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, 2005
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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 976)
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 5, 2005
----------------------------------------------------- -------------------------------------------------------
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, 2005 and 2004 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2005 and 2004 2
Consolidated Balance Sheets - June 30, 2005
and December 31, 2004 3
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2005 and 2004 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 33
Item 3. Quantitative and Qualitative Disclosures About Market Risk 85
Item 4. Controls and Procedures 85
Part II. Other Information:
Item 1. Legal Proceedings 86
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 87
Item 4. Submission of Matters to a Vote of Security Holders 88
Item 6. Exhibits 89
Signature
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
June 30, June 30,
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In millions, except per-share amounts 2005 2004 2005 2004
-----------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility $ 2,203 $ 2,176 $ 4,109 $ 3,872
Nonutility power generation 417 359 928 748
Financial services and other 29 30 56 61
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Total operating revenue 2,649 2,565 5,093 4,681
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Fuel 399 384 818 611
Purchased power 743 527 1,131 1,107
Provisions for regulatory adjustment clauses - net (41) (33) 24 (51)
Other operation and maintenance 815 796 1,624 1,581
Asset impairment and loss on lease termination 7 954 11 954
Depreciation, decommissioning and amortization 267 266 527 522
Property and other taxes 50 53 102 98
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Total operating expenses 2,240 2,947 4,237 4,822
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Operating income (loss) 409 (382) 856 (141)
Interest and dividend income 25 11 47 22
Equity in income from partnerships and
unconsolidated subsidiaries - net 24 10 108 29
Other nonoperating income 20 9 37 87
Interest expense - net of amounts capitalized (204) (252) (417) (489)
Loss on early extinguishment of debt -- -- (24) --
Other nonoperating deductions (13) (16) (22) (29)
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Income (loss) from continuing operations before tax
and minority interest 261 (620) 585 (521)
Income tax (benefit) 34 (264) 138 (221)
Dividends on utility preferred and preference stock
not subject to mandatory redemption 5 1 7 3
Minority interest 42 43 65 44
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Income (loss) from continuing operations 180 (400) 375 (347)
Income from discontinued operations - net of tax 21 26 28 72
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Income (loss) before accounting change 201 (374) 403 (275)
Cumulative effect of accounting change - net of tax -- -- -- (1)
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Net income (loss) $ 201 $ (374) $ 403 $ (276)
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Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings (loss) per common share:
Continuing operations $ 0.55 $ (1.23) $ 1.15 $ (1.07)
Discontinued operations 0.06 0.08 0.08 0.22
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Total $ 0.61 $ (1.15) $ 1.23 $ (0.85)
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Weighted-average shares, including
effect of dilutive securities 331 326 331 326
Diluted earnings (loss) per common share:
Continuing operations $ 0.55 $ (1.23) $ 1.14 $ (1.07)
Discontinued operations 0.06 0.08 0.08 0.22
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Total $ 0.61 $ (1.15) $ 1.22 $ (0.85)
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Dividends declared per common share $ 0.25 $ 0.20 $ 0.50 $ 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,
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In millions 2005 2004 2005 2004
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(Unaudited)
Net income (loss) $ 201 $ (374) $ 403 $ (276)
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments (2) (29) (2) (7)
Unrealized gain on investments - net -- 18 -- 18
Unrealized gains (losses) on cash flow hedges:
Other unrealized (gain) loss on and
amortization of cash flow hedges - net 16 (3) (54) (48)
Reclassification adjustment for gain (loss)
included in net income (3) 22 (8) 43
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Other comprehensive income (loss) 11 8 (64) 6
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Comprehensive income (loss) $ 212 $ (366) $ 339 $ (270)
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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 2005 2004
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(Unaudited)
ASSETS
Cash and equivalents $ 2,119 $ 2,688
Restricted cash 170 73
Receivables, less allowances of $30 and $31 for uncollectible
accounts at respective dates 931 846
Accrued unbilled revenue 519 320
Fuel inventory 95 73
Materials and supplies 240 231
Accumulated deferred income taxes - net 445 288
Trading and price risk management assets 35 41
Regulatory assets 752 553
Other current assets 242 336
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Total current assets 5,548 5,449
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Nonutility property - less accumulated provision for
depreciation of $1,369 and $1,311 at respective dates 3,949 3,922
Nuclear decommissioning trusts 2,793 2,757
Investments in partnerships and unconsolidated subsidiaries 587 608
Investments in leveraged leases 2,451 2,424
Other investments 176 197
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Total investments and other assets 9,956 9,908
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Utility plant, at original cost:
Transmission and distribution 16,042 15,685
Generation 1,372 1,356
Accumulated provision for depreciation (4,629) (4,506)
Construction work in progress 871 789
Nuclear fuel, at amortized cost 141 151
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Total utility plant 13,797 13,475
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Restricted cash 128 155
Regulatory assets 3,169 3,285
Other deferred charges 927 875
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Total deferred charges 4,224 4,315
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Assets of discontinued operations 12 122
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Total assets $ 33,537 $ 33,269
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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, except share amounts 2005 2004
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 148 $ 88
Long-term debt due within one year 736 809
Preferred stock to be redeemed within one year -- 9
Accounts payable 717 749
Accrued taxes 507 226
Accrued interest 220 233
Customer deposits 177 168
Book overdrafts 262 232
Trading and price risk management liabilities 148 31
Regulatory liabilities 766 490
Other current liabilities 939 1,002
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Total current liabilities 4,620 4,037
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Long-term debt 8,872 9,678
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Accumulated deferred income taxes - net 5,230 5,233
Accumulated deferred investment tax credits 135 138
Customer advances and other deferred credits 1,237 1,109
Power-purchase contracts 88 130
Preferred stock subject to mandatory redemption -- 139
Accumulated provision for pensions and benefits 569 523
Asset retirement obligations 2,247 2,188
Regulatory liabilities 3,217 3,356
Other long-term liabilities 249 232
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Total deferred credits and other liabilities 12,972 13,048
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Liabilities of discontinued operations 15 15
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Total liabilities 26,479 26,778
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Commitments and contingencies (Notes 2, 4 and 7)
Minority interest 308 313
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Preferred and preference stock of utility
not subject to mandatory redemption 529 129
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Common stock (325,811,206 shares outstanding at each date) 1,993 1,975
Accumulated other comprehensive loss (68) (4)
Retained earnings 4,296 4,078
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Total common shareholders' equity 6,221 6,049
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Total liabilities and shareholders' equity $ 33,537 $ 33,269
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Ended
June 30,
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In millions 2005 2004
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 375 $ (347)
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax -- 1
Depreciation, decommissioning and amortization 527 522
Other amortization 47 49
Minority interest 65 44
Deferred income taxes and investment tax credits (155) (160)
Equity in income from partnerships and unconsolidated subsidiaries (108) (29)
Income from leveraged leases (36) (44)
Regulatory assets - long-term 214 199
Regulatory liabilities - long-term (127) (50)
Loss on early extinguishment of debt 24 --
Other assets (20) (55)
Other liabilities 166 33
Receivables and accrued unbilled revenue (268) (198)
Inventory, prepayments and other current assets (193) (72)
Regulatory assets - short-term (199) (404)
Regulatory liabilities - short-term 276 299
Accrued interest and taxes 282 (32)
Accounts payable and other current liabilities (97) (137)
Distributions and dividends from unconsolidated entities 39 50
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Net cash provided (used) by operating activities 812 (331)
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Cash flows from financing activities:
Long-term debt issued and issuance costs 980 3,322
Long-term debt repaid (1,848) (1,648)
Bonds remarketed - net -- 350
Issuance of preference stock 395 --
Redemption of preferred securities (148) (2)
Rate reduction notes repaid (116) (115)
Change in book overdrafts 30 36
Short-term debt financing - net 60 (209)
Shares purchased for stock-based compensation (90) (21)
Proceeds from stock option exercises 51 15
Dividends to minority shareholders (58) (25)
Dividends paid (163) (130)
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Net cash provided (used) by financing activities (907) 1,573
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Cash flows from investing activities:
Capital expenditures (809) (749)
Acquisition costs related to nonutility generation plant -- (285)
Proceeds from sale of property and interests in projects -- 118
Proceeds from sale of discontinued operations 124 --
Contributions to and earnings from nuclear decommissioning trusts - net (51) (42)
Distributions from (investments in) partnerships and unconsolidated subsidiaries 68 13
Sales of short-term investments - net 140 10
Sales of investments in other assets 26 23
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Net cash used by investing activities (502) (912)
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Effect of consolidation of variable interest entities on cash 3 79
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Effect of deconsolidation of variable interest entities on cash -- (32)
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Net changes in cash of discontinued operations 27 41
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Effect of exchange rate changes on cash (1) --
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Net increase (decrease) in cash and equivalents (568) 418
Cash and equivalents, beginning of period 2,689 2,178
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Cash and equivalents, end of period 2,121 2,596
Cash and equivalents, discontinued operations (2) (199)
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Cash and equivalents, continuing operations $ 2,119 $ 2,397
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The accompanying notes are an integral part of these financial statements.
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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, 2005
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, 2004 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 2004 Annual Report. Edison International follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the June 30, 2005 financial statement presentation. These
reclassifications include the reclassification of income from continuing operations to discontinued operations for Edison Mission
Energy's (EME) international operations, except the Doga project. See further discussion in Note 6. Except as indicated, amounts
presented in the Notes to the Consolidated Financial Statements relate to continuing operations.
Earnings Per Common Share (EPS)
In March 2004, the Financial Accounting Standards Board (FASB) issued new accounting guidance for the effect of participating
securities on EPS calculations and the use of the two-class method. The new guidance, which was effective in second quarter 2004,
requires the use of the two-class method of computing EPS for companies with participating securities. The two-class method is an
earnings allocations formula that determines EPS for each class of common stock and participating security. Edison International has
participating securities (vested stock options that earn dividend equivalents on an equal basis with common shares), but determined
that the effect on 2004, 2003 and 2002 EPS was immaterial.
Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding.
Net income (loss) available for common stock was $200 million and $(374) million for the three months ended June 30, 2005, and 2004,
respectively, and was $400 million and $(276) million for the six months ended June 30, 2005, and 2004, respectively. In arriving at
net income, dividends on preferred securities and preferred stock have been deducted.
For the diluted EPS calculation, dilutive securities (stock-based compensation awards exercisable) are added to the weighted-average
shares. However, in periods of net loss, dilutive securities are not added to the weighted-average shares due to their antidilutive
effect.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
Edison International's income tax expense increased $298 million and $359 million for the three- and six-month periods ended June 30,
2005, respectively, as compared to the same periods in 2004, primarily due to increases in pre-tax income. The increases were
partially offset by reductions in accrued tax liabilities at Southern California Edison (SCE) and Mission Energy Holding Company
(MEHC) in 2005 to reflect progress in settlement negotiations related to prior-year tax liabilities, property-related flow-through
items at SCE, and adjustments made to tax balances at SCE and MEHC.
Edison International's composite federal and state statutory rate was approximately 40% for the three-and six-month periods ended
June 30, 2005. The lower effective tax rate of 16% and 27% realized in the three- and six-month periods ended June 30, 2005,
respectively, was primarily due to reductions in tax liabilities at SCE and MEHC, property-related flow-through items at SCE, the
benefits received from low-income housing and production tax credits at Edison Capital, and adjustments to tax balances at SCE and
MEHC.
New Accounting Principles
In March 2005, the FASB issued an interpretation related to accounting for conditional asset retirement obligations. This
Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement
obligation (ARO) if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of
settlement. This Interpretation is effective December 31, 2005. Edison International is assessing the impact of this Interpretation
on its results of operations and financial condition.
A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison
International currently uses the intrinsic value accounting method for stock-based compensation. On April 14, 2005, the Securities
and Exchange Commission announced a delay in the effective date for the new standard to fiscal years beginning after June 15, 2005.
Edison International will implement the new standard effective January 1, 2006 by applying the modified prospective transition
method. The difference in expense between the two accounting methods is shown below under "Stock-Based Compensation."
The American Jobs Creation Act of 2004 included a tax deduction on qualified production activities income (including income from the
sale of electricity). In December 2004, the FASB issued guidance that this deduction should be accounted for as a special deduction,
rather than a tax rate reduction. Accordingly, the special deduction is recorded in the year it is earned. The tax deduction is not
expected to materially affect Edison International's 2005 financial statements. Edison International is evaluating the effect that
the manufacturer's deduction will have in subsequent years.
In March 2004, the FASB issued new accounting guidance for the effect of participating securities on EPS calculations and the use of
the two-class method. The new guidance, which was effective in second quarter 2004, requires the use of the two-class method of
computing EPS for companies with participating securities (including vested stock options with dividend equivalents). See "Earnings
Per Common Share" above.
In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003), Consolidation of
Variable Interest Entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and
financial reporting for, VIEs, where
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 was 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. Edison International implemented the
Interpretation for its special purpose entities 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. Edison International recorded a cumulative effect
adjustment that decreased net income by less than $1 million, net of tax, due to negative equity at one of Edison Capital's newly
consolidated entities.
Regulatory Assets and Liabilities
Regulatory assets included in the consolidated balance sheets are:
June 30, December 31,
In millions 2005 2004
-------------------------------------------------------------------------------------------------------------
(Unaudited)
Current
Regulatory balancing accounts $ 523 $ 371
Direct access procurement charges 111 109
Purchased-power settlements 60 62
Other 58 11
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752 553
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Long-term
Flow-through taxes - net 1,048 1,018
Rate reduction notes - transition cost deferral 593 739
Unamortized nuclear investment - net 523 526
Nuclear-related ARO investment - net 265 272
Unamortized coal plant investment - net 81 78
Unamortized loss on reacquired debt 326 250
Direct access procurement charges 90 141
Environmental remediation 58 55
Purchased-power settlements 62 91
Other 123 115
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3,169 3,285
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Total regulatory assets $ 3,921 $ 3,838
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory liabilities included in the consolidated balance sheets are:
June 30, December 31,
In millions 2005 2004
------------------------------------------------------------------------------------------------------------
(Unaudited)
Current
Regulatory balancing accounts $ 609 $ 357
Direct access procurement charges 111 109
Other 46 24
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766 490
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Long-term
ARO 765 819
Costs of removal 2,137 2,112
Direct access procurement charges 90 141
Employee benefits plans 223 200
Other 2 84
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3,217 3,356
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Total regulatory liabilities $ 3,983 $ 3,846
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Stock-Based Compensation
Edison International has three stock-based compensation plans, which are described more fully in Note 7 of "Notes to Consolidated
Financial Statements" included in its 2004 Annual Report. Edison International accounts for these plans using the intrinsic value
method. Upon grant, no stock-based compensation cost is reflected in net income, as all options granted under those plans had an
exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the
effect on net income and EPS if Edison International had used the fair-value accounting method.
Three Months Ended Six Months Ended
June 30, June 30,
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In millions, except per-share amounts 2005 2004 2005 2004
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income (loss), as reported $ 201 $ (374) $ 403 $ (276)
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 15 3 25 7
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 17 3 30 6
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Pro forma net income (loss) $ 199 $ (374) $ 398 $ (275)
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Basic earnings (loss) per common share:
As reported $ 0.61 $(1.15) $ 1.23 $ (0.85)
Pro forma $ 0.61 $(1.15) $ 1.22 $ (0.84)
Diluted earnings (loss) per common share:
As reported $ 0.61 $(1.15) $ 1.22 $ (0.85)
Pro forma $ 0.60 $(1.15) $ 1.20 $ (0.84)
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Accumulated Other Comprehensive Loss Information
Supplemental information regarding Edison International's accumulated other comprehensive loss, including discontinued operations, is:
June 30, December 31,
In millions 2005 2004
---------------------------------------------------------------------------------------------------------------
(Unaudited)
Foreign currency translation adjustments $ (2) $ --
Minimum pension liability - net (16) (15)
Unrealized gains (losses) on cash flow hedges - net (50) 11
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Accumulated other comprehensive loss $ (68) $ (4)
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The minimum pension liability is discussed in Note 7, Compensation and Benefit Plans of "Notes to Consolidated Financial Statements"
included In Edison International's 2004 Annual Report.
Included in Edison International's accumulated other comprehensive loss at June 30, 2005, was a $44 million loss related to EME's net
unrealized losses on cash flow hedges and a $5 million loss related to SCE's interest rate swap (see discussion below).
Unrealized losses on cash flow hedges at June 30, 2005, include unrealized losses on commodity hedges primarily related to EME's
Midwest Generation and Homer City forward electricity contracts that qualify for hedge accounting. These losses arise because
current forecasts of future electricity prices in these markets are greater than contract prices. Partially offsetting these
unrealized losses were unrealized gains on commodity hedges related to EME's share of fuel contracts at its March Point cogeneration
facility.
Unrealized losses on cash flow hedges also included those related to SCE's interest rate swap (the swap terminated on January 5,
2001, but the related debt matures in 2008). The unamortized loss of $5 million (as of June 30, 2005, net of tax) on the interest
rate swap will be amortized over a period ending in 2008. Approximately $2 million, after tax, of the unamortized loss on this swap
will be reclassified into earnings during the next 12 months. Amortized losses are recoverable through SCE's annual cost of capital
proceeding.
As EME's hedged positions for continuing operations are realized, approximately $55 million (after tax) of the net unrealized losses
on cash flow hedges at June 30, 2005 are expected to be reclassified into earnings during the next 12 months. EME expects that
reclassification of net unrealized losses will offset energy revenue recognized at market prices. Actual amounts ultimately
reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market
conditions. The maximum period over which an EME cash flow hedge is designated is through December 31, 2006.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flows Information
Six Months Ended
June 30,
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In millions 2005 2004
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(Unaudited)
Cash payments (receipts) for interest and taxes:
Interest - net of amounts capitalized $ 377 $ 429
Tax payments (receipts) (47) 7
Non-cash investing and financing activities:
Details of debt exchanges:
Pollution-control bonds redeemed $ (204) --
Pollution-control bonds issued 204 --
Dividends declared but not paid $ 81 $ 65
Details of consolidation of variable interest entities:
Assets -- $ 625
Liabilities -- (704)
Details of deconsolidation of variable interest entities:
Assets -- $ (133)
Liabilities -- 165
Reoffering of pollution-control bonds -- $ 196
Details of pollution-control bond redemption:
Release of funds held in trust -- $ 20
Pollution-control bonds redeemed -- (20)
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Note 2. Regulatory Matters
Further information on these regulatory matters is described in Note 2 of "Notes to Consolidated Financial Statements" included in
Edison International's 2004 Annual Report.
California Department of Water Resources (CDWR) Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in Note 2 of "Notes to Consolidated
Financial Statements" included in Edison International's 2004 Annual Report, in December 2004, the California Public Utilities
Commission (CPUC) issued its decision on how the CDWR's power charge revenue requirement for 2004 through 2013 will be allocated
among the investor-owned utilities. On June 30, 2005, the CPUC granted, in part, San Diego Gas & Electric's (SDG&E) petition for
modification of the December 2004 decision. The June 30, 2005 decision adopted a methodology that retains the cost-follows-contract
allocation of the avoidable costs, and allocates the unavoidable costs associated with the contracts: 42.2% to Pacific Gas and
Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. This newly adopted allocation methodology
decreases the total costs allocated to SDG&E's customers and increases the total costs
Page 11
allocated to SCE's and PG&E's customers, relative to the December 2004 decision. Amounts billed to 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 and therefore have no
impact on SCE's earnings.
Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms
Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain shareholder incentives for its
performance achievements in delivering demand-side management and energy efficiency programs. On June 10, 2005, SCE and the Office
of Ratepayer Advocates (ORA) executed a settlement agreement for SCE's outstanding issues concerning SCE shareholder incentives and
performance achievements resulting from the demand-side management, energy efficiency, and low-income energy efficiency programs from
program years 1994-2004. In addition, the settlement addresses shareholder incentives and performance achievements for program years
1994-1998, anticipated but not yet claimed. The settlement agreement recommends, among other things, that SCE be entitled to
immediately recover 92% of the total of SCE's current claims and future claims related to SCE's pre-1998 energy efficiency programs.
SCE's total claim for program years 1994-2004 made in 2000 through 2008, including interest, franchise fees and uncollectibles, is
approximately $46 million. The settling parties agreed that it is reasonable for SCE to recover approximately $42 million of these
claims in the near future as full recovery of all of SCE's outstanding claims as well as future claims related to SCE's pre-1998
energy efficiency programs. The settlement agreement requires CPUC approval. On June 13, 2005, SCE and the ORA filed a joint motion
requesting CPUC adoption of the settlement agreement. A decision is expected in the fourth quarter of 2005, which if approved, would
result in the recognition of a $42 million increase in earnings. SCE has collected and deferred most of the expected claims in
rates, and expects to recover the remaining portion of the claims over a 12-month period beginning on January 1, 2006.
Energy Resource Recovery Account (ERRA) Proceedings
In an October 2002 decision, the CPUC established the Energy Resource Recovery Account (ERRA) as the rate-making mechanism to track
and recover SCE's: (1) fuel costs related to its generating stations; (2) purchased-power costs related to cogeneration and
renewable contracts; (3) purchased-power costs related to existing interutility and bilateral contracts that were entered into before
January 17, 2001; and (4) new procurement-related costs incurred on or after January 1, 2003 (the date on which the CPUC transferred
back to SCE the responsibility for procuring energy resources for its customers). SCE recovers these costs on a cost-recovery basis,
with no markup for return or profit. SCE files annual forecasts of the above-described costs that it expects to incur during the
following year. As these costs are subsequently incurred, they will be tracked and recovered through the ERRA, but are subject to a
reasonableness review in a separate annual ERRA application. If the ERRA overcollection or undercollection exceeds 5% of SCE's prior
year's generation revenue, the CPUC has established a "trigger" mechanism, whereby SCE can request an emergency rate adjustment in
addition to the annual forecast and reasonableness ERRA applications.
ERRA Trigger Mechanism Filing
On March 25, 2005, SCE submitted a CPUC rate application under the ERRA trigger mechanism, as the recorded undercollection in its
ERRA balancing account as of February 28, 2005 had reached 9.7% of recorded 2004 generation revenue, well above the 5% threshold for
an emergency rate adjustment established by the CPUC. SCE's undercollection had been less than 4% of recorded 2004 generation
revenue at the end of January 2005. A combination of higher procurement costs, a delay in approval of
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the 2005 ERRA rate change and other factors contributed to the large increase in the undercollection amount in February 2005. SCE's
trigger application stated that if the CPUC retained recently authorized ERRA rate levels rather than increasing rates, the
undercollection would be recovered by mid-September 2005. On May 26, 2005, the CPUC issued a decision granting SCE's application to
maintain its previously authorized ERRA rate levels.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its procurement-related costs for calendar
year 2004 to be reasonable, and that its contract administration and economic dispatch operations during 2004 complied with its
CPUC-adopted procurement plan. In addition, SCE requested recovery of approximately $13 million associated with Nuclear Unit
Incentive Procedure rewards for efficient operation of the Palo Verde Nuclear Generating Station (Palo Verde) and approximately
$7 million in administrative and general costs incurred to carry out the CPUC's directive to begin procuring energy supplies on
January 1, 2003 following the California energy crisis. The ORA is scheduled to issue its report on SCE's 2004 costs and operations
in mid-August 2005. Evidentiary hearings are scheduled to begin in September 2005 and a decision is expected in late December 2005
or early January 2006.
Generation Procurement Proceedings
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan was filed on March 7, 2005. On July 21, 2005, the CPUC issued a decision approving SCE's 2005
renewable procurement plan and deferred a ruling on SCE's renewable procurement plan for 2006 through 2014. This decision also
approved the methodology advocated by SCE for determining the amount by which reported renewable procurement should be adjusted to
reflect line losses.
In addition, the decision states that SCE cannot count procurement from certain geothermal facilities towards its 1% annual renewable
procurement requirement, unless such procurement is from production certified as "incremental" by the California Energy Commission
(CEC). A 2003 CPUC decision had held that SCE could count procurement from these geothermal facilities toward its 1% annual
renewable procurement requirement.
The geothermal facilities have applied to the CEC for certification of a portion of the facilities' production as "incremental." A
decision from the CEC is expected in late August or early September 2005. It is not clear whether any of the facilities' production
will be certified as "incremental" or how much, if any, of the "incremental" production from the facilities will be allocated to
SCE's procurement under its contract with the facilities if the CEC certification is granted.
Depending upon the amount, if any, of CEC certified "incremental" production allocated to SCE's procurement under its contract and
the manner in which the CPUC implements its flexible rules for compliance with renewable procurement obligations, SCE may not be in
compliance with its statutory renewable procurement obligations for 2003 through 2006 and could be subject to penalties for those
years. The maximum penalty is $25 million per year. To comply with renewable procurement mandates and avoid penalties for years
beyond 2006, SCE will either need to sign new contracts and/or extend existing renewable qualifying facility contracts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and conducted negotiations
with bidders regarding potential procurement contracts. On June 30, 2005, the CPUC issued a resolution approving six renewable
contracts resulting from the solicitation. The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new
request for offers for additional renewable contracts, which SCE contemplates initiating in the third quarter of 2005.
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in southern California. SCE
has issued a Request for Offers (RFO) for new generation resources. SCE has solicited offers for power-purchase agreements lasting
up to 10 years from new generation facilities with delivery under the agreement beginning between June 1, 2006 and August 1, 2008.
SCE has filed an application with the CPUC seeking approval of the RFO and the power-purchase agreements executed under the RFO. SCE
is seeking recovery of the costs of the contracts, through the Federal Energy Regulatory Commission (FERC)-jurisdictional rates, from
all affected customers. In addition, SCE seeks CPUC assurance of full cost recovery in CPUC-approved rates, if the FERC denies any
recovery. Any power-purchase agreement that SCE executes as a result of the RFO will be contingent on CPUC approval of the contract
and assurance of full cost recovery.
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. For a discussion of item (1) above, see the "Holding Company Proceeding" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in Edison International's 2004 Annual Report.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed the proceeding without
addressing some of the issues the proceeding raised (such as the appropriateness of the large utilities' holding company structure
and dividend policies), the CPUC may rule on or investigate these issues in the future.
California Independent System Operator (ISO) Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning and
Riverside, California over the proper allocation and characterization of certain charges. The order reversed an arbitrator's award
that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those
charges to Scheduling Coordinators (SCs) in the affected zone within the ISO transmission grid. The April 20, 2004 order directed
the ISO to shift the costs from SCs in the affected zone to the responsible Participating Transmission Owner, SCE, and to do so
within 60 days of the April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the
Participating Transmission Owner but also will be credited through the California Power Exchange, SCE's SC at the time. SCE obtained
a stay of the April 20, 2004 order pending resolution of its request for rehearing. On March 30, 2005, the FERC issued an Order
Denying Rehearing. SCE obtained an extension of the stay pending resolution of the appeal SCE has filed with the United States Court
of Appeals for the D.C. Circuit (D.C. Circuit Court).
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The potential net impact on SCE is estimated to be approximately $20 million to $25 million, including interest. SCE filed a request
for clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the disputed costs in SCE's reliability
services rates. On June 8, 2005, the FERC denied the clarification, noting that during the appeal, the FERC's order is stayed,
therefore SCE is not required to pay at this time. SCE may seek recovery in its reliability service rates of the costs should SCE be
required to pay these costs.
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 2004 Annual Report, the CPUC issued a final decision in December 2004 on SCE's
application regarding the post-2005 operation of Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant parties in an effort
to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been reached to date. Because resolution has not
been reached and because of the lead times required for installation of certain pollution-control equipment and other upgrades
necessary for post-2005 operation, it is probable that Mohave will shut down for at least several years, and perhaps permanently, at
the end of 2005. The outcome of the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. SCE's 2006 ERRA
forecast application assumes Mohave is an unavailable resource for power for 2006. Because SCE expects to recover Mohave shut-down
costs in future rates, the outcome of this matter is not expected to have a material impact on earnings.
For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.
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 $80 million of these unrecovered
costs since 1998. In addition, SCE has accrued interest on these unrecovered costs. The three California utilities appealed the
decisions to the D.C. Circuit Court. On July 12, 2005, the D.C. Circuit Court vacated the FERC's August and November 2002 orders,
and remanded the case to the FERC for further proceedings. SCE believes that the D.C. Circuit Court's decision increases the
likelihood that it will recover these costs.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report, SCE is participating in several related proceedings seeking
recovery of refunds from sellers of electricity and natural gas who allegedly manipulated the electric and natural gas markets.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including SCE, PG&E, the State of
California and various consumer class action representatives) settling various 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 was required to refund to customers amounts received under the terms of the El Paso settlement (net of legal and
consulting costs) through its ERRA mechanism. In June 2004, SCE received its first settlement payment of $76 million. Approximately
$66 million of this amount was credited to purchased-power expense, and was refunded to SCE's ratepayers through the ERRA over the
following twelve months, and the remaining $10 million was used to offset SCE's incurred legal costs. El Paso has elected to prepay
the additional settlement payments due over a 20-year period and, as a result, SCE received $66 million in May 2005. 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 January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant Corporation and a
number of its affiliates (collectively Mirant), all of whom are debtors in Chapter 11 bankruptcy proceedings pending in Texas. Among
other things, the settlement terms provide for cash and equivalent refunds totaling $320 million, of which SCE's allocated share is
approximately $68 million. The settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of
one of the Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual value of the
unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant settlement was approved
by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. In April and May 2005, SCE received its allocated
$68 million in cash settlement proceeds. SCE continues to hold its $33 million share of the allowed, unsecured bankruptcy claim. The
Mirant settlement will be refunded to ratepayers as described below.
On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Enron Corporation and a number
of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. Among
other things, the settlement terms provide for cash and equivalent payments from Enron totaling approximately $47 million and an
allowed, unsecured claim in the bankruptcy against one of the Enron entities in the amount of $875 million. SCE's allocable share of
both the cash and allowed claim portions of the settlement consideration has not yet been finally determined, and the value of an
allocable share of the allowed claim will be determined as part of the resolution of the Enron parties' bankruptcies. The settlement
remains subject to the approvals of the FERC, the CPUC and the Enron bankruptcy court. The Enron settlement proceeds will be
refunded to ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum Account (ESMA) for
the purpose of recording the foregoing settlement proceeds (excluding the El Paso settlement) from energy providers and allocating
them in accordance with the terms of the October 2001 settlement agreement entered into by SCE and the CPUC which settled SCE's
lawsuit against the CPUC. This lawsuit sought full recovery of SCE's electricity procurement costs incurred during the energy
crisis. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will be allocated to
recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above and a 10% shareholder incentive
pursuant to the CPUC litigation settlement agreement. Remaining amounts for each settlement are to be refunded to ratepayers through
the ERRA mechanism. In the second quarter of 2005, SCE recorded a $7 million
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
increase to other nonoperating income as a shareholder incentive related to the Mirant refund received during the second quarter of
2005.
Note 3. Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2004 Annual Report that it expects to contribute approximately $53 million to its pension plans in 2005. As of
June 30, 2005, $6 million in contributions have been made. Edison International anticipates that its original expectation will be met
by year-end 2005.
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
--------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 29 $ 27 $ 58 $ 53
Interest cost 43 44 86 87
Expected return on plan assets (56) (60) (112) (118)
Net amortization and deferral 7 6 14 12
--------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 23 17 46 34
Regulatory adjustment - deferred (2) -- (4) --
--------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 21 $ 17 $ 42 $ 34
--------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2004 Annual Report that it expects to contribute approximately $77 million to its postretirement benefits other than
pensions plans in 2005. As of June 30, 2005, $13 million in contributions have been made. Edison International anticipates that its
original expectation will be met by year-end 2005.
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 12 $ 11 $ 24 $ 23
Interest cost 31 33 62 67
Expected return on plan assets (25) (27) (51) (55)
Amortization of unrecognized prior service costs (8) (8) (15) (16)
Amortization of unrecognized loss 12 16 24 31
-------------------------------------------------------------------------------------------------------------------
Total expense $ 22 $ 25 $ 44 $ 50
-------------------------------------------------------------------------------------------------------------------
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings
before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International
believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has invested in three aircraft leased to American Airlines. American has reported very large operating and net losses
due to reduced pricing power, increases in capacity in excess of demand, deeply discounted fare sales and significant increases in
fuel prices. In the event 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 2005 is $45 million. A restructuring of the lease could
also result in a loss of some or all of the investment. At June 30, 2005, American Airlines was current in its lease payments to
Edison Capital.
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 28 identified sites at SCE (22 sites) and EME (6 sites
related to Midwest Generation) is $86 million, $84 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to
$113 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. In addition to its identified sites (sites in which the upper
end of the range of costs is at least $1 million), SCE also has 33 immaterial sites whose total liability ranges from $4 million (the
recorded minimum liability) to $10 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $31 million of its recorded liability,
through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to
recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $57 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 $12 million to $25 million. Recorded costs for the twelve months ended June 30, 2005 were
$12 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental
remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
Edison International has reached a settlement with the Internal Revenue Service (IRS) on tax issues and pending affirmative claims
relating to its 1991-1993 tax years. This settlement, which was signed by Edison International in March 2005 and approved by the
United States Congress Joint Committee on Taxation on July 27, 2005, will result in a third quarter 2005 net earnings benefit for
Edison International of approximately $56 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. Many of the asserted tax
deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would be
deductible on future tax returns of Edison International.
As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income
taxes in audits of the 1994-1996 and 1997-1999 tax years associated with Edison
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Capital's cross-border leases. The IRS is challenging Edison Capital's foreign power plant and electric locomotive sale/leaseback
transactions (termed a sale-in/lease-out or SILO transaction). The estimated federal and state taxes deferred from these leases were
$44 million in the 1994-1996 and 1997-1999 audit periods and $32 million in subsequent years through 2004.
The IRS is also challenging Edison Capital's foreign power plant and electric transmission system lease/leaseback transactions
(termed a lease-in, lease-out or LILO transaction). The estimated federal and state income taxes deferred from these leases were
$558 million in the 1997-1999 audit period and $565 million in subsequent years through 2004. The IRS has also proposed interest and
penalties in its challenge to each SILO and LILO transaction.
Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in
effect at the time the transactions were entered into. Written protests were filed to appeal the 1994-1996 audit adjustments
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 International also filed protests in March 2005 to appeal the issues raised
in the 1997-1999 audit. Edison International intends to contest these proposed deficiencies through administrative appeals and
litigation, if necessary.
Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (termed a
Service Contract). The IRS did not assert an adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge
this lease in subsequent audit cycles similar to positions asserted against the SILOs discussed above. The estimated federal and
state taxes deferred from this lease are $221 million through 2004.
If Edison International is not successful in its defense of the tax treatment for the SILOs, LILOs and the Service Contract, the
payment of taxes, exclusive of any interest or penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow. However, the FASB is currently considering changes to the accounting for
leases. If the proposed accounting changes are adopted and Edison International's tax treatment for the SILOs, LILOs and Service
Contract is significantly altered as a result of IRS challenges, there could be a material effect on reported earnings by requiring
Edison International to reverse earnings previously recognized as a current period adjustment and to report these earnings over the
remaining life of the leases. At this time, Edison International is unable to predict the impact of the ultimate resolution of these
matters.
The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to 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. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits
relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these
tax losses are sustained.
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 and the SCE subsidiary contingent liability company transaction described above. Edison International
filed these amended returns under protest retaining its appeal rights.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Investigations Regarding Performance Incentives Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties for the period of
1997 through 2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and
illness reporting, and system reliability. Current CPUC ratemaking (through SCE's 2003 General Rate Case (GRC) decision) provides
for performance incentives or penalties for differences between actual results and GRC-determined standards of employee injury and
illness reporting, and system reliability.
SCE has been conducting investigations into its performance under these mechanisms and has reported to the CPUC certain findings of
misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own
proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer
satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose
additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of
refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE's
transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction
surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to
determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE
also anticipated that it could be eligible for customer satisfaction rewards of about $10 million for 2003.
SCE has been keeping the CPUC informed of the progress of SCE's internal investigation. On June 25, 2004, SCE submitted to the CPUC
a PBR customer satisfaction investigation report, which concluded that employees in the design organization of the transmission and
distribution business unit deliberately altered customer contact information in order to affect the results of customer satisfaction
surveys. At least 36 design organization personnel engaged in deliberate misconduct including alteration of customer information
before the data were transmitted to the independent survey company. Because of the apparent scope of the misconduct, SCE proposed to
refund to ratepayers $7 million of the PBR rewards previously received and forego an additional $5 million of the PBR rewards pending
that are both attributable to the design organization's portion of the customer satisfaction rewards for the entire PBR period
(1997-2003). In addition, during its investigation, SCE determined that it could not confirm the integrity of the method used for
obtaining customer satisfaction survey data for meter reading. Thus, SCE also proposed to refund all of the approximately $2 million
of customer satisfaction rewards associated with meter reading. As a result of these findings, SCE accrued a $9 million charge in
2004 for the potential refunds of rewards that have been received.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory
personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls
over data collection and processing.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The PBR performance incentive mechanism for customer satisfaction expired after calendar year 2003 pursuant to the CPUC's decision in
SCE's 2003 GRC.
The CPUC has not yet opened a formal investigative proceeding into this matter. However, the Consumer Protection and Safety Division
(CPSD) of the CPUC has submitted several data requests to SCE and has requested an opportunity to interview a number of current and
former SCE employees in the design organization. SCE has responded to these requests and the CPSD has conducted interviews of
approximately 20 employees who were disciplined for misconduct.
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE's
employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine
the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received
$20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, would have been entitled to an
additional $15 million for 2001 through 2003 ($5 million for each year).
