Kwinana, a 116 MW gas-fired power plant in Australia (of which EME owns 70%), has
power sales contracts that are considered variable interests due to the energy price provisions that absorb the
risk of changes in fuel costs. EME deconsolidated the Doga and Kwinana projects effective March 31, 2004 and
recorded its interests in these projects on the equity method beginning April 1, 2004. The remaining projects
either meet the definition of a business under the new accounting standard and thus fall outside the scope of the
new accounting standard or absorb insufficient variability for EME to be considered the consolidating entity.
Edison Capital analyzed all of its projects and consolidated two affordable housing partnerships and three wind
projects. Edison Capital determined it was the related party most closely associated with the business of the
VIEs for the two affordable housing partnerships and absorbs the majority of the expected losses and receives the
majority of the expected residual returns for the three wind projects. For the remaining projects, Edison
Capital determined it was not the related party entity most closely associated with the VIEs.
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 will adopt this guidance in
third quarter 2004. If Edison International's retiree health care plans provide prescription drug benefits that
are deemed to be actuarially equivalent to Medicare benefits, Edison International will recognize the subsidy in
the measurement of its accumulated obligation and record an actuarial gain. Proposed federal regulations
defining actuarial equivalency are expected in third quarter 2004, with final regulations expected to be released
by year-end 2004. Until the proposed regulations are issued, Edison International is unable to predict the
effect of the new law on its postretirement health care costs and obligations.
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
Page 79
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 June 30, 2004 are: 2005 - $1.3 billion; 2006 - $1.2 billion; 2007 - $2.5 billion; 2008 - $385 million;
2009 - $2.1 billion; and thereafter - $8.1 billion. These amounts have been updated to reflect financing
activities during the six months ended June 30, 2004.
OTHER DEVELOPMENTS
Environmental Matters
Edison International is subject to numerous environmental laws and regulations, which require it to incur
substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove
the effect of past operations on the environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements;
however, possible future developments, such as the enactment of more stringent environmental laws and
regulations, could affect the costs and the manner in which business is conducted and could cause substantial
additional capital expenditures. There is no assurance that additional costs would be recovered from customers
or that Edison International's financial position and results of operations would not be materially affected.
Environmental Remediation
Edison International records its environmental remediation liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International
reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of involvement and financial condition of
other potentially responsible parties. These estimates include costs for site investigations, remediation,
operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 33 identified sites at SCE
(26 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.
Page 80
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 $63 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 June 30, 2004 were $16 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts
in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's
regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs
ultimately recorded will not materially affect its results of operations or financial position. There can be no
assurance, however, that future developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
In August 2002, Edison International received a notice from the Internal Revenue Service (IRS) asserting
deficiencies in federal corporate income taxes for its 1994 to 1996 tax years. The vast majority of the asserted
tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of interest and
penalties), if any, would benefit Edison International as future tax deductions. Edison International believes
that it has meritorious legal defenses to those deficiencies and believes that the ultimate outcome of this
matter will not result in a material impact on Edison International's consolidated results of operations or
financial position.
Among the issues raised by the IRS in the 1994 to 1996 audit was Edison Capital's 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 expects the IRS to propose an adjustment 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
expected to be 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
Page 81
(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 may also propose 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 82
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 83
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 (2003 Form 10-K), and in Part II, Item 1 of Edison International's Quarterly Report on Form
10-Q for the period ending March 31, 2004 (First Quarter 10-Q).
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
Information about the CPUC's order instituting investigation regarding SCE's electric line maintenance practices
appears in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of
Operations" under the heading "SCE: Regulatory Matters--Transmission and Distribution--Electric Line Maintenance
Practices Proceeding" and is incorporated herein by this reference. Information about the CPUC's order
instituting investigation regarding SCE's electric line maintenance practices was previously reported in Part I,
Item 3 of the 2003 Form 10-K and in Part II, Item 1 of the First Quarter 10-Q.