On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE's performance
under the PBR incentive mechanism for injury and illness reporting. Under the PBR mechanism, rewards and/or penalties for the years
1997 through 2003 were based upon a total incident rate, which included two equally weighted measures: Occupational Safety and
Health Administration (OSHA) recordable incidents and first aid incidents. The major issue disclosed in the investigative findings
to the CPUC was that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid
incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these inaccuracies
did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the PBR mechanism for any year before
2004, and it return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in 2004 for
the potential refund of these rewards. SCE has also proposed to withdraw the pending requests for rewards for the 2001-2002 time
frames. SCE has not yet filed a request related to its performance for 2003 under the PBR mechanism.
SCE is taking other remedial action to address the issues identified, including revising its organizational structure and overall
program for environmental, health and safety compliance. SCE also took disciplinary action against twenty-four individuals in
several SCE business areas in early June 2005. SCE submitted a report on the results of its investigation to the CPUC on December 3,
2004.
As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative proceeding into this matter. However,
the CPSD did submit several data requests to SCE to which SCE has responded.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE has conducted an investigation into the PBR system
reliability metric for the years 1997 through 2003. Since the inception of PBR payments in 1997, SCE has received $8 million in
rewards and has applied for an additional $5 million reward based on frequency of outage data for 2001. For 2002, SCE's data
indicates that it
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
earned no reward and incurred no penalty. Based on the application of the PBR mechanism, SCE would be penalized $5 million for 2003;
however, as indicated above, SCE has not filed a request related to its performance under the PBR mechanism for 2003.
On February 28, 2005, SCE provided its investigatory report on the PBR system reliability incentive mechanism to the CPUC concluding
that the reliability reporting system is working as intended.
The CPUC is not expected to act on SCE's recent advice letter for 2004 or the pending PBR advice letters for 2001 and 2002 until the
CPSD has completed its investigation of these matters. SCE has agreed to file its PBR advice letter for 2003 after the CPSD has
completed its investigation.
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 supplied to Mohave. 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.
Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the
Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the
Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in
the Navajo Nation's lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there
was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for summary judgment in
the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003 motions to dismiss
or, in the alternative, for summary judgment. The D.C. District Court subsequently issued a scheduling order that imposed a
December 31, 2004 discovery cut-off. Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay of
the action to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave.
Negotiations are ongoing and the stay has been continued until further order of the court.
The D.C. Circuit Court, acting on a suggestion on remand filed by the Navajo Nation, held in an October 24, 2003 decision that the
Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations and therefore did not address the
question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the
United States during the time period in question. The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision. Both petitions were denied on
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 9, 2004. On March 16, 2004, the D.C. Circuit Court issued an order remanding the case against the Government to the Court of
Federal Claims, which conducted a status conference on May 18, 2004. As a result of the status conference discussion, the Navajo
Nation and the Government are in the process of briefing the remaining issues following remand. 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. The Navajo Nation's initial brief was filed in the remanded Court of Federal Claims matter on August 26, 2004, and the
Government filed its responsive brief on December 10, 2004. The Navajo Nation subsequently obtained an extension of the due date for
its reply brief while the Court of Federal Claims is considering a motion to strike filed by the Government. Peabody's motion to
intervene in the remanded Court of Federal Claims case as a party was denied. On February 24, 2005, the Court of Federal Claims
denied the motion to strike filed by the Government, but authorized the Government to file a supplemental brief and appendix, which
was filed by the Government on March 23, 2005. On April 25, 2005, the Navajo Nation filed its reply brief and also filed a motion to
strike the Government's supplemental brief and all of the exhibits attached to that brief. Oral argument on the motion to strike is
scheduled for September 28, 2005.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of the Supreme Court's
decision in the Navajo Nation's suit against the Government on this complaint, or the impact of the complaint on the operation of
Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre Nuclear
Generating Station and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear
incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant
site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San
Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $101 million
per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership
interests, SCE could be 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.
Page 24
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Spent Nuclear Fuel
Under federal law, the United States Department of Energy (DOE) is responsible for the selection and construction of a facility for
the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin
acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear
fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives
and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at
San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to
0.1(cent)-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a
complaint against the DOE in the United States Court of Federal Claims seeking damages for DOE's failure to meet its obligation to
begin accepting spent nuclear fuel from San Onofre. The case is currently stayed pending development in other spent nuclear fuel
cases also before the United States Court of Federal Claims.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored
in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation. Movement of Unit 1
spent fuel from the Unit 2 spent fuel pool to the independent spent fuel storage installation is complete. There is now sufficient
space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008, respectively. In order to
maintain a full core off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel
storage installation by late 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage
facility. Arizona Public Service, as operating agent, plans to continually load casks on a schedule to maintain full core off-load
capability for all three units.
Note 5. Business Segments
Edison International's reportable business segments include an electric utility operation segment (SCE), a nonutility power
generation segment (MEHC - parent only and EME), and a financial services provider segment (Edison Capital). Also, in accordance
with an accounting standard related to the impairment and disposal of long-lived assets, prior periods have been restated to reflect
EME's international operations being reported as discontinued operations.
Page 25
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information for the three and six months ended June 30, 2005 and 2004 was:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
--------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 2,203 $ 2,176 $ 4,109 $ 3,872
Nonutility power generation 417 359 928 748
Financial services 24 27 51 56
Corporate and other 5 3 5 5
--------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,649 $ 2,565 $ 5,093 $ 4,681
--------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 161 $ 242 $ 292 $ 341
Nonutility power generation(2) 21 (610) 53 (603)
Financial services(3) 25 11 77 21
Corporate and other (6) (17) (19) (35)
---------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 201 $ (374) $ 403 $ (276)
---------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock.
(2) Includes earnings from discontinued operations of $21 million and $28 million, respectively, for the three and six months
ended June 30, 2005 and $26 million and $72 million, respectively, for the three and six months ended June 30, 2004.
(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, 2005 were: electric utility, $24 billion; nonutility power generation, $6 billion; and,
financial services, $4 billion.
Note 6. Discontinued Operations
On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15,
2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately
$20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.
On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan project to Corporacion IMPSA S.A., pursuant to
a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on
the sale of approximately $9 million during the first quarter of 2005.
On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) to IPM, pursuant to a purchase
agreement dated July 29, 2004. The purchase agreement was entered into following a competitive bidding process. The sale of MECIBV
included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and
Puerto Rico. Consideration from the sale of MECIBV and related assets was $2.0 billion.
Page 26
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On September 30, 2004, EME sold its 51% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a purchase
agreement dated July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for
the sale was NZ$1.6 billion (approximately $1.1 billion) which includes NZ$535 million of debt assumed by the purchaser.
EME previously owned and operated a 220-MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the
Lakeland project. The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power
generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU
UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland Power Ltd.
in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement.
Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is
distributed from this entity.
As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination
of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited, entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy proceedings in the
United States). On March 31, 2005, Lakeland Power Ltd. received(pound)112 million (approximately $210 million) from the TXU
administrators, representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately $217 million).
From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of
(pound)20 million (approximately $37 million) to EME on April 7, 2005 comprised of(pound)7 million (approximately $13 million) for a secured loan
which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd.,
and (pound)13 million (approximately $24 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power
Ltd. This distribution was recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay
to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining
secured and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with
Lakeland Power Ltd.'s liquidation.
EME estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the
above payments will be approximately $64 million. These remaining proceeds are expected to be received in late 2005 or in 2006, as
Lakeland Power Ltd.'s liquidation progresses. Because the amounts required to settle outstanding claims and UK taxes have not been
finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net
income may vary materially from the above estimate.
For all periods presented, the results of EME's international projects discussed above have been accounted for as discontinued
operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal
of long-lived assets.
For the three months ended June 30, 2005 and 2004, revenue from discontinued operations was zero and $354 million, respectively, and
pre-tax income was $22 million and $53 million, respectively. For the
Page 27
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
six months ended June 30, 2005 and 2004, revenue from discontinued operations was zero and $748 million, respectively, and pre-tax
income was $22 million and $123 million, respectively.
The carrying value of assets and liabilities recorded as discontinued operations is:
June 30, December 31,
In millions 2005 2004
--------------------------------------------------------------------------------------------------------------
(Unaudited)
Assets
Cash and equivalents $ 3 $ 2
Other current assets -- 2
--------------------------------------------------------------------------------------------------------------
Total current assets 3 4
--------------------------------------------------------------------------------------------------------------
Investments in partnerships and
unconsolidated subsidiaries -- 107
Other deferred charges 9 11
--------------------------------------------------------------------------------------------------------------
Total assets of discontinued operations $ 12 $ 122
--------------------------------------------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities $ -- $ 2
--------------------------------------------------------------------------------------------------------------
Total current liabilities -- 2
--------------------------------------------------------------------------------------------------------------
Customer advances and other deferred credits 5 4
Other long-term liabilities 10 9
--------------------------------------------------------------------------------------------------------------
Total liabilities of discontinued operations $ 15 $ 15
--------------------------------------------------------------------------------------------------------------
Note 7. Commitments
The following is an update to Edison International's commitments. See Note 9 of "Notes to Consolidated Financial Statements"
included in Edison International's 2004 Annual Report for a detailed discussion.
Leases
During the first quarter of 2005, SCE entered into new power contracts in which it takes virtually all of the power. In accordance
with an accounting standard, these power contracts are classified as operating leases. SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million for 2007 and $43 million for 2008.
Other Commitments
Midwest Generation, LLC (Midwest Generation) and EME Homer City Generation L.P. (EME Homer City) have entered into additional fuel
purchase commitments with various third-party suppliers during the first six months of 2005. These additional commitments are
currently estimated to be $25 million for 2005, $61 million for 2006, $108 million for 2007, $34 million for 2008, and $53 million
for 2009.
Midwest Generation has entered into additional coal transportation commitments during the first six months of 2005. Based on the
committed coal volumes in the fuel supply contracts mentioned above,
Page 28
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
these additional commitments are currently estimated to be $32 million for 2005, $50 million for 2006, $109 million for 2007,
$37 million for 2008, and $74 million for 2009.
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's revised purchased-power capacity
payment commitments under these contracts are currently estimated to be $32 million for 2005, $95 million for 2006, $101 million for
2007 and $84 million for 2008.
Guarantees and Indemnities
Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the
normal course of business. As discussed below, these contracts included performance guarantees, guarantees of debt and
indemnifications.
EME's Tax Indemnity Agreements
In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois,
and previously the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries
entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the
sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax
indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax
indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum
potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these
indemnities. In connection with the termination of the Collins Station lease in April 2004, Midwest Generation will continue to have
obligations under the tax indemnity agreement with the former lease equity investor.
Indemnities Provided as Part of EME's Acquisition of the Illinois Plants
In connection with the acquisition of the Illinois plants, EME agreed to indemnify Commonwealth Edison with respect to specified
environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any
insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all
reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this
indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in
term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability
related to this indemnity.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003
to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities
set forth in the asset sale agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison
and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a
sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a
general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the
number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this
agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal
provision (subject to the right of
Page 29
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of
liability for an asbestos-related settlement, judgment, verdict, or expense. There were between 130 and 170 cases for which Midwest
Generation was potentially liable and that had not been settled and dismissed at June 30, 2005. Midwest Generation had recorded a
$68 million liability at June 30, 2005 related to this matter.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Projecting
future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the
numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than
projected.
Indemnity Provided as Part of EME's Acquisition of the Homer City Facilities
In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to
specific environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1,
1998. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is
not subject to a maximum potential liability and does not have an expiration date. Payments would be triggered under this indemnity
by a claim from the sellers. EME has not recorded a liability related to this indemnity.
Indemnities Provided under EME's Asset Sale Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including
indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental
liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a
purported right of first refusal. Not all indemnities under the asset sale agreements have specific expiration dates. Payments
would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2005, EME
had recorded an $85 million liability related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes
imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items
specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the
nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities
under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims
from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.
Guarantee of Brooklyn Navy Yard Contractor Settlement Payments
On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which holds a 50% partnership
interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn
Navy Yard owns a 286-MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor
asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on
January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale
of EME's interest in Brooklyn Navy
Page 30
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through 2006. At June 30, 2005,
EME had recorded a $7 million liability related to this indemnity.
EME's Capacity Indemnification Agreements
EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project
power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements
terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a
reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have
guaranteed the obligations of Kern River Cogeneration Company and Sycamore Cogeneration Company under their project power sales
agreements to repay capacity payments to the projects' power purchaser in the event that the projects unilaterally terminate their
performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the
indemnification agreements as of June 30, 2005, if payment were required, would be $140 million. EME has no reason to believe that
any of these projects will either cease operations or reduce its electric power producing capability during the term of its power
contract. EME has not recorded a liability related to this indemnity.
Indemnity Provided as Part of SCE's Acquisition of Mountainview
In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims
related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the
Mountainview acquisition. The generating station has not operated since early 2001, and SCE retained certain responsibilities with
respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the
purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities
expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.
Note 8. Asset Impairment and Loss on Lease Termination
On April 27, 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity
investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the
$774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination
of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of
approximately $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.
Note 9. Preferred Stock Subject to Mandatory Redemption
SCE redeemed 807,000 shares of 7.23% $100 cumulative preferred stock at par value on April 30, 2005 and 637,500 shares of 6.05% $100
cumulative preferred stock at par value on May 20, 2005.
Page 31
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Preferred and Preference Stock of Utility Not Subject to Mandatory Redemption
SCE's authorized shares are: $25 cumulative preferred - 24 million and preference - 50 million. SCE issued 4 million shares of
5.349% Series A $100 stated value non-cumulative preference stock on April 20, 2005. The preference stock ranks junior to all of the
preferred stock and senior to all common stock. The preference shares may not be redeemed prior to April 30, 2010. After that date,
SCE may, at its option, redeem the shares in whole or in part and the dividend rate may be adjusted. The preference stock is not
convertible into shares of any other class or series of SCE's capital stock or any other security. Shares of SCE's preferred stock
have liquidation and dividend preferences over shares of SCE's preference stock and common stock.
Page 32
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, 2005 discusses material changes in the financial condition, results of operations and other developments of
Edison International since December 31, 2004, and as compared to the three- and six-month periods ended June 30, 2004. This
discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2004 (the year-ended
2004 MD&A), which was included in Edison International's 2004 annual report to shareholders and incorporated by reference into Edison
International's Annual Report on Form 10-K for the year ended December 31, 2004, filed with the Securities and Exchange Commission.
This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.
Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison
International's knowledge of present facts and circumstances and assumptions about future events and include any statement that does
not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in
this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and
elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will,"
"could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended
to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results
to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results
to differ, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:
o the ability of Edison International to meet its financial obligations and to pay dividends on its common stock if its
subsidiaries are unable to pay dividends;
o the ability of Edison International to effectively execute its strategic plan;
o the ability of Southern California Edison Company (SCE) to recover its costs in a timely manner from its customers through
regulated rates;
o decisions and other actions by the California Public Utilities Commission (CPUC) and other regulatory authorities and delays
in regulatory actions;
o market risks affecting SCE's energy procurement activities;
o access to capital markets and the cost of capital;
o changes in interest rates and rates of inflation;
o governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including
environmental regulations that could require additional expenditures or otherwise affect the cost and manner of doing business;
o risks associated with operating nuclear and other power generating facilities, including operating risks, equipment failure,
availability, heat rate and output;
o the ability to obtain sufficient insurance;
o effects of legal proceedings, changes in tax laws, rates or policies, and changes in accounting standards;
o supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets
to which Edison Mission Energy's (EME) generating units have access;
o EME's and its subsidiaries' ability to provide sufficient collateral in support of their forward sales of electricity and
purchases of fuel;
o competition from other power plants, including new plants and technologies that may be developed in the future;
Page 33
o the cost of and availability of fuel, fuel transportation services, electric transmission services, and required emission credits or
allowances;
o weather conditions, natural disasters and other unforeseen events; and
o changes in the fair value of investments accounted for using fair value accounting.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained
throughout this MD&A. Readers are urged to read this entire report, including the information incorporated by reference, and
carefully consider the risks, uncertainties and other factors that affect Edison International's business. The information contained
in this report is subject to change without notice. Forward-looking statements speak only as of the date they are made and Edison
International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed
by Edison International with the Securities and Exchange Commission. The following discussion provides updated information about
material developments since the issuance of the year-ended 2004 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, 2004.
Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison
International's principal operating subsidiaries are Southern California Edison Company (SCE), Edison Mission Energy (EME) and Edison
Capital. Mission Energy Holding Company (MEHC) (parent), a subsidiary of Edison International, is the holding company for its wholly
owned subsidiary EME. Since the second quarter of 2004, MEHC (parent) and EME are presented as one business segment on a
consolidated basis due primarily to the elimination of EME's so-called "ring fencing" provisions in EME's certificate of
incorporation and bylaws discussed below under "MEHC: Liquidity--MEHC (parent)'s Liquidity." SCE comprises the largest portion of
the assets and revenue of Edison International. In this MD&A, except when stated to the contrary, references to each of Edison
International, SCE, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to
Edison International (parent) or parent company and MEHC (parent) mean Edison International or MEHC on a stand-alone basis, not
consolidated with its subsidiaries. References to SCE, EME or Edison Capital followed by "(stand alone)" mean each such company
alone, not consolidated with its subsidiaries.
This MD&A is presented in 10 major sections. The MD&A begins with a discussion of current developments. Following is a
company-by-company discussion of Edison International's principal business segments (SCE, MEHC, and Edison Capital) and Edison
International (parent). Each principal business segment's discussion includes discussions of liquidity, market risk exposures, and
other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a
consolidated basis, including results of operations and historical cash flow analysis, discontinued operations, new and proposed
accounting principles, commitments, guarantees and indemnities and other developments. These sections should be read in conjunction
with the continuing operations discussion of each principal business segment's section.
Page
----
Current Developments 35
Southern California Edison Company 38
Mission Energy Holding Company 48
Edison Capital 66
Edison International (Parent) 67
Results of Operations and Historical Cash Flow Analysis 69
Discontinued Operations 78
New and Proposed Accounting Principles 79
Commitments, Guarantees and Indemnities 81
Other Developments 82
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CURRENT DEVELOPMENTS
The following section provides a summary of current developments related to Edison International's principal business segments. This
section is intended to be a summary of those current developments that management believes are of most importance since year-end
December 31, 2004. This section is not intended to be an all-inclusive list of all current developments related to each principal
business segment. Further details of each current development discussed below can be found in the specific principal business
segment's section of this MD&A, along with discussions of liquidity, market risk exposures, and other matters as relevant to each
principal business segment.
Passage of Comprehensive Energy Legislation by Congress
A comprehensive energy bill was passed by the House and Senate in the last week of July 2005 and is expected to be signed by the
President on August 8, 2005. This comprehensive legislation includes provisions for the repeal of the Public Utility Holding Company
Act, for amendments of the Public Utility Regulatory Policies Act of 1978, for the introduction of new regulations regarding
"Transmission Operation Improvements," for Transmission Rate Reform, for incentives for various generation technologies and for the
extension through December 31 2007 of production tax credits for wind and other specified types of generation. A number of these
provisions will require implementing regulations by the Federal Energy Regulatory Commission (FERC). Edison International is
currently assessing the potential impact of this legislation and the likely regulations.
SCE: CURRENT DEVELOPMENTS
2006 General Rate Case Proceeding
In December 2004, SCE filed an application with the CPUC for its 2006 General Rate Case (GRC). During the course of the GRC
proceeding, SCE agreed to certain revisions to its original request, updated the revenue requirement for the 2005 cost of capital,
and incorporated a second refueling O&M expense forecast for San Onofre Nuclear Generating Station (San Onofre) in 2006, which
reduced SCE's test year request by $29 million. In a joint comparison exhibit filed by all parties on August 2, 2005, SCE requested
an increase of $341 million in 2006 base rate revenue, followed by a requested increase of $106 million in 2007 and $111 million in
2008. In this exhibit, the ORA revised its previously requested decrease in 2006 revenue to $47 million, a difference of $388
million from SCE's request. The revised ORA request, when combined with proposed reductions from several other intervenors, would
result in a reduction of $273 million in revenue, a difference of $614 million from SCE's request. A decision in this matter is
expected in January 2006. On August 2, 2005 SCE filed a motion requesting the establishment of a GRC Memo Account which would make
the GRC decision retroactive to January 9, 2006, or the first CPUC meeting in January 2006, whichever is earlier. See "SCE:
Regulatory Matters--Transmission and Distribution--2006 General Rate Case Proceeding" for further discussion.
In SCE's 2006 Energy Resource Recovery Account (ERRA) forecast proceeding, SCE is proposing to consolidate the rate changes arising
from the 2006 GRC proceeding with other changes in rates beginning on January 1, 2006 (see "SCE: Regulatory Matters--Generation and
Power Procurement--Generation Procurement Proceedings--Energy Resource Recovery Account Proceedings--2006 ERRA Forecast").
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MEHC: CURRENT DEVELOPMENTS
EME Restructuring Activities
During 2004, EME sold most of its international operations. EME's international operations, except for the Doga project, are
accounted for as discontinued operations in accordance with an accounting standard for the impairment or disposal of long-lived
assets and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as
discontinued operations. In the first quarter of 2005, EME completed the sale of two international projects:
o EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to CBK Projects B.V., the purchasing entity
designated by its partner, for $104 million.
o EME sold its 25% equity interest in the Tri Energy project to IPM for approximately $20 million.
While EME will continue to seek to sell its ownership interest in the Doga project, there is no assurance that such efforts will
result in a sale.
In connection with the sale of its international operations in 2004, together with cash on hand, in January 2005, EME:
o made distributions to MEHC totaling $360 million, which were subsequently used primarily to repay the remaining $285 million
portion of the term loan; and
o repaid its junior subordinated debentures and, consequently, repaid the monthly income preferred securities (MIPS) totaling
$150 million.
In April 2005, EME made an equity contribution of $300 million to Midwest Generation, which used the proceeds to repay indebtedness.
See "MEHC: Liquidity--Midwest Generation Financing" for a discussion of the Midwest Generation financing.
EME has also completed a review of its domestic organization to better align its resources with its domestic business requirements.
Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional
management structure. As part of the restructuring, EME expects to reduce annualized costs by $7 million (pre-tax) although this
decrease is expected to be offset by higher development costs in the future. As a result of these changes, EME recorded charges of
approximately $3 million and $10 million (pre-tax) in the quarter and six months ended June 30, 2005, respectively, for severance and
related costs.
Expiration of the Exelon Power Purchase Agreements
The five-year power purchase agreements between Midwest Generation and Exelon Generation Company expired on December 31, 2004 and,
accordingly, beginning January 1, 2005, all the output from the Illinois plants is considered merchant generation. In 2004,
approximately 53% of the energy and capacity sales from the Illinois plants were to Exelon Generation under the power purchase
agreements.
The Exelon Generation power purchase agreement for coal-fired units was structured to provide significant capacity payments and lower
energy payments which were primarily designed to reimburse the cost of production. The agreement also provided for substantial
capacity payments during the summer months. The Illinois plants continue to derive revenue from sales of capacity and energy to
domestic utilities and power marketers. In the current wholesale energy market, energy prices are
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substantially higher than the energy prices previously set forth in the agreement, but capacity payments are, and are expected to
remain, substantially lower. As a result, the composition of EME's revenue is significantly different in the first half of 2005
compared to 2004. EME's merchant generation is subject to significant volatility as described further in "MEHC: Market Risk
Exposures--Commodity Price Risk."
Wholesale Energy Prices in Illinois
Wholesale energy prices at the Northern Illinois Hub (related to the Illinois plants) have increased substantially in 2005 from the
comparable market prices in 2004 driven largely by increases in the market price of natural gas and oil. The average market price
during the six months ended June 30, 2005 at the Northern Illinois Hub (related to the Illinois plants) increased to $39.01 per MWh,
compared to the average market price at "Into ComEd" and the Northern Illinois Hub of $29.84 per MWh during the six months ended
June 30, 2004.
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SOUTHERN CALIFORNIA EDISON COMPANY
SCE: LIQUIDITY
SCE's liquidity is primarily affected by under- or over-collections of energy procurement-related costs, collateral requirements
associated with power-purchase contracts, and access to capital markets or external financings. At June 30, 2005, SCE's credit and
long-term senior secured issuer ratings from Standard & Poor's and Moody's Investors Service were BBB+ and A3, respectively. At
June 30, 2005, SCE's short-term (commercial paper) credit ratings from Standard & Poor's and Moody's Investors Service were A2 and P2,
respectively. As of June 30, 2005, SCE had $148 million in commercial paper outstanding.
As of June 30, 2005, SCE had cash and equivalents of $176 million ($88 million of which was held by SCE's consolidated Variable
Interest Entities (VIEs)). As of June 30, 2005, long-term debt, including current maturities of long-term debt, was $5.4 billion.
As of June 30, 2005, SCE posted approximately $44 million (comprised of $37 million in cash and $7 million in letters of credit) as
collateral to secure its obligations under power-purchase contracts and to enter into transactions for imbalance energy through the
California Independent System Operator (ISO). 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. In February 2005, SCE replaced its $700 million credit facility with a $1.25 billion senior secured 5-year revolving credit
facility. The security pledged (first and refunding mortgage bonds) for the new facility can be removed at SCE's discretion. If SCE
chooses to remove the security, the credit facility's rating and pricing will change to an unsecured basis per the term of the credit
facility agreement. As of June 30, 2005, SCE's credit facility supported $148 million of commercial paper outstanding and $7
million in letters of credit, leaving $1.1 billion available under the credit facility.
SCE's estimated cash outflows, during the twelve-month period following June 30, 2005, consist of:
o Debt maturities of approximately $597 million, including approximately $246 million of rate reduction notes that are due at
various times in 2005 and 2006, but which have a separate cost recovery mechanism approved by state legislation and CPUC
decisions;
o Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct
and replace generation assets, as discussed below;
o Dividend payments to SCE's parent company. SCE made a $71 million dividend payment to Edison International on both April
28, 2005 and July 28, 2005;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections (as 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 operating cash flows and the issuance of long-term debt and preferred equity.
SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and
transmission infrastructure, and to construct and replace generation assets. In April 2005, the Finance Committee of SCE's Board of
Directors approved a $10.1 billion capital budget
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and forecast for the period 2005-2009, an increase of approximately $700 million over the $9.4 billion amount adopted in October
2004. The increase is mainly due to acceleration of spending in 2005-2009 on several transmission projects, as well as additional
expenditures associated with the replacement of the steam generator and pressurizer at San Onofre. All amounts exceeding the October
2004 forecast are included in either the 2006 GRC or separate regulatory filings for major generation and transmission projects.
Pursuant to the approved capital budget and forecast, SCE expects its capital expenditures to be $1.8 billion, $1.9 billion, and $2.1
billion in 2005, 2006 and 2007, respectively.
On July 18, 2005, SCE gave notice of its election to prepay $29 million of its 6.90% Pollution Control Revenue Bonds (1991 Series),
$30 million of its 6% Pollution Control Revenue Bonds (1992A Series) and $190 million of its 6.4% Pollution Control Revenue Bonds
(1992B Series) on September 8, 2005. The notice is revocable and SCE may, at its option, choose not to prepay such bonds.
SCE has debt covenants that require certain interest coverage, interest and preferred dividend coverage, and debt to total
capitalization ratios to be met. At June 30, 2005, SCE was in compliance with these debt covenants.
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, commodity prices and volume, and counterparty credit.
Fluctuations in interest rates can affect earnings and cash flows. However, fluctuations in commodity prices and volumes, and
counterparty credit losses temporarily affect cash flows, but generally should not affect earnings due to recovery through regulatory
mechanisms. SCE uses derivative financial instruments to manage its market risks, but does not use these instruments for speculative
purposes. See "SCE: Market Risk Exposures" in the year-ended 2004 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
Energy Resource Recovery Account Proceedings
In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to track and recover SCE's: (1) fuel costs
related to its generating stations; (2) purchased-power costs related to cogeneration and renewable contracts; (3) purchased-power
costs related to existing interutility and bilateral contracts that were entered into before January 17, 2001; and (4) new
procurement-related costs incurred on or after January 1, 2003 (the date on which the CPUC transferred back to SCE the responsibility
for procuring energy resources for its customers). SCE recovers these costs on a cost-recovery basis, with no markup for return or
profit. SCE files annual forecasts of the above-described costs that it expects to incur during the following year. As these costs
are subsequently incurred, they
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will be tracked and recovered through the ERRA, but are subject to a reasonableness review in a separate annual ERRA application. If
the ERRA overcollection or undercollection exceeds 5% of SCE's prior year's generation revenue, the CPUC has established a "trigger"
mechanism, whereby SCE can request an emergency rate adjustment in addition to the annual forecast and reasonableness ERRA
applications.
ERRA Trigger Mechanism Filing
On March 25, 2005, SCE submitted a CPUC rate application under the ERRA trigger mechanism, as the recorded undercollection in its
ERRA balancing account as of February 28, 2005 had reached 9.7% of recorded 2004 generation revenue, well above the 5% threshold for
an emergency rate adjustment established by the CPUC. SCE's undercollection had been less than 4% of recorded 2004 generation
revenue at the end of January 2005. A combination of higher procurement costs, a delay in approval of the 2005 ERRA rate change and
other factors contributed to the large increase in the undercollection amount in February 2005. SCE's trigger application stated
that if the CPUC retained recently authorized ERRA rate levels rather than increasing rates, the undercollection would be recovered
by mid-September 2005. On May 26, 2005, the CPUC issued a decision granting SCE's application to maintain its previously authorized
ERRA rate levels.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its procurement-related costs for calendar
year 2004 to be reasonable, and that its contract administration and economic dispatch operations during 2004 complied with its
CPUC-adopted procurement plan. In addition, SCE requested recovery of approximately $13 million associated with Nuclear Unit
Incentive Procedure rewards for efficient operation of the Palo Verde Nuclear Generating Station (Palo Verde) and approximately
$7 million in administrative and general costs incurred to carry out the CPUC's directive to begin procuring energy supplies on
January 1, 2003 following the California energy crisis. The ORA is scheduled to issue its report on SCE's 2004 costs and operations
in mid-August 2005. Evidentiary hearings are scheduled to begin in September 2005 and a decision is expected in late December 2005
or early January 2006.
2005 ERRA Forecast
On March 17, 2005, the CPUC issued a final decision adopting SCE's requested ERRA revenue requirement of $3.3 billion for the 2005
calendar year, an increase of $1 billion over the 2004 revenue requirement. The increase was primarily attributable to increasing
procurement costs, in part because SCE must procure additional energy and capacity in 2005 to replace energy and capacity that had
been provided by a major California Department of Water Resources (CDWR) contract that terminated in December 2004. In addition, the
increase was attributable to additional capacity and associated energy costs resulting from increasing SCE's reserve margin to
fulfill the CPUC's requirement of a 15% to 17% planning reserve and a substantially higher forecasted ERRA undercollected balance as
of December 31, 2004 than the balance included in 2004 rate levels.
2006 ERRA Forecast
SCE submitted an ERRA forecast application on August 1, 2005, in which it forecasts a procurement-related revenue requirement for the
2006 calendar year of $3.8 billion. The 2006 ERRA proceeding revenue requirement is an increase of $509 million over SCE's adopted
2005 ERRA proceeding revenue requirement. The increase is mainly attributable to load growth and resource adequacy requirements
(see the discussion under "--Generation Procurement Proceedings--Resource Adequacy Requirements" included in the year-ended 2004 MD&A),
and the unavailability of SCE's Mohave coal-fired generating
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station (Mohave) after December 31, 2005, and its replacement with higher-cost natural gas generation (see "--Mohave Generating
Station and Related Proceedings").
In addition, the 2006 ERRA forecast application requests the CPUC to consolidate all CPUC-authorized revenue requirements, including
the revenue requirements from the 2006 ERRA forecast application, the 2006 GRC (see "--Transmission and Distribution--2006 General Rate
Case Proceeding") and CDWR-related proceedings (see "--CDWR-Related Matters--CDWR Power Purchases and Revenue Requirement
Proceeding"), for recovery through rates beginning January 1, 2006. SCE's current system average rate for bundled service customers
is 12.6(cent)-per-kilowatt-hour (kWh). SCE expects the 2006 system average rate for bundled service customers to range between
13.9(cent)-per-kWh to 14.4(cent)-per-kWh.
CDWR-Related Matters
CDWR Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2004 MD&A, in December
2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement for 2004 through 2013 will be allocated among
the investor-owned utilities. On June 30, 2005, the CPUC granted, in part, San Diego Gas & Electric's (SDG&E) petition for
modification of the December 2004 decision. The June 30, 2005 decision adopted a methodology that retains the cost-follows-contract
allocation of the avoidable costs, and allocates the unavoidable costs associated with the contracts: 42.2% to Pacific Gas and
Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. This newly adopted allocation methodology
decreases the total costs allocated to SDG&E's customers and increases the total costs allocated to SCE's and PG&E's customers,
relative to the December 2004 decision.
Amounts billed to 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 and therefore have no impact on SCE's earnings. In SCE's 2006 ERRA forecast proceeding, SCE is
proposing to consolidate the impact of the June 30, 2005 decision, as well as other CDWR revenue requirement changes, with other
changes in rates beginning on January 1, 2006 (see "--Energy Resource Recovery Account Proceedings--2006 ERRA Forecast").
Generation Procurement Proceedings
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan was filed on March 7, 2005. On July 21, 2005, the CPUC issued a decision approving SCE's 2005
renewable procurement plan and deferred a ruling on SCE's renewable procurement plan for 2006 through 2014. This decision also
approved the methodology advocated by SCE for determining the amount by which reported renewable procurement should be adjusted to
reflect line losses.
In addition, the decision states that SCE cannot count procurement from certain geothermal facilities towards its 1% annual renewable
procurement requirement, unless such procurement is from production certified as "incremental" by the California Energy Commission.
A 2003 CPUC decision had held that SCE could count procurement from these geothermal facilities toward its 1% annual renewable
procurement requirement.
The geothermal facilities have applied to the California Energy Commission for certification of a portion of the facilities'
production as "incremental." A decision from the California Energy Commission is expected in late August or early September 2005.
It is not clear whether any of the facilities' production
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will be certified as "incremental" or how much, if any, of the "incremental" production from the facilities will be allocated to
SCE's procurement under its contract with the facilities if the California Energy Commission certification is granted.
Depending upon the amount, if any, of California Energy Commission certified "incremental" production allocated to SCE's procurement
under its contract and the manner in which the CPUC implements its flexible rules for compliance with renewable procurement
obligations, SCE may not be in compliance with its statutory renewable procurement obligations for 2003 through 2006 and could be
subject to penalties for those years. The maximum penalty is $25 million per year. To comply with renewable procurement mandates
and avoid penalties for years beyond 2006, SCE will either need to sign new contracts and/or extend existing renewable qualifying
facility (QF) contracts.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and conducted negotiations
with bidders regarding potential procurement contracts. On June 30, 2005, the CPUC issued a resolution approving six renewable
contracts resulting from the solicitation. The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new
request for offers for additional renewable contracts, which SCE contemplates initiating in the third quarter of 2005.
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in southern California. SCE
has issued a Request for Offers (RFO) for new generation resources. SCE has solicited offers for power-purchase agreements lasting
up to 10 years from new generation facilities with delivery under the agreement beginning between June 1, 2006 and August 1, 2008.
SCE has filed an application with the CPUC seeking approval of the RFO and the power-purchase agreements executed under the RFO. SCE
is seeking recovery of the costs of the contracts, through the FERC-jurisdictional rates, from all affected customers. In addition,
SCE seeks CPUC assurance of full cost recovery in CPUC-approved rates, if the FERC denies any recovery. Any power-purchase agreement
that SCE executes as a result of the RFO will be contingent on CPUC approval of the contract and assurance of full cost recovery.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2004 MD&A, the CPUC issued a
final decision in December 2004 on SCE's application regarding the post-2005 operation of Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant parties in an effort
to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been reached to date. Because resolution has not
been reached and because of the lead times required for installation of certain pollution-control equipment and other upgrades
necessary for post-2005 operation, it is probable that Mohave will shut down for at least several years, and perhaps permanently, at
the end of 2005. The outcome of the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. SCE's 2006 ERRA
forecast application assumes Mohave is an unavailable resource for power for 2006 (see "--Energy Resource Recovery Account
Proceedings--2006 ERRA Forecast" for further discussion). Because SCE expects to recover Mohave shut-down costs in future rates, the
outcome of this matter is not expected to have a material impact on earnings.
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San Onofre Nuclear Generating Station
As discussed in the "San Onofre Nuclear Generating Station" disclosure in the year-ended 2004 MD&A, there are several issues related
to the operation and maintenance of San Onofre Units 2 and 3. The following are new developments with respect to San Onofre.
San Onofre Steam Generators
A decision on the reasonableness of the proposed replacement of the San Onofre Units 2 and 3 steam generators and the establishment
of appropriate ratemaking for recovery in rates of the reasonable cost of the replacement project is expected in the fourth quarter
of 2005. By the time of the expected decision, SCE anticipates that it will have incurred approximately $80 million in steam
generator fabrication and associated project costs. SCE will seek recovery of these costs in the event that the CPUC does not
authorize SCE to go forward with steam generator replacement. If the CPUC authorizes SCE to go forward with steam generator
replacement, SCE will recover costs that are reasonably incurred as part of the steam generator replacement capital costs.
2005 Outage Schedule, O&M and Capital Budget Disputes
On April 20, 2005, the San Onofre Units 2 and 3 Board of Review (BOR) held a special meeting to consider the 5-year outage schedule,
revisions to the 2005 operation and maintenance (O&M) budget, and the 2005 capital budget. These matters require unanimous approval
of the BOR. The representatives of SDG&E did not agree with the information presented for approval. Consequently, a vote was not
taken. SCE and SDG&E agreed to consolidate the disputes over the 2005 O&M and 2005 capital budgets and to treat the dispute over the
5-year outage schedule as a separate dispute. The BOR subsequently approved a modified 5-year outage schedule. The parties are
proceeding with the dispute resolution procedures in the Second Amended San Onofre Operating Agreement for the consolidated 2005 O&M
and capital budget disputes, which provide for binding arbitration if the disputes cannot be resolved through informal methods.