County of San Bernardino Investigation
As previously reported in Part I, Item 3 of the 2003 Form 10-K and in Part II, Item 1 of the First Quarter 10-Q,
the County of San Bernardino Office of District Attorney notified SCE, in a letter dated September 23, 2003, of
its intent to file a misdemeanor criminal complaint and a civil complaint seeking injunctive relief for the
alleged failure to report a spill of oil from a transformer in an isolated area of San Bernardino County. SCE
entered into a stipulated judgment with the County of San Bernardino on May 18, 2004 concerning the alleged
failure to report the spill. Without admitting liability, the judgment provided that SCE pay the sum of
$125,604. The original penalty assessment according to the County of San Bernardino ranged from $5,604 to
$555,604.
Page 84
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
(e) Issuer purchases of equity securities
The following table contains information about all purchases made by or on behalf of Edison International or any
affiliated purchaser (as defined in Rule 10b-18(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 Purchased1 Share (or Unit)1 Programs Programs
- ------------------------ ---------------------- -------------------- ---------------------- -----------------------
April 1, 2004 to 1,694,032 $23.31 -- --
April 30, 2004
May 1, 2004 to 1,545,274 $22.94 -- --
May 31, 2004
June 1, 2004 to 1,995,595 $23.92 -- --
June 30, 2004
- ------------------------ ---------------------- -------------------- ---------------------- -----------------------
Total 5,234,901 $23.44 -- --
- ------------------------ ---------------------- -------------------- ---------------------- -----------------------
- -------------------
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 85
Item 4. Submission of Matters to a Vote of Security Holders
At Edison International's Annual Meeting of Shareholders on May 20, 2004, two matters were put to a vote of the
shareholders: the election of ten directors, and a shareholder proposal on Edison International's Shareholder
Rights Agreement.
Shareholders elected ten nominees to the Board of Directors. The number of broker non-votes for each nominee was
zero. The numbers of votes cast for and withheld from each Director-nominee were as follows:
Numbers of Votes
- ----------------------------------------------------------------------------------------------------------
Name For Withheld
- ----------------------------------------------------------------------------------------------------------
John E. Bryson 258,780,670 17,415,484
France A. Cordova 267,535,889 8,660,265
Bradford M. Freeman 258,214,546 17,981,608
Bruce Karatz 263,487,289 12,708,865
Luis G. Nogales 259,285,241 16,910,913
Ronald L. Olson 236,269,470 39,926,684
James M. Rosser 259,306,482 16,889,672
Richard T. Schlosberg, III 258,211,482 17,984,672
Robert H. Smith 258,106,741 18,089,413
Thomas C. Sutton 258,198,044 17,998,110
- ----------------------------------------------------------------------------------------------------------
The shareholder proposal on Edison International's Shareholder Rights Agreement, which failed to receive the
affirmative vote of a majority of the votes cast, was not adopted. The proposal received the following numbers
of votes:
FOR AGAINST ABSTENTIONS BROKER NON-VOTES
- --------------------------------------------------------------------------------------------------
71,079,597 157,735,989 4,700,843 42,679,725
Page 86
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Edison International
3.1 Restated Articles of Incorporation of Edison International effective May 9, 1996
(File No. 1-9936, filed as Exhibit 3.1 to Edison International Form 10-K for the year ended
December 31, 1998)*
3.2 Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of
Edison International dated November 21, 1996 (File No. 1-9936, Edison International Form 8-A
dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors effective May 20,
2004 (File No. 1-9936, Edison International Form 8-K, dated May 21, 2004)*
10.1 Director 2004 Nonqualified Stock Option Terms and Conditions under the Equity Compensation
Plan
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. Section 1350
- ----------------
* Incorporated by reference pursuant to Rule 12b-32.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 7, 2004 May 11, 2004 12
May 20, 2004 May 21, 2004 5 and 7
- ----------------
** The May 11, 2004 Form 8-K reporting events under Item 12 was furnished under Item 12 and shall not be deemed
to be "filed" for purposes of the Securities and Exchange Act of 1934, nor shall it be deemed to be
incorporated by reference in any filing under the Securities Act of 1933.
Page 87
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: August 5, 2004