Transmission and Distribution
2006 General Rate Case Proceeding
On December 21, 2004, SCE filed its application for a 2006 GRC, requesting an increase of $370 million in SCE's 2006 base rate
revenue, primarily for capital-related expenditures to accommodate infrastructure replacement, customer and load growth. This
increase is also necessary to fund substantially higher O&M expenses, particularly in SCE's transmission and distribution business
unit. SCE also requested that the CPUC authorize continuation of SCE's existing post-test year rate-making mechanism, which would
result in base rate revenue increases of $159 million and $122 million in 2007 and 2008, respectively. If the CPUC approves these
requested increases and allocates them to ratepayer groups on a system average percentage change basis, the total increase over
current base rates is estimated to be 10%.
On April 15, 2005, the ORA submitted testimony recommending that SCE's 2006 base rate revenue be decreased by $93 million, a
difference of $463 million from SCE's request. In addition, the ORA recommended that an additional year, 2009, be added to SCE's GRC
cycle and that the CPUC use a Consumer Price Indexed (CPI) method, applied to the test year revenue requirement, to determine base
rate revenue adjustments in the attrition years (2007 and 2008). SCE had used a budget-based approach to projected capital additions
in the attrition years in its filing. This approach was previously authorized in the 2003 GRC decision. The ORA's CPI methodology
would raise SCE's 2007 base rate revenue by $2 million (as opposed to SCE's requested increase of $159 million) and would decrease
SCE's 2008
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base rate revenue by $10 million (as opposed to SCE's requested increase of $122 million). Portions of the ORA's proposed
adjustments reflect an updated rate of return, authorized by the CPUC subsequent to the filing of SCE's GRC application. On May 6,
2005, several intervenors filed testimony proposing reductions to SCE's 2006 GRC request, which, when combined with the ORA's
recommendation, would result in a reduction of $326 million in revenue, a difference of $696 million from SCE's request.
During the course of the GRC proceeding, SCE agreed to certain revisions to its request, updated the revenue requirement for the 2005
cost of capital, and incorporated a second refueling O&M expense forecast for San Onofre in 2006, which reduced SCE's test year
request by $29 million. In a joint comparison exhibit filed by all parties on August 2, 2005, SCE requested an increase of $341
million in 2006 base rate revenue, followed by a requested increase of $106 million in 2007 and $111 million in 2008. In this
exhibit, the ORA revised its requested decrease in 2006 revenue to $47 million, a difference of $388 million from SCE's request. The
revised ORA request, when combined with proposed reductions from several other intervenors, would result in a reduction of $273
million in revenue, a difference of $614 million from SCE's request. A decision in this matter is expected in January 2006.
On August 2, 2005 SCE filed a motion requesting the establishment of a GRC Memo Account which would make the GRC decision retroactive
to January 9, 2006, or the first CPUC meeting in January 2006, whichever is earlier.
In SCE's 2006 ERRA forecast proceeding, SCE is proposing to consolidate the rate changes arising from the 2006 GRC proceeding with
other changes in rates beginning on January 1, 2006 (see "--Generation and Power Procurement--Generation Procurement Proceedings
--Energy Resource Recovery Account Proceedings--2006 ERRA Forecast").
2006 Cost of Capital
On May 9, 2005, SCE filed an application requesting that the CPUC authorize a return on SCE's common equity and an overall rate of
return for SCE's CPUC-jurisdictional assets for 2006. In its application, SCE requests that the CPUC maintain its 2005 authorized
rate-making capital structure of 43% long-term debt, 9% preferred equity, and 48% common equity for 2006. SCE's application also
requests that the CPUC authorize SCE's 2006 cost of long-term debt of 6.53%, cost of preferred equity of 6.43% and a return on common
equity of 11.80%. A proposed decision is scheduled for November 15, 2005, and a final CPUC decision is anticipated on or before
December 15, 2005. CPUC adoption of SCE's application request would result in a projected $10 million increase in its annual revenue
requirements.
ISO Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning and
Riverside, California over the proper allocation and characterization of certain charges. The order reversed an arbitrator's award
that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those
charges to Scheduling Coordinators (SCs) in the affected zone within the ISO transmission grid. The April 20, 2004 order directed
the ISO to shift the costs from SCs in the affected zone to the responsible Participating Transmission Owner, SCE, and to do so
within 60 days of the April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the
Participating Transmission Owner but also will be credited through the California Power Exchange, SCE's SC at the time. SCE obtained
a stay of the April 20, 2004 order pending resolution of its request for rehearing. On March 30, 2005, the FERC issued an Order
Denying Rehearing. SCE obtained an extension of the stay pending resolution of the appeal SCE has filed with the United States Court
of Appeals for the D.C. Circuit (D.C. Circuit Court).
Page 44
The potential net impact on SCE is estimated to be approximately $20 million to $25 million, including interest. SCE filed a request
for clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the disputed costs in SCE's reliability
services rates. On June 8, 2005, the FERC denied the clarification, noting that during the appeal, the FERC's order is stayed,
therefore SCE is not required to pay at this time. SCE may seek recovery in its reliability service rates of the costs should SCE be
required to pay these costs.
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 $80 million of these unrecovered
costs since 1998. In addition, SCE has accrued interest on these unrecovered costs. The three California utilities appealed the
decisions to the D.C. Circuit Court. On July 12, 2005, the D.C. Circuit Court vacated the FERC's August and November 2002 orders,
and remanded the case to FERC for further proceedings. SCE believes that the D.C. Circuit Court's decision increases the likelihood
that it will recover these costs.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in the year-ended 2004 MD&A, SCE is participating in
several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who allegedly manipulated the
electric and natural gas markets.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including SCE, PG&E, the State of
California and various consumer class action representatives) settling various 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 was required to refund to customers amounts received under the terms of the El Paso settlement (net of legal and
consulting costs) through its ERRA mechanism. In June 2004, SCE received its first settlement payment of $76 million. Approximately
$66 million of this amount was credited to purchased-power expense, and was refunded to SCE's ratepayers through the ERRA over the
following twelve months, and the remaining $10 million was used to offset SCE's incurred legal costs. El Paso has elected to prepay
the additional settlement payments due over a 20-year period and, as a result, SCE received $66 million in May 2005. 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 January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant Corporation and a
number of its affiliates (collectively Mirant), all of whom are debtors in Chapter 11 bankruptcy proceedings pending in Texas. Among
other things, the settlement terms provide for cash and equivalent refunds totaling $320 million, of which SCE's allocated share is
approximately $68 million. The settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of
one of the Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual value of the
unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant settlement was approved
by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. In April and May 2005, SCE received its allocated
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$68 million in cash settlement proceeds. SCE continues to hold its $33 million share of the allowed, unsecured bankruptcy claim.
The Mirant settlement will be refunded to ratepayers as described below.
On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Enron Corporation and a number
of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. Among
other things, the settlement terms provide for cash and equivalent payments from Enron totaling approximately $47 million and an
allowed, unsecured claim in the bankruptcy against one of the Enron entities in the amount of $875 million. SCE's allocable share of
both the cash and allowed claim portions of the settlement consideration has not yet been finally determined, and the value of an
allocable share of the allowed claim will be determined as part of the resolution of the Enron parties' bankruptcies. The settlement
remains subject to the approvals of the FERC, the CPUC and the Enron bankruptcy court. The Enron settlement proceeds will be
refunded to ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum Account (ESMA) for
the purpose of recording the foregoing settlement proceeds (excluding the El Paso settlement) from energy providers and allocating
them in accordance with the terms of the October 2001 settlement agreement entered into by SCE and the CPUC which settled SCE's
lawsuit against the CPUC. This lawsuit sought full recovery of SCE's electricity procurement costs incurred during the energy
crisis. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will be allocated to
recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above and a 10% shareholder incentive
pursuant to the CPUC litigation settlement agreement. Remaining amounts for each settlement are to be refunded to ratepayers through
the ERRA mechanism. In the second quarter of 2005, SCE recorded a $7 million increase to other nonoperating income as a shareholder
incentive related to the Mirant refund received during the second quarter of 2005.
Other Regulatory Matters
Catastrophic Event Memorandum Account
Fire-Related CEMA
In October and November of 2003, wildfires damaged SCE's electrical infrastructure, primarily in the San Bernardino Mountains of
southern California where an estimated 2,085 power poles, 2,059 services, 371 transformers, 557,033 of overhead conductors and 25,822
feet of underground cable were replaced or repaired. SCE notified the CPUC that it initiated a CEMA on October 21, 2003 to track the
incremental costs to restore and repair damage to its facilities. SCE filed an application with the CPUC on December 2, 2004 to seek
recovery of its fire-related costs over a one-year period commencing January 1, 2006. On June 23, 2005, SCE and the ORA filed a
settlement agreement with the CPUC which (i) allows the authorized CEMA Firestorm revenue requirement calculation to be based on
approximately $8 million of incremental operations and maintenance expenses and $20 of incremental capital plant additions and
(ii) allows SCE to continue to record in its Firestorm CEMA the revenue requirement associated with these costs, plus accrued
interest, until the effective date of the final decision in SCE's 2006 GRC. The revenue requirement recorded in SCE's Firestorm CEMA
through April 2005 is approximately $12 million. SCE has forecast the recorded revenue requirement in this account to total
approximately $14 million in December 2005. SCE expects to recover the costs recorded in the Firestorm CEMA account through a
mechanism approved in SCE's 2006 GRC.
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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. For a discussion of item (1) above, see the "Holding Company Proceeding" disclosure in the year-ended 2004
MD&A.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed the proceeding without
addressing some of the issues the proceeding raised (such as the appropriateness of the large utilities' holding company structure
and dividend policies), the CPUC may rule on or investigate these issues in the future.
Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms
Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain shareholder incentives for its
performance achievements in delivering demand-side management and energy efficiency programs. On June 10, 2005, SCE and the ORA
executed a settlement agreement for SCE's outstanding issues concerning SCE shareholder incentives and performance achievements
resulting from the demand-side management, energy efficiency, and low-income energy efficiency programs from program years
1994-2004. In addition, the settlement addresses shareholder incentives and performance achievements for program years 1994-1998,
anticipated but not yet claimed. The settlement agreement recommends, among other things, that SCE be entitled to immediately
recover 92% of the total of SCE's current claims and future claims related to SCE's pre-1998 energy efficiency programs. SCE's total
claim for program years 1994-2004 made in 2000 through 2008, including interest, franchise fees and uncollectibles, is approximately
$46 million. The settling parties agreed that it is reasonable for SCE to recover approximately $42 million of these claims in the
near future as full recovery of all of SCE's outstanding claims as well as future claims related to SCE's pre-1998 energy efficiency
programs. The settlement agreement requires CPUC approval. On June 13, 2005, SCE and the ORA filed a joint motion requesting CPUC
adoption of the settlement agreement. A decision is expected in the fourth quarter of 2005, which if approved, would result in the
recognition of a $42 million increase in earnings. SCE has collected and deferred most the of the expected claims in rates, and
expects to recover the remaining portion of the claims over a 12-month period beginning on January 1, 2006 through the 2006 ERRA
Forecast application (see "--Generation and Power Procurement--Energy Resource Recovery Account Proceedings--2006 ERRA Forecast").
Page 47
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 Midwest Generation Financing
o Capital Expenditures
o MEHC and 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
At June 30, 2005, MEHC had cash and cash equivalents of $62 million (excluding amounts held by EME and its subsidiaries). MEHC's
ability to honor its obligations under the senior secured notes and to pay overhead is substantially dependent upon the receipt of
dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and ultimately Edison
International. See "EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Agreement." Dividends from EME are limited
based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax
considerations and restrictions imposed by applicable law.
Dividends to MEHC (parent)
In January 2005, EME made total dividend payments of $360 million to MEHC (parent). A portion of these payments was used to repay the
remaining $285 million of MEHC's term loan plus interest on January 3, 2005.
EME's Liquidity
At June 30, 2005, EME and its subsidiaries had cash and cash equivalents of $1.6 billion and EME had available the full amount of
borrowing capacity under a $98 million corporate credit facility. EME's consolidated debt at June 30, 2005 was $3.2 billion. In
addition, EME's subsidiaries had $5.0 billion of long-term lease obligations that are due over periods ranging up to 30 years.
Midwest Generation Financing
On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and
restatement of Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility
had provided for a $700 million first priority secured institutional term loan due in 2011 and a $200 million first priority secured
revolving credit, working capital facility due in 2009.
The refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million
revolving credit, working capital facility due in 2011. The previously existing $200 million working capital facility remains in
place. Midwest Generation drew in full upon the new
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$300 million working capital facility at closing and used the proceeds to pay down an equivalent portion of the existing term loan.
After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity date of the repriced term
loan remains 2011. The new working capital facility, together with the existing working capital facility, shares first lien priority
with the repriced term loan. The new working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new
working capital facility is 2011; however, the lenders can request to be fully repaid in 2010.
On the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and
Midwest Generation used the proceeds of this equity contribution to repay the loans outstanding under the new working capital
facility. Thus, after completion of the actions outlined herein, Midwest Generation had $343 million outstanding under its term loan
and $500 million of working capital facilities available for working capital requirements, including credit support for hedging
activities. As of June 30, 2005, approximately $5 million was outstanding under these working capital facilities.
Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as
defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to
distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributes to the equity
contribution equals the amount thereof. Accordingly, Midwest Generation is permitted to distribute 100% of excess cash flow until the
aggregate portion of such distributions attributed to the equity contribution made by EME in Midwest Generation on April 19, 2005
equals $300 million. However, Midwest Generation is required to make concurrently with each distribution an offer to repay debt in
an amount equal to the excess, if any, of one-third of such distribution over the portion thereof attributed to the equity
contribution. Thus, Midwest Generation will not be required to offer to repay debt concurrently with a distribution so long as the
portion of each distribution attributed to the April 19, 2005 equity contribution is at least one-third of such distribution.
Capital Expenditures
The estimated capital and construction expenditures of EME's subsidiaries are $22 million for the final two quarters of 2005 and
$32 million and $13 million for 2006 and 2007, respectively. Non-environmental expenditures relate to upgrades to dust
collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. These expenditures
are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the
estimated expenditures are environmental expenditures of $7 million for the second half of 2005 and $1 million for 2006. The 2005
environmental expenditures relate to selective catalytic reduction system improvements at the Homer City facilities.
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MEHC and EME's Credit Ratings
Overview
Credit ratings for MEHC and its subsidiaries, EME, Midwest Generation, LLC and Edison Mission Marketing & Trading, are as follows:
Moody's Rating S&P Rating
-------------------------------------------------------------------------------
MEHC B2 CCC+
EME B1 B+
Midwest Generation, LLC:
First priority senior secured rating Ba3 BB-
Second priority senior secured rating B1 B
Edison Mission Marketing & Trading Not Rated B+
-------------------------------------------------------------------------------
MEHC 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. MEHC 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.
MEHC does not have any "rating triggers" contained in subsidiary financings that would result in it or EME being required to make
equity contributions or provide additional financial support to its subsidiaries.
The credit ratings of EME are below investment grade and, accordingly, EME has historically provided collateral in the form of cash
and letters of credit for the benefit of counterparties for its price risk management and trading activities related to accounts
payable and unrealized losses. Midwest Generation provides credit support for forward contracts entered into by Edison Mission
Marketing & Trading related to the Illinois plants.
EME and its subsidiaries have provided credit for the benefit of counterparties in the form of cash and letters of credit
($202 million as of June 30, 2005) for price risk management activities of EME (including Midwest Generation and EME Homer City) and
domestic trading activities primarily related to the fair value of open positions.
EME expects to have higher merchant generation in 2005 than in previous years as a result of the expiration in 2004 of the power
purchase agreements between Midwest Generation and Exelon Generation. The increased merchant generation will increase the potential
for margin and collateral requirements. Changes in forward market prices and the strategies adopted for merchant generation could
further increase the need for credit support for price risk management activities related to EME's projects. Using advanced industry
analytics, EME estimates that total margin and collateral requirements to support price risk management could increase to
approximately $400 million in 2005 if 56% of the remaining 2005 output and 33% of the 2006 output from the Illinois plants and Homer
City facilities is sold forward for one year and power prices subsequently increased. Midwest Generation is expected to have cash on
hand and $500 million of working capital facilities that can be used to provide credit support for forward contracts entered into on
behalf of the Illinois plants. As of June 30, 2005, approximately $5 million was outstanding under these facilities. In addition, EME
is expected to have cash on hand and a $98 million working capital facility that can be used to provide credit support for its
subsidiaries. See "--EME's Liquidity" for further discussion.
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Credit Rating of Edison Mission Marketing & Trading
The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer City's) ability to enter into trading
activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City
facilities if Edison Mission Marketing & Trading does not have an investment grade credit rating from Standard & Poor's or Moody's
or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures.
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 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, 2006. EME Homer City continues to be in compliance with the
terms of the consent; however, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback 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--Energy Price Risk Affecting Sales from the Homer City
Facilities."
EME's Liquidity as a Holding Company
Overview
At June 30, 2005, EME had corporate cash and cash equivalents of $1.5 billion to meet liquidity needs. See "--EME's Liquidity." EME
had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at June 30, 2005. Cash
distributions from EME's subsidiaries and partnership investments, 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."
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, 2005, 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 is free to use these distributions unless and until an event of default occurs under its corporate credit facility.
At June 30, 2005, EME also had available $86 million under Midwest Generation EME, LLC's $100 million letter of credit facility with
Citibank, N.A., as Issuing Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation
EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be outstanding under
the facility.
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The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn
owns 100% of Midwest Generation, LLC.
Historical Distributions Received By EME
The following table is presented as an aid in understanding the cash flow of EME's continuing operations 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, 2005 2004
---------------------------------------------------------------------------------------------------
Distributions from Consolidated Operating Projects:
Edison Mission Midwest Holdings (Illinois plants) $ 171 $ --
EME Homer City Generation L.P. (Homer City facilities)(1) 41 49
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects)(2) 29 21
Sunrise Power Company 5 5
Holding company for Doga project 17 15
Holding companies for Westside projects 6 7
Holding companies of other unconsolidated operating projects 4 1
---------------------------------------------------------------------------------------------------
Total Distributions $ 273 $ 98
---------------------------------------------------------------------------------------------------
--------------
(1) On July 1, 2005, EME received a $21 million distribution from Homer City.
(2) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and
Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy
Funding Corp.
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 in circumstances where domestic
tax losses are incurred. The right of MEHC (parent) and EME to receive and the amount and timing of tax-allocation payments is
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 (parent)'s tax losses or the tax losses of EME in the consolidated income tax returns for Edison International
and its subsidiaries. Based on the application of the factors cited above, MEHC (parent) and EME are 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
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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, 2005:
Subsidiary Financial Ratio Covenant Actual
-------------------------------------------------------------------------------------------------------------
Midwest Generation, LLC Interest Coverage Greater than or 2.78 to 1
(Illinois plants) Ratio equal to 1.25 to 1
Midwest Generation, LLC Secured Leverage Less than or 3.18 to 1
(Illinois plants) Ratio equal to 8.75 to 1
EME Homer City Senior Rent Service Greater than 1.7 to 1 2.68 to 1
Generation L.P. Coverage Ratio
(Homer City facilities)
Edison Mission Energy Debt Service Greater than or 2.97 to 1
Funding Corp. Coverage Ratio equal to 1.25 to 1
(Big 4 Projects)
-------------------------------------------------------------------------------------------------------------
For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities
to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "MEHC:
Liquidity--Dividend Restrictions in Major Financings" in the year-ended 2004 MD&A.
MEHC's Interest Coverage Ratio
The following details with respect to MEHC's interest coverage ratio are provided as an aid to understanding the computations set
forth in the indenture governing MEHC's senior secured notes. This information is not intended to measure the financial performance
of MEHC and, accordingly, should not be read in lieu of the financial information set forth in MEHC's consolidated financial
statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture and are
not the same as would be determined in accordance with generally accepted accounting principles.
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MEHC's interest coverage ratio equals Funds Flow from Operations divided by Interest Expense and 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, 2005:
June 30,
In millions 2005
-------------------------------------------------------------------------------------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants $ 313
Homer City 113
First Hydro 30
Other consolidated operating projects 18
Price risk management and energy trading 39
Distributions from unconsolidated Big 4 projects 116
Distributions from other unconsolidated operating projects 107
Interest income 28
Operating expenses (133)
-------------------------------------------------------------------------------------------------
Total EME funds flow from operations $ 631
Operating cash flow from unrestricted subsidiaries 1
Funds flow from operations of projects sold (84)
MEHC (parent) (2)
-------------------------------------------------------------------------------------------------
Total funds flow from operations $ 546
Interest Expense:
EME $ 262
EME - affiliate debt 2
MEHC (parent) interest expense 134
Interest savings on projects sold (65)
-------------------------------------------------------------------------------------------------
Total interest expense $ 333
-------------------------------------------------------------------------------------------------
Interest Coverage Ratio 1.64
-------------------------------------------------------------------------------------------------
--------------
(1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid and project debt service. Operating
cash flow does not include capital expenditures or the difference between cash payments under EME's long-term leases and
lease expenses recorded in 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.
The above interest coverage ratio was determined in accordance with the definitions set forth in the indenture governing MEHC's
senior secured notes. The provisions of the indenture prohibits MEHC, EME and its subsidiaries from incurring additional
indebtedness, except as specified in the indenture, unless MEHC's interest coverage ratio exceeds 2.0 to 1 for the immediately
preceding four fiscal quarters.
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MEHC: MARKET RISK EXPOSURES
Introduction
EME's primary market risk exposures are associated with the sale of electricity and capacity from and the procurement of fuel for its
uncontracted generating plants. These market risks arise from fluctuations in electricity, capacity 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 Fair Value of Financial Instruments
Commodity Price Risk
General Overview
EME's revenue and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy,
ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market
areas where EME's merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services
in these markets are:
o prevailing market prices for coal, natural gas and fuel oil, 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 and regulatory developments affecting the market areas;
o the cost and availability 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.
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A discussion of commodity price risk for the Illinois plants and Homer City facilities is set forth below.
Energy Price Risk - Introduction
Electric power generated at EME's merchant plants is generally sold under bilateral arrangements with domestic utilities and power
marketers with terms of two years or less or into the PJM Interconnection, LLC (PJM) and/or the New York Independent System Operator
(NYISO) markets. As discussed further below, beginning in 2003, EME has been selling a significant portion of the power generated from
its Illinois plants into wholesale power markets, including PJM since May 1, 2004.
EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in
the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure
compliance with EME's risk management policies. Policies are in place which define risk tolerance, and procedures exist which allow
for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be
no assurance that all risks have been accurately identified, measured and/or mitigated.
In addition to the prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the
cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and,
accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary from unit
to unit.
EME uses a "value at risk" analysis in its daily business to identify, measure, monitor and control its overall market risk exposure
in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk allows management
to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the
possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations
of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and
worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits.
Hedging Strategy
EME intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. To the extent that EME does
not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. The
extent to which EME will hedge its market price risk through forward over-the-counter sales depends on several factors. First, EME
will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared
to assuming the risk associated with spot market sales. Second, EME's ability to enter into hedging transactions will depend upon
its, Midwest Generation's and Edison Mission Marketing & Trading's credit capacity and upon the over-the-counter forward sales
markets having sufficient liquidity to enable EME to identify counterparties who are able and willing to enter into hedging
transactions.
Primary counterparties for hedging transactions are utilities and power marketing companies. In addition, the Intercontinental
Exchange and the New York Mercantile Exchange now permit trading in cash settled futures contracts. This allows hedge transactions
to be executed with financial entities such as hedge funds and investment banks. The number of such transactions being cleared has
been steadily increasing recently.
Page 56
In the case of forward sales of generation and capacity from the Illinois plants, 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
for capacity and energy generation of the Illinois plants under an 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 EME's contracting strategy for the Illinois plants. In the case of forward sales
of generation and capacity from the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements
between it and Edison Mission Marketing & Trading. See "--Credit Risk," below.
Energy Price Risk Affecting Sales from the Illinois Plants
Pre-2005 Merchant Sales
Energy generated at the Illinois plants was historically sold under three power purchase agreements between Midwest Generation and
Exelon Generation Company, under which Exelon Generation was obligated to make capacity payments for the plants under contract and
energy payments for the energy produced by these plants and taken by Exelon Generation. The power purchase agreements began on
December 15, 1999. The capacity payments provided the units under contract with revenue for fixed charges, and the energy payments
compensated those units for all, or a portion of, variable costs of production. The three power purchase agreements with Exelon
Generation had all been terminated by December 31, 2004.
To the extent that energy and capacity from the Illinois plants was not sold under the power purchase agreements with Exelon
Generation, it was sold on a wholesale basis through a combination of bilateral agreements, forward energy sales and spot market
sales. Approximately 51% of the energy and capacity sales from the Illinois plants in the first six months of 2004 were made on a
wholesale basis outside of the power purchase agreements.
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." Since the expansion of PJM and the commencement
of the Midwest Independent Transmission System Operator (MISO) locational marginal pricing markets, EME believes that the most liquid
delivery locations for wholesale trading in the Midwest are the Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM, and the
Cinergy Hub in MISO. Because of proximity, the Midwest Generation assets are primarily hedged with transactions at the Northern
Illinois Hub, but from time to time may be hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub.
Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois
control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, which linked eastern PJM and the
Northern Illinois control areas of the PJM system and improved access from the Illinois plants into the broader PJM market. Under the
PJM tariff, Midwest Generation is no longer required to arrange and pay separately for transmission when making sales to wholesale
buyers located within the PJM system.
Following the expansion of the PJM system described above, sales of electricity from the Illinois plants have been made on the basis
of 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 the Illinois plants, replaced sales previously made as bilateral sales and spot sales "Into
ComEd" and "Into AEP." See "MEHC: Other Development--Regulatory Matters" in the year-ended 2004 MD&A for a more detailed discussion
of developments regarding Commonwealth Edison's joining PJM, and "--Basis Risk" below for a discussion of locational marginal pricing.
Page 57
2005 Merchant Sales
Beginning on January 1, 2005, electric power generated at the Illinois plants is generally sold under bilateral arrangements with
terms of two years or less, or into the PJM market. The PJM pool has a short-term market, which establishes an hourly clearing price.
The Illinois plants are situated in the new expanded western PJM control area and are physically connected to high-voltage
transmission lines serving this market.
The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2005 and
2004.
2005(1) 2004
-------------------------------------------------------------------
January $ 38.36 $ 27.88(2)
February 34.92 29.98(2)
March 45.75 30.66(2)
April 38.98 27.88(2)
May 33.60 34.05(1)
June 42.45 28.58(1)
-------------------------------------------------------------------
Six-Month Average $ 39.01 $ 29.84
-------------------------------------------------------------------
--------------
(1) Represents average historical market prices for energy as quoted for sales into the Northern Illinois
Hub. Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time
prices as published by PJM.
(2) Represents average historical market prices for energy for "Into ComEd." Energy prices were determined
by obtaining broker quotes and other public price sources for "Into ComEd" delivery points. See
discussion under "--Pre-2005 Merchant Sales" above for further discussion regarding the replacement of
sales "Into ComEd" with sales into the expanded PJM.
Forward market prices at 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 by the
Illinois plants into these markets may vary materially from the forward market prices set forth in the table below.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois
Hub at June 30, 2005:
24-Hour Northern
Illinois Hub
2005 Forward Energy Prices*
-----------------------------------------------------------------------
July $ 46.64
August 48.68
September 37.55
October 33.44
November 35.26
December 41.22
2006 Calendar "strip"(1) $ 42.73
-----------------------------------------------------------------------
--------------
(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 information from other public
sources relating to the Northern Illinois Hub delivery point.
Page 58
The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at
June 30, 2005:
2005 2006
-------------------------------------------------------------------
Megawatt hours 9,386,086 9,707,014
Average price/MWh(1) $ 38.15 $ 41.84
-------------------------------------------------------------------
--------------
(1) The above hedge positions include forward contracts for the sale of power during different periods of
the year and the day. Market prices tend to be higher during on-peak periods during the day and
during summer months, although there is significant variability of power prices during different
periods of time. Accordingly, the above hedge position at June 30, 2005 is not directly comparable to
the 24-hour Northern Illinois Hub prices set forth above.
Energy Price Risk Affecting Sales from the Homer City Facilities
Electric power generated at the Homer City facilities is generally sold under bilateral arrangements with terms of two years or less,
or into the PJM market. 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 historical market prices for energy per megawatt-hour in PJM during the first six months of
2005 and 2004:
24-Hour PJM
Historical Energy Prices*
-----------------------------
2005 2004
----------------------------------------------------------------------------
January $ 45.82 $ 51.12
February 39.40 47.19
March 47.42 39.54
April 44.27 43.01
May 43.67 44.68
June 46.63 36.72
----------------------------------------------------------------------------
Six-Month Average $ 44.54 $ 43.71
----------------------------------------------------------------------------
--------------
* Energy prices were calculated at the Homer City busbar (delivery point) using historical hourly real-time
prices provided on the PJM-ISO web-site.
Forward market prices at the PJM West 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 by the Homer
City facilities into these markets may vary materially from the forward market prices set forth in the table below.
Page 59
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, 2005:
24-Hour PJM West Hub
2005 Forward Energy Prices*
------------------------------------------------------------
July $ 56.50
August 58.55
September 46.95
October 43.52
November 44.72
December 51.25
2006 Calendar "strip"(1) $ 53.66
------------------------------------------------------------
--------------
(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 information from public
sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are
generally higher than the prices at the Homer City busbar.
The following table summarizes Homer City's hedge position at June 30, 2005:
2005 2006
----------------------------------------------------------------
Megawatt hours 4,641,100 5,256,000
Average price/MWh(1) $ 44.94 $ 51.50
----------------------------------------------------------------
--------------
(1) The above hedge positions include forward contracts for the sale of power during different periods of
the year and the day. Market prices tend to be higher during on-peak periods during the day and
during summer months, although there is significant variability of power prices during different
periods of time. Accordingly, the above hedge position at June 30, 2005 is not directly comparable to
the 24-hour PJM West Hub prices set forth above.
The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have averaged
6% lower than energy prices at the PJM West Hub during the past twelve months with the monthly average difference during this period
ranging from zero to 13%, which occurred in June 2005. See "--Basis Risk" below for a discussion of the difference.
Basis Risk
Sales made from the Illinois plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices
at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the
individual plant busbars, 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 individual plant busbars. A liquid market does
exist for a delivery point known as the PJM West Hub in the case of Homer City and for a delivery point known as the Northern
Illinois Hub in the case of the Illinois plants. EME's price risk management activities use these delivery points to enter into
forward contracts. EME's revenue with respect to such forward contracts include:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot prices at the busbar
of the plant involved, plus,
Page 60
o sales to third parties under such forward contracts at designated delivery points (generally the PJM West Hub for Homer City and the
Northern Illinois Hub for the Illinois plants) less the cost of purchasing power at spot prices at the same designated delivery
points to fulfill obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific
locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can
cause the price of a specific delivery point to be raised or lowered relative to other locations depending on how the point is
affected by transmission constraints. During the past 12 months, transmission congestion in PJM has resulted in prices at the Homer
City busbar being lower than those at the PJM West Hub (the primary trading hub in PJM for the Homer City facilities) by an average
of 6%. By contrast, during the past 12 months, transmission congestion in PJM has not resulted in prices at the Northern Illinois Hub
being significantly different from those at the individual busbars of the Illinois plants.
By entering into forward contracts using the PJM West Hub and the Northern Illinois Hub as the delivery points, EME is exposed to
"basis risk," which occurs when forward contracts are executed on a different basis (PJM West Hub for Homer City and the Northern
Illinois Hub for the Illinois plants) than the actual point of delivery (the individual plant busbars). In order to mitigate basis
risk resulting from forward contracts using the 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 basis risks.
Coal Price and Transportation Risk
The Illinois plants use approximately 18 million to 20.5 million tons of coal annually, primarily obtained from the Southern Powder
River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million tons of coal annually, obtained from mines
located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements typically ranging from one
year to six years in length. The following table summarizes the percent of expected coal requirements for the next five years that
are under contract at June 30, 2005.
Percent of Coal Requirements
Under Contract
---------------------------------------
2005(1) 2006 2007 2008 2009
--------------------------------------------------------------------------------
Illinois plants 110% 98% 96% 29% 29%
Homer City facilities(2) 105% 53% 49% 14% 10%
--------------------------------------------------------------------------------
--------------
(1) The percentage in 2005 is calculated based on coal supply and expected generation requirements for a full year.
(2) Adjusted for expected deliveries under an agreement in principle to settle outstanding contract disputes.
See "Commitments, Guarantees and Indemnities--Fuel Supply Contracts" for more information regarding fuel supply
interruptions and the dispute with two suppliers.
EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachia coal, which is
purchased for the Homer City facilities, increased considerably since 2004. In January 2004, prices of Northern Appalachia coal (with
13,000 British Thermal units (Btu) content and ‹3.0 SO2 MMBtu content) were below $40 per ton and increased to more than $60 per ton
during 2004. At July 22, 2005, the Energy Information Administration reported the price of Northern Appalachia coal at $52.50 per
ton. The overall increase in the Northern Appalachia coal price has been largely attributed
Page 61
to greater demand from domestic power producers and increased international shipments of coal to Asia. Prices of Powder River Basin
(PRB) coal (with 8,800 Btu content and 0.8 SO2 MMBtu content), which is purchased for the Illinois plants, have recently increased
due to curtailment of coal shipments for the remainder of 2005 due to increased PRB coal demand from the other regions (east), rail
constraints (discussed below) and higher prices for SO2 allowances. At July 22, 2005, the Energy Information Administration reported
the price of $9.66 per ton, which compares to 2004 prices generally below $7 per ton.
During the first half of 2005, the rail lines that bring coal from the Powder River Basin to the East, including to EME's Illinois
plants, were damaged from derailments caused by heavy rains. The railroads are in the process of making repairs to these rail lines
and have advised their customers, including EME, that shipments will be curtailed by 15% to 20% during the second half of 2005. EME
is working with its transportation provider to minimize any disruption of planned shipments. Based on communication with the
transportation provider, EME expects to continue receiving a sufficient amount of coal to generate power at historical levels while
these repairs are being completed.
Emission Allowances Price Risk
Under the federal Acid Rain Program (which requires electric generating stations to hold sulfur dioxide allowances) and Illinois and
Pennsylvania regulations implementing the federal NOx SIP Call requirement, EME purchases (or sells) emission allowances based on the
amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. As part of the
acquisition of the Illinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been
or are allocated to these plants.
The price of emission allowances, particularly SO2 allowances issued through the US EPA Acid Rain Program increased substantially
during 2004 and the first half of 2005. The average price of purchased SO2 allowances increased to $707 per ton during the six months
ended June 30, 2005 from $281 per ton during the six months ended June 30, 2004. The increase in the price of SO2 allowances has been
attributed to reduced numbers of both allowance sellers and prior vintage allowances.
Credit Risk
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies,
financial institutions, and other companies, 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 re-contracting the product at a price
different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated damages
owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to
the time such counterparty defaulted.
To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would
be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and
mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used whenever possible
and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or
lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME
manages the credit risk on the portfolio based on credit ratings using published ratings of counterparties and other publicly
disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. A risk management committee
Page 62
regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be
wholly successful in mitigating credit risk or that collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities as either: (i) the sum of 60 days of
accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid
accounts receivable and the current fair value of open positions. 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, 2005, the amount of exposure, broken down by the credit ratings of EME's counterparties was as follows:
June 30,
In millions 2005
-------------------------------------------------------------
S&P Credit Rating
A or higher $ 2
A- 15
BBB+ 82
BBB 17
BBB- 1
Below investment grade --
-------------------------------------------------------------
Total $ 117
-------------------------------------------------------------
EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements.
Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase
agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such
power plant.
In addition, coal for the Illinois plants and the Homer City facilities is purchased from suppliers under contracts which may be for
multiple years. A number of the coal suppliers to the Illinois plants and the Homer City facilities do not currently have an
investment grade credit rating and, accordingly, EME may have limited recourse to collect damages from a supplier in the event of
default. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral
arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk
from coal suppliers.
For the six months ended June 30, 2005, one customer accounted for 11% of EME's consolidated operating revenue. For the six months
ended June 30, 2004, one customer accounted for 15% and a second customer, Exelon Generation, accounted for 33% of EME's consolidated
operating revenue. For more information on Exelon Generation see "--Commodity Price Risk--Energy Price Risk Affecting Sales from the
Illinois Plants--Pre-2005 Merchant Sales."
Interest Rate Risk
Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or
other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations
are subject to interest rate risk. The fair market value of MEHC's total long-term obligations (including current portion) was
$4.6 billion at June 30, 2005, compared to the carrying value of $4.0 billion. The fair market value of MEHC's parent only total
long-term obligations was $1.0 billion at June 30, 2005, compared to the carrying value of $790 million.
Page 63
Fair Value of Financial Instruments
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used in EME's continuing operations
for purposes other than trading by risk category:
June 30, December 31,
In millions 2005 2004
-----------------------------------------------------------------------
Commodity price:
Electricity $ (122) $ 10
-----------------------------------------------------------------------
In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions
based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts
takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The
following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management
assets and liabilities as of June 30, 2005:
Total Maturity Maturity Maturity Maturity
Fair Less than 1 to 3 4 to 5 Greater than
In millions Value 1 year years years 5 years
---------------------------------------------------------------------------------------------------
Prices actively quoted $ (122) $ (115) $ (7) $ -- $ --
---------------------------------------------------------------------------------------------------
Energy Trading Derivative Financial Instruments
EME's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading. Edison Mission
Marketing & Trading seeks to generate profit from the volatility of the price of electricity, fuels and transmission by buying and
selling contracts for their sale or provision, as the case may be, which are referred to as energy trading activities. Energy trading
activities are primarily focused on understanding the relative values between different locations in the eastern power grid;
particularly those locations in PJM, MISO, and NYISO. See "--Commodity Price Risk--Basis Risk" above for a discussion of locational
marginal pricing. Edison Mission Marketing & Trading, utilizes over-the-counter products as well as financial transmission rights,
transmission congestion contracts, and virtual incremental and decremental generation bids to capture the difference in prices
between various locations.
The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2005 and December 31, 2004,
are set forth below:
June 30, 2005 December 31, 2004
------------------------------ -----------------------------
In millions Assets Liabilities Assets Liabilities
---------------------------------------------------------------------------------------
Electricity $ 114 $ 18 $ 125 $ 36
---------------------------------------------------------------------------------------
Page 64
The change in the fair value of trading contracts for the six months ended June 30, 2005, was as follows:
In millions
------------------------------------------------------------------
Fair value of trading contracts at January 1, 2005 $ 89
Net gains from energy trading activities 45
Amount realized from energy trading activities (38)
------------------------------------------------------------------
Fair value of trading contracts at June 30, 2005 $ 96
------------------------------------------------------------------
Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except
for the power sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term
power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair value based upon a
discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the
non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the
valuation method and the related fair value of energy trading assets and liabilities (as of June 30, 2005):
Maturity
Total Maturity Maturity Maturity Greater
Fair Less than 1 to 3 4 to 5 than
In millions Value 1 year years years 5 years
---------------------------------------------------------------------------------------------------
Prices actively quoted $ 6 $ 6 $ -- $ -- $ --
Prices based on models and other
valuation methods 90 (2) 9 7 76
---------------------------------------------------------------------------------------------------
Total $ 96 $ 4 $ 9 $ 7 $ 76
---------------------------------------------------------------------------------------------------
MEHC: OTHER DEVELOPMENT
Regulatory Matters
There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of MEHC's
annual report, except as follows:
The MISO's day-ahead and real-time locational marginal pricing markets commenced operation on April 1, 2005. Since that time, the
wholesale electricity trading community has opted to trade a product delivered at the Cinergy Hub as defined by MISO rather than at
the "Into Cinergy" location that was used previously. EME anticipates that the opening of the MISO market will lead to increased
liquidity in the Midwest electricity markets because locational marginal pricing provides a liquid and credible cash index against
which the trading community can settle contracts. See "MEHC: Other Development--Regulatory Matters" in the year-ended 2004 MD&A for
further discussion.
Page 65
EDISON CAPITAL
EDISON CAPITAL: CURRENT DEVELOPMENTS
Edison Capital has investments in three regionally focused global infrastructure funds: Europe, Asia and Latin America. All three
funds follow fair value accounting, in which changes in the fair value of investments are recorded directly in earnings. Edison
Capital records its share of the funds' earnings as equity in income from partnerships and unconsolidated affiliates. Edison
Capital's share of earnings from these funds totaled $13 million and $59 million, after tax, for the three- and six-month periods
ended June 30, 2005, respectively. These earnings mainly resulted from gains on investments in several telecommunications companies
in Eastern Europe. Edison Capital also received $38 million and $69 million of cash distributions from its fund investments during
the three- and six-month periods ended June 30, 2005, respectively, and ended the current quarter with a $187 million investment
balance in the global infrastructure funds.
EDISON CAPITAL: LIQUIDITY
Edison Capital's main sources of liquidity are tax-allocation payments from Edison International, lease rents and distributions from
its global infrastructure fund investments.
Edison Capital's cash requirements during the twelve-month period following June 30, 2005, primarily consist of:
o Funding new investments in renewable energy;
o Scheduled debt principal and interest payments; and
o General and administrative expenses.
As of June 30, 2005, Edison Capital had unrestricted cash and cash equivalents of $240 million and long-term debt, including current
maturities, of $312 million. Additionally, as of June 30, 2005, Edison Capital had unfunded commitments of $25 million. Edison
Capital's pursuit of new renewable energy investments depends upon economic and regulatory conditions and continuation of government
policies supporting renewable energy.
Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation payments from Edison International
(parent) and expected cash flow from operating activities.
At June 30, 2005, Edison Capital's long-term debt had credit ratings of Ba1 and BB+ from Moody's Investors Service and Standard &
Poor's, respectively.
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
2004 MD&A for a complete discussion of Edison Capital's market risk exposures.
EDISON CAPITAL: OTHER DEVELOPMENT
Federal Income Taxes
Edison International received Revenue Agent Reports from the Internal Revenue Service (IRS) in August 2002 and in January 2005
asserting deficiencies in federal corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years,
respectively. Among the issues raised were items related to Edison Capital. See "Other Developments--Federal Income Taxes" for
further discussion of these matters.
Page 66
EDISON INTERNATIONAL (PARENT)
EDISON INTERNATIONAL (PARENT): LIQUIDITY
The parent company's liquidity and its ability to pay interest, debt principal, operating expenses and dividends to common
shareholders are affected by dividends from subsidiaries, tax-allocation payments under its tax-allocation agreements with its
subsidiaries, and access to capital markets or external financings. Edison International was focused on reducing its parent company
debt in 2004, and as of June 30, 2005, had no debt outstanding.
Edison International (parent)'s 2005 cash requirements primarily consist of:
o Dividends to common shareholders. On February 17, 2005 and May 19, 2005, the Board of Directors of Edison International
declared a $0.25 per share quarterly common stock dividend. The two separate dividend payments of $81 million each were paid on
May 3, 2005 and August 1, 2005; and
o General and administrative expenses.
Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, short-term
borrowings, when necessary, and dividends from its subsidiaries. At June 30, 2005, Edison International (parent) had approximately
$46 million of cash and cash equivalents on hand. In February 2005, Edison International (parent) entered into a $750 million senior
unsecured 5-year revolving credit facility and as of June 30, 2005, the entire $750 million was available under its credit facility.
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 equity
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 on a 13-month weighted average basis. 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, dividends on SCE's preferred and preference stock, and actions by the CPUC. SCE made
a $71 million dividend payment to Edison International on both April 28, 2005 and July 28, 2005.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At June 30, 2005, its interest coverage
ratio was 1.64 to 1. See "MEHC: Liquidity--MEHC's Interest Coverage Ratio." In addition, MEHC's certificate of incorporation and
senior secured note indenture contain restrictions on MEHC's ability to declare or pay dividends or distributions (other than
dividends payable solely in MEHC's common stock). These restrictions require the unanimous approval of MEHC's Board of Directors,
including its independent director, before it can declare or pay dividends or distributions, as long as any indebtedness is
outstanding under the indenture. MEHC did not declare or pay 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). MEHC has not declared or made dividend payments to Edison
International in 2005. EME and its subsidiaries have certain dividend restrictions as discussed in the "MEHC: Liquidity--Dividend
Restrictions in Major Financings" section.
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Edison Capital's ability to make dividend payments is currently restricted by covenants in its financial instruments, which require
Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital
satisfied this minimum net worth requirement as of June 30, 2005. Edison Capital has not declared or made dividend payments to
Edison International in 2005.
EDISON INTERNATIONAL (PARENT): MARKET RISK EXPOSURES
Although Edison International (parent) had no debt outstanding as of June 30, 2005, the parent company may be exposed to changes in
interest rates which may result from future borrowing and investing activities. The proceeds of such borrowings and investing
activities may be 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 was a party to a CPUC holding company proceeding. See "SCE: Regulatory Matters--Other Regulatory
Matters--Holding Company Proceeding" for a discussion of this matter.
Federal Income Taxes
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. See "Other
Developments--Federal Income Taxes" for further discussion of these matters.
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EDISON INTERNATIONAL (CONSOLIDATED)
The following sections of the MD&A are on a consolidated basis. The section begins with a discussion of Edison International's
consolidated results of operations and historical cash flow analysis. This is followed by discussions of discontinued operations,
new and proposed accounting principles, commitments, guarantees and indemnities and other developments.
RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS
The following subsections of "Results of Operations and Historical Cash Flow Analysis" provide a discussion on the changes in various
line items presented on the Consolidated Statements of Income as well as a discussion of the changes on the Consolidated Statements
of Cash Flows.
Results of Operations
Edison International recorded consolidated earnings of $201 million, or 61(cent)per common share for the three-month period ended June
30, 2005, compared to a loss of $374 million, or $1.15 per common share for the three-month period ended June 30, 2004. The
increased earnings primarily reflect lower net interest expense, improved results at MEHC (including higher wholesale energy prices),
and higher revenue at SCE. Included in earnings is a lease termination charge of $586 million or $1.80 per common share at MEHC in
2004, net positive regulatory adjustments of $117 million or 36(cent)per common share at SCE in 2004, as well as earnings from
discontinued operations at MEHC in both 2005 and 2004.
Edison International recorded consolidated earnings of $403 million, or $1.23 per common share for the six-month period ended June
30, 2005, compared to a loss of $276 million, or 85(cent)per common share for the six-month period ended June 30, 2004. The increased
earnings primarily result from higher wholesale energy prices at MEHC's Illinois plants, higher earnings at SCE associated with the
2003 GRC received in July 2004, lower net interest expense, earnings from Edison Capital's interest in the Emerging Europe
Infrastructure Fund, and increased trading income at MEHC. The 2005 earnings include a charge at MEHC of $15 million or 5(cent)per
common share related to the early extinguishment of debt. The 2004 results include a charge of $586 million or $1.80 per common
share related to EME's termination of the Collins Station lease, a net gain of $27 million or 8(cent)per common share at MEHC from the
sale of its interest in Four Star Oil & Gas and the Brooklyn Navy Yard project, and earnings of $117 million or 36(cent)per common share
at SCE from regulatory items related to its 2003 GRC decision. Both years include earnings from discontinued operations related to
MEHC's international projects.
The tables below presents Edison International's earnings and earnings per common share for the three- and six-month periods ended
June 30, 2005 and 2004, and the relative contributions by its subsidiaries.
In millions, except per common share amounts Earnings (Loss) Earnings (Loss) per Common Share
-----------------------------------------------------------------------------------------------------------------------
Three-Month Period Ended June 30, 2005 2004 2005 2004
-----------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 161 $ 242 $ 0.49 $ 0.74
MEHC -- (636) -- (1.96)
Edison Capital 25 11 0.08 0.04
Edison International (parent) and other (6) (17) (0.02) (0.05)
-----------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings (Loss)
from Continuing Operations 180 (400) 0.55 (1.23)
-----------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations 21 26 0.06 0.08
-----------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 201 $ (374) $ 0.61 $ (1.15)
-----------------------------------------------------------------------------------------------------------------------
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In millions, except per common share amounts Earnings (Loss) Earnings (Loss) per Common Share
---------------------------------------------------------------------------------------------------------------------
Six-Month Period Ended June 30, 2005 2004 2005 2004
---------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 292 $ 341 $ 0.89 $ 1.05
MEHC 25 (675) 0.08 (2.07)
Edison Capital 77 22 0.24 0.07
Edison International (parent) and other (19) (35) (0.06) (0.12)
---------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings (Loss)
from Continuing Operations 375 (347) 1.15 (1.07)
---------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations 28 72 0.08 0.22
---------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change -- (1) -- --
---------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 403 $ (276) $ 1.23 $ (0.85)
---------------------------------------------------------------------------------------------------------------------
Earnings from Continuing Operations
SCE's earnings from continuing operations were $161 million and $292 million for the three- and six-month periods ended June 30,
2005, respectively, compared to $242 million and $341 million for the same periods in 2004. SCE's 2004 earnings from continuing
operations included net positive regulatory items of $117 million or 36(cent)per common share primarily related to the implementation of
SCE's 2003 GRC decision. The decrease in earnings for the three- and six-month period ended June 30, 2005, compared to the same
periods in 2004, is primarily due to the net positive regulatory items recorded in 2004, partially offset by higher revenue
associated with the timing of the 2003 GRC decision. SCE received the 2003 GRC decision in July 2004, which resulted in a catch-up
adjustment in the third quarter of 2004 for the amounts related to the first half of 2004, as well as an increase in earnings for the
second half of 2004. The variances for both periods also reflects higher revenue authorized by the CPUC for 2005, the favorable
resolution of certain tax issues and lower net interest costs (quarter only), which were mostly offset by higher operating expenses.
MEHC's earnings from continuing operations were breakeven and $25 million for the three- and six-months ended June 30, 2005,
respectively, compared to a loss of $636 million and a loss of $675 million for the same periods in 2004, respectively. MEHC's
second quarter results in 2005 include a $15 million, or 5(cent)per common share, charge related to the early retirement of debt. MEHC's
results for both the three- and six-month periods in 2004 included a charge of $586 million, or $1.80 per common share, related to
the termination of the Collins Station lease. The Collins Station was deemed uneconomic and operations ceased effective September
30, 2004. The increase for the three- and six-month periods ended June 30, 2005, as compared to the same periods in 2004, is mainly
due to the lease termination charge in 2004, improved earnings of $50 million, or 16(cent)per common share, and $156 million, or 48(cent)per
common share, over the three- and six-month periods ended June 30, 2004, respectively, primarily due to higher wholesale energy
prices at MEHC's Illinois plants, lower net corporate interest expense, the resolution of a prior-year tax issue and higher income
from Edison Mission Marketing & Trading. On an annual basis, MEHC's earnings are seasonal with higher earnings expected during the
summer months. In addition to the items discussed above, the six-month period increase was also partially offset by net gains of $27
million on the sale of MEHC's interests in Four Star Oil & Gas and the Brooklyn Navy Yard project in the six-month period ended June
30, 2004, and a $15 million loss on the early retirement of debt for the six-month period ended June 30, 2005.
Earnings in the second quarter of 2005 for Edison Capital were $25 million and $77 million for the three- and six-month periods ended
June 30, 2005, respectively, compared to $11 million and $22 million for the same periods in 2004, respectively. The three- and
six-month period increases, as compared to the same periods in 2004, is primarily due to Edison Capital's share of income from its
investments in the Emerging Europe Infrastructure Fund. During the second quarter of 2005, the Fund recorded a gain resulting from
an announced purchase of a wireless company held by the Fund. Edison Capital's share of
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gain was about $13 million. The Fund has subsequently exited this investment and the related gain has been realized.
The loss for "Edison International parent company and other" decreased by $11 million and $16 million for the three- and six-month
periods ended June 30, 2005, respectively, as compared to the same periods in 2004, primarily due to lower net interest expense. The
six-month period decrease was partially offset by higher taxes.
Operating Revenue
SCE's retail sales represented approximately 83% of electric utility revenue for both the three- and six month periods ended June 30,
2005, compared to approximately 82% and 85% of electric utility revenue for the three- and six-month periods ended June 30, 2004,
respectively. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is
generally significantly higher than other quarters.
The following table sets forth the major changes in electric utility revenue:
Three-Month Period Six-Month Period
Ended June 30, Ended June 30,
In millions 2005 vs. 2004 2005 vs. 2004
---------------------------------------------------------------------------------------------
Electric utility revenue
Rate changes (including unbilled) $ (93) $ (102)
Sales volume changes (including unbilled) 118 170
Sales for resale (14) 44
SCE's variable interest entities 8 109
Other (including intercompany transactions) 8 16
---------------------------------------------------------------------------------------------
Total $ 27 $ 237
---------------------------------------------------------------------------------------------
Total electric utility revenue increased by $27 million and $237 million for the three- and six-month periods ended June 30, 2005,
respectively (as shown in the table above), as compared to the same periods in 2004. The variance in electric utility revenue from
rate changes reflects the implementation of the 2003 GRC, effective in August 2004. As a result, generation rates decreased revenue
by approximately $30 million and $150 million for the three- and six-month periods ended June 30, 2005, respectively, and
distribution rates increased revenue by approximately $100 million and $255 million for the three- and six-month periods ended June
30, 2005, respectively. Included in the variance in electric utility revenue from rate changes are higher deferrals of revenue of
approximately $210 million and $275 million for the three- and six-month periods ended June 30, 2005, respectively, related to
balancing account overcollections in 2005, as compared to 2004. The increase in electric utility revenue resulting from sales volume
changes was mainly due to an increase in kWh sold and SCE providing a greater amount of energy to its customers from its own sources
in 2005, compared to 2004, in which the CDWR provided a greater amount of energy to SCE's customers. Electric utility revenue from
sales for resale represents the sale of excess energy. 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. SCE's variable interest entities revenue represents
the recognition of revenue resulting from the consolidation of SCE's variable interest entities on March 31, 2004.
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 $409 million and $919 million for the three- and
Page 71
six-month periods ended June 30, 2005, respectively, compared to $546 million and $1.2 billion for the same periods in 2004.
Nonutility power generation revenue increased $58 million and $180 million for the three- and six-month periods ended June 30, 2005,
respectively, as compared to the same periods in 2004. The three-month period increase was mainly due to higher energy revenue of
approximately $100 million and $10 million at EME's Illinois plants and Homer City facilities, respectively, resulting from increased
average realized energy prices, and an increase of $16 million related to MEHC's trading activities at EME's wholly owned subsidiary,
Edison Mission Marketing & Trading. The three-month period increase was partially offset by lower capacity revenue of approximately
$60 million at EME's Illinois plants from the expiration of the power-purchase agreements with Exelon Generation. The six-month
period increase was mainly due to higher energy revenue of approximately $215 million and $55 million at EME's Illinois plants and
Homer City facilities, respectively, resulting from higher average realized energy prices and increased generation, as well as an
increase of $39 million related to trading activities at Edison Mission Marketing & Trading. During the first quarter of 2004, an
unplanned outage at EME's Homer City facilities contributed to lower generation. The year-to-date increase was partially offset by
lower capacity revenue of approximately $80 million at EME's Illinois plants, as well as a decrease of $29 million (representing
revenue for the first quarter of 2005) due to the deconsolidation of EME's Doga project at March 31, 2004, in accordance with
accounting standards.
Nonutility power generation revenue is generally higher in the third quarter than revenue related to other quarters of the year. Due
to a higher demand for electricity resulting from warmer weather during the summer months, nonutility power generation revenue
generated from EME's Homer City facilities and the Illinois plants are generally higher during the third quarter of each year.
Operating Expenses
Fuel Expense
Fuel expense for the six-month period ended June 30, 2005 increased $207 million, as compared to the same period in 2004, mainly due
to the consolidation of SCE's variable interest entities in March 31, 2004. Fuel expense related to SCE's variable interest entities
for the six-month period ended June 30, 2005 was $398 million, compared to $187 million for the comparable period in 2004.
Purchased-Power Expense
Purchased-power expense increased $216 million and $24 million for the three- and six-month periods ended June 30, 2005,
respectively, as compared to the same periods in 2004. The quarter increase was mainly due to higher unrealized losses of
approximately $205 million related to economic hedging transactions resulting from increased hedging activities in 2005, as compared
to 2004, higher expenses of approximately $100 million (an approximate increase of $175 million for the year-to-date period)
resulting from an increase in the number of bilateral contracts in 2005, as compared to 2004, and higher expenses of approximately $30
million related to QFs purchases. These increases were partially offset by approximately $130 million of energy settlement refunds
received in 2005 (see "SCE: Regulatory Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas Markets"). In
addition to the items discussed above, the year-to-date increase also resulted from an increase in exchanged energy of approximately
$50 million due to higher volumes and a true-up of exchanged energy. The year-to-date variance was partially offset by higher
unrealized gains of approximately $150 million in the first quarter of 2005, as well as a decrease of $186 million reduction in
purchased-power resulting from the consolidation of SCE's variable interest entities on March 31, 2004.
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.
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Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)-per-kWh. Average spot natural
gas prices were slightly higher during 2005 as compared to 2004. The higher expenses related to power purchased from QFs were mainly
due to higher average spot natural gas prices, partially offset by lower kWh purchases.
Provisions for Regulatory Adjustment Clauses - Net
Provisions for regulatory adjustment clauses - net increased $8 million and $75 million for the three- and six-month periods ended
June 30, 2005, respectively, as compared to the same periods in 2004. The quarter and year-to-date increases reflect a net effect of
approximately $180 million of regulatory adjustments related to the implementation of SCE's 2003 GRC decision recorded in the second
quarter of 2004 and lower costs incurred and deferred (approximately $50 million and $60 million for the three- and six-month periods
ended June 30, 2005, respectively, as compared to the same periods in 2004) associated with the bark beetle infestation. The 2003
GRC regulatory adjustments primarily related 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 incremental cost incentive pricing
mechanism for dry cask storage. These items which resulted in increases in the provision for regulatory adjustment clauses were
partially offset by net unrealized losses of $205 million and $55 million for the three- and six-month period ended June 30, 2005,
respectively, related to economic hedging transactions (mentioned above in purchased-power expense) that, if realized, would be
refunded to ratepayers and net undercollections of purchased-power, fuel, and O&M costs of approximately $70 million and $135 million
for the three- and six-months ended June 30, 2005, respectively, which were deferred in balancing accounts for future recovery.
Other Operation and Maintenance Expense
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
---------------------------------------------------------------------------------------------
SCE $ 569 $ 577 $ 1,167 $ 1,154
MEHC 225 200 414 390
Other 21 19 43 37
---------------------------------------------------------------------------------------------
Edison International Consolidated $ 815 $ 796 $ 1,624 $ 1,581
---------------------------------------------------------------------------------------------
SCE's other operation and maintenance expense decreased slightly for the three-month period ended June 30, 2005, and increased
slightly for the six-month period ended June 30, 2005, as compared to the same periods in 2004. The decrease was due to lower costs
of approximately $50 million incurred in 2005 compared to 2004 related to the removal of trees and vegetation associated with the
bark beetle infestation, almost entirely offset by higher benefit-related costs of approximately $10 million in 2005 compared to
2004, higher worker's compensation accruals of approximately $10 million in 2005 compared to 2004, and an increase of approximately
$10 million in demand side management and energy efficiency costs in 2005 as compared to 2004 (which are recovered through regulatory
mechanisms approved by the CPUC). In addition to the above mentioned variance explanations, the year-to-date variance was also due
to the recognition of approximately $30 million in O&M expenses as a result of the consolidation of SCE's variable interest entities,
an increase in reliability costs of approximately $45 million due to an increase in must run units to improve the reliability of the
California ISO systems operations (which are recovered through regulatory mechanisms approved by the FERC), and a decrease of
approximately $55 million in generation-related expenses primarily related to lower outage and refueling costs in 2005, as compared
to 2004. In 2004, there was a scheduled major overhaul at SCE's Four Corners coal facility, as well as a refueling outage at SCE's
San Onofre Unit 2.
Page 73
MEHC's other operation and maintenance expense increased for the three- and six-month periods ended June 30, 2005, as compared to the
same periods in 2004, mainly due to higher plant operation costs of approximately $10 million and $25 million for the three and six
months ended June 30, 2005, respectively, at MEHC's Illinois plants due to higher planned maintenance, and higher maintenance costs
of approximately $10 million for the three months ended June 30, 2005 at MEHC's Homer City facilities. The year-to-date variance
also reflects a decrease of approximately $10 million in plant operating lease costs due to the termination of EME's Collins Station
lease in April 2004.
Asset Impairment and Loss on Lease Termination
Asset impairment and loss on lease termination in 2004 includes a $951 million loss on the termination of EME's Collins Station
lease. MEHC concluded that the Collins Station was not economically competitive in the marketplace given generation overcapacity and
ceased operations effective September 30, 2004.
Other Income and Deductions
Interest and Dividend Income
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
---------------------------------------------------------------------------------------------
SCE $ 9 $ 3 $ 17 $ 6
MEHC 14 1 26 3
Other 2 7 4 13
---------------------------------------------------------------------------------------------
Edison International Consolidated $ 25 $ 11 $ 47 $ 22
---------------------------------------------------------------------------------------------
SCE's interest and dividend income increased for the six-month period ended June 30, 2005, as compared to the same period in 2004,
mainly due to higher interest income on balancing account undercollections in 2005 compared to 2004.
MEHC's interest and dividend income increased for both the three- and six-month periods ended June 30, 2005, as compared to the same
periods in 2004, primarily due to higher interest income resulting from higher average cash balances during the first six months of
2005, compared to the corresponding period of 2004.
Equity in Income from Partnerships and Unconsolidated Subsidiaries - Net
Equity in income from partnerships and unconsolidated subsidiaries - net increased $14 million and $79 million for the three- and
six-month periods ended June 30, 2005, respectively, as compared to the same periods in 2004. The increases are mainly due to
increased earnings of approximately $20 million and $93 million for the three- and six-month periods ended June 30, 2005,
respectively, from Edison Capital's global infrastructure funds (see "Edison Capital: Current Developments"), partially offset by
the effects of accounting for variable interest entities consolidated upon adoption of a new accounting pronouncement in second
quarter 2004, resulting in a decrease of approximately $42 million and $66 million for the three- and six-month periods ended June
30, 2005, respectively, compared to $42 million for both the three- and six-month periods ended June 30, 2004. As a result, SCE now
consolidates projects previously treated under the equity method by EME.
Third quarter equity in income from partnerships and unconsolidated subsidiaries - net from EME's energy projects is materially
higher than equity in income from partnerships and unconsolidated
Page 74
subsidiaries - net related to other quarters of the year due to warmer weather during the summer months and because a number of EME's
energy projects located on the west coast have power sales contracts that provide for higher payments during the summer months.
Other Nonoperating Income
Three Months Six Months
Ended June 30, Ended June 30,
----------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
----------------------------------------------------------------------------------------------
SCE $ 18 $ 9 $ 35 $ 40
MEHC 2 -- 2 47
----------------------------------------------------------------------------------------------
Edison International Consolidated $ 20 $ 9 $ 37 $ 87
----------------------------------------------------------------------------------------------
SCE's other nonoperating income for the three-month period ended June 30, 2005 includes a $7 million shareholder incentive related to
the Mirant settlement received in the second quarter of 2005 (see "SCE: Regulatory Matters--Transmission and Distribution--Wholesale
Electricity and Natural Gas Markets"). The year-to-date 2005 amount also includes a $10 million reward for the efficient operation
of Palo Verde during 2003, which was approved by the CPUC in 2005. SCE's other nonoperating income for the six-month period ended
June 30, 2004 includes $19 million in rewards for the efficient operation of Palo Verde during 2001 and 2002, which were approved by
the CPUC in 2004.
MEHC's other nonoperating income in 2004 primarily related to a pre-tax gain of $47 million on the sale of EME's interest in Four
Star Oil & Gas on January 7, 2004.
Interest Expense - Net of Amounts Capitalized
Three Months Six Months
Ended June 30, Ended June 30,
-----------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
-----------------------------------------------------------------------------------------------
SCE $ 96 $ 101 $ 198 $ 204
MEHC 101 115 204 214
Other 7 36 15 71
-----------------------------------------------------------------------------------------------
Edison International Consolidated $ 204 $ 252 $ 417 $ 489
-----------------------------------------------------------------------------------------------
MEHC's interest expense - net of amounts capitalized decreased for the three- and six-month periods ended June 30, 2005, as compared
to the same periods in 2004, mainly due to the repayment of MEHC (parent)'s $385 million term loan ($100 million of the term loan was
repaid in July 2004 and the remaining $285 million of the term loan was repaid in January 2005). The year-to-date decrease was
partially offset by higher interest expense at EME's Illinois plants, primarily attributable to higher interest rates on fixed rate
debt issued in April 2004.
The decrease in interest expense - net of amounts capitalized related to Other for the three- and six-month periods ended June 30,
2005, as compared to the same periods in 2004, was mainly due to the elimination of Edison International (parent)'s debt. Edison
International (parent) has had no debt outstanding since the fourth quarter of 2004.
Loss on Early Extinguishment of Debt
The loss on early extinguishment of debt in the six-month period ended June 30, 2005, consisted of a $20 million loss related to the
early repayment of MEHC (parent)'s $385 million term loan and a
Page 75
$4 million loss related to the early repayment of EME's junior subordinated debentures during the first quarter of 2005.
Income Taxes
Three Months Six Months
Ended June 30, Ended June 30,
-----------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
-----------------------------------------------------------------------------------------------
SCE $ 59 $ 155 $ 124 $ 223
MEHC (22) (400) (6) (410)
Other (3) (19) 20 (34)
-----------------------------------------------------------------------------------------------
Edison International Consolidated $ 34 $ (264) $ 138 $ (221)
-----------------------------------------------------------------------------------------------
Edison International's income tax expense increased $298 million and $359 million for the three- and six-month periods ended June 30,
2005, respectively, as compared to the same periods in 2004, primarily due to increases in pre-tax income. The increases were
partially offset by reductions in accrued tax liabilities at SCE and MEHC in 2005 to reflect progress in settlement negotiations
related to prior-year tax liabilities, property-related flow-through items at SCE, and adjustments made to tax balances at SCE and
MEHC.
Edison International's composite federal and state statutory rate was approximately 40% for the three-and six-month periods ended
June 30, 2005. The lower effective tax rate of 16% and 27% realized in the three- and six-month periods ended June 30, 2005,
respectively, was primarily due to reductions in tax liabilities at SCE and MEHC, property-related flow-through items at SCE, the
benefits received from low-income housing and production tax credits at Edison Capital, and adjustments to tax balances at SCE and
MEHC.
Minority Interest
Minority interest represents the effects of the adoption of a new accounting pronouncement in second quarter 2004 related to SCE's
variable interest entities.
Income from Discontinued Operations
Edison International's earnings from discontinued operations were $21 million in the second quarter of 2005, compared to $26 million
in the same period last year. The 2005 earnings result primarily from dividends received from EME's Lakeland Power project. The
2004 results include earnings from MEHC's international assets that have been sold. Earnings from discontinued operations were
$28 million for the six-month period ended June 30, 2005, compared to $72 million for the same period last year. The 2005 earnings
result primarily from dividends from EME's Lakeland Power project and gains on the sale of MEHC's CBK and Tri-Energy international
projects. The 2004 results include earnings from MEHC's international assets held for sale.
Cumulative Effect of Accounting Change - Net of Tax
Edison International's results for the six-month period ended June 30, 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.
Page 76
Historical Cash Flow Analysis
The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating, financing and investing
activities.
Cash Flows from Operating Activities
Net cash provided (used) by operating activities:
In millions Six-Month Period Ended June 30, 2005 2004
---------------------------------------------------------------------------------------------
Continuing operations $ 812 $ (331)
---------------------------------------------------------------------------------------------
The 2005 change in cash provided by operating activities from continuing operations was mainly due to a $960 million lease
termination payment in 2004 related to EME's Collins Station lease. In addition, the change in cash provided by operating activities
results from the timing of cash receipts and disbursements related to working capital items.
Cash Flows from Financing Activities
Net cash provided (used) by financing activities:
In millions Six-Month Period Ended June 30, 2005 2004
---------------------------------------------------------------------------------------------
Continuing operations $ (907) $ 1,573
---------------------------------------------------------------------------------------------
Cash (used) provided by financing activities from continuing operations mainly consisted of long-term and short-term debt payments at
SCE and EME.
Financing activities in the six-month period ended June 30, 2005, were mainly due to activities at SCE. SCE's first quarter 2005
financing activity included the issuance of $650 million of first and refunding mortgage bonds. The issuance included $400 million
of 5% bonds due in 2016 and $250 million of 5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of its
8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding
mortgage bonds due February 2007 (Series 2003B). SCE's second quarter financing activity included the issuance of $350 million of
its 5.35% first and refunding mortgage bond due in 2035 (Series 2005E). A portion of the proceeds was used to redeem $316 million of
its 8% first and refunding mortgage bonds due in 2007 (Series 2003B). In addition, in April 2005, SCE issued 4,000,000 shares of
Series A preference stock (non-cumulative, $100 liquidation value) and received net proceeds of approximately $394 million.
Approximately $81 million of the proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred stock, 7.23%
Series, and approximately $64 million of the proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred
stock, 6.05% Series. MEHC's first quarter financing activity included the repayment of the remaining $285 million of the term loan
and the repayment of the junior subordinated debentures of $150 million. MEHC's second quarter activity included a $302 million
repayment in April 2005 related to Midwest Generation's existing term loan. Financing activities in 2005 also include dividend
payments of $163 million paid by Edison International to its shareholders.
Financing activities in the six-month period ended June 30, 2004, were mainly due to activities at SCE. SCE's first quarter 2004
financing activity included the issuance of $300 million of 5% bonds due in 2014, $525 million of 6% bonds due in 2034 and $150
million of floating rate bonds due in 2006. The proceeds from these issuances were used to redeem $300 million of its 7.25% first
and refunding mortgage bonds due March 2026, $225 million of its 7.125% first and refunding mortgage bonds
Page 77
due July 2025, $200 million of its 6.9% first and refunding mortgage bonds due October 2018, and $100 million of its 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.
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Six-Month Period Ended June 30, 2005 2004
----------------------------------------------------------------------------------------------
Continuing operations $ (502) $ (912)
----------------------------------------------------------------------------------------------
Cash flows from investing activities are affected by capital expenditures, EME's sales of assets and SCE's funding of nuclear
decommissioning trusts.
Investing activities for the six-month period ended June 30, 2005, reflect $774 million in capital expenditures at SCE, primarily for
transmission and distribution assets, including approximately $21 million for nuclear fuel acquisitions, and $35 million in capital
expenditures at EME. In addition, investing activities include $140 million in net sales of auction rate securities at EME and
$124 million in proceeds received in 2005 from the sale of EME's 25% investment in the Tri Energy project and EME's 50% investment in
the CBK project.
Investing activities for the six-month period ended June 30, 2004 reflect, $718 million in capital expenditures at SCE, primarily for
transmission and distribution assets, including approximately $31 million for nuclear fuel acquisitions, and $31 million in capital
expenditures at EME. In addition, investing activities include $285 million of acquisition costs related to the Mountainview project
as SCE, and $118 million in proceeds received from the sale of 100% of EME's stock of Edison Mission Energy Oil & Gas and the sale of
EME's interest in the Brooklyn Navy Yard project.
DISCONTINUED OPERATIONS
On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15,
2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately
$20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.
On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to Corporacion IMPSA S.A.,
pursuant to a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a
pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.
EME previously owned and operated a 220-MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the
Lakeland project. The ownership of the project was held through
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EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with
Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU
Europe). EME ceased consolidating the activities of Lakeland Power Ltd. in 2002, when an administrative receiver was appointed
following a default by Norweb Energi Ltd. under the power sales agreement. Accordingly, EME accounts for its ownership of Lakeland
Power Ltd. on the cost method and earnings are recognized as cash is distributed from this entity.
As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination
of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited (TXU Energy), entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy
proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received(pound)112 million (approximately $210 million) from
the TXU administrators, representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately $217 million).
From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of
(pound)20 million (approximately $37 million) to EME on April 7, 2005 comprised of(pound)7 million (approximately $13 million) for a secured loan
which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd.,
and (pound)13 million (approximately $24 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power
Ltd. This distribution was recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay
to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining
secured and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with
Lakeland Power Ltd.'s liquidation.
EME estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the
above payments will be approximately $64 million. These remaining proceeds are expected to be received in late 2005 or in 2006, as
Lakeland Power Ltd.'s liquidation progresses. Because the amounts required to settle outstanding claims and UK taxes have not been
finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net
income may vary materially from the above estimate.
For all periods presented, the results of EME's international projects discussed above have been accounted for as discontinued
operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal
of long-lived assets.
For the three months ended June 30, 2005 and 2004, revenue from discontinued operations was zero and $354 million, respectively, and
pre-tax income was $22 million and $53 million, respectively. For the six months ended June 30, 2005 and 2004, revenue from
discontinued operations was zero and $748 million, respectively, and pre-tax income was $22 million and $123 million, respectively.
NEW AND PROPOSED ACCOUNTING PRINCIPLES
In March 2005, the FASB issued an interpretation related to accounting for conditional asset retirement obligations. This
Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement
obligation (ARO) if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of
settlement. This Interpretation is effective December 31, 2005. Edison International is assessing the impact of this Interpretation
on its results of operations and financial condition.
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A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison
International currently uses the intrinsic value accounting method for stock-based compensation. On April 14, 2005, the Securities
and Exchange Commission announced a delay in the effective date for the new standard to fiscal years beginning after June 15, 2005.
Edison International will implement the new standard effective January 1, 2006 by applying the modified prospective transition
method. The difference in expense between the two accounting methods is an increase of $2 million and $5 million in expense for the
three- and six-month periods ended June 30, 2005.
The American Jobs Creation Act of 2004 included a tax deduction on qualified production activities income (including income from the
sale of electricity). In December 2004, the FASB issued guidance that this deduction should be accounted for as a special deduction,
rather than a tax rate reduction. Accordingly, the special deduction is recorded in the year it is earned. The tax deduction is not
expected to materially affect Edison International's 2005 financial statements. Edison International is evaluating the effect that
the manufacturer's deduction will have in subsequent years.
In March 2004, the FASB issued new accounting guidance for the effect of participating securities on EPS calculations and the use of
the two-class method. The new guidance, which was effective in second quarter 2004, requires the use of the two-class method of
computing EPS for companies with participating securities (including vested stock options with dividend equivalents).
Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding.
Net income (loss) available for common stock was $200 million and $(374) million for the three months ended June 30, 2005, and 2004,
respectively, and was $400 million and $(276) million for the six months ended June 30, 2005, and 2004, respectively. In arriving at
net income, dividends on preferred securities and preferred stock have been deducted.
In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003), Consolidation of
Variable Interest Entities (VIEs). 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 was 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.
Edison International implemented the Interpretation for its special purpose entities 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. Edison International recorded a cumulative effect
adjustment that decreased net income by less than $1 million, net of tax, due to negative equity at one of Edison Capital's newly
consolidated entities.
On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax positions. An enterprise would recognize, in its
financial statements, the benefit of a tax position only if that position is probable of being sustained on audit based solely on the
technical merits of the position. The comment period for the exposure draft ends on September 12, 2005; the earliest the guidance
would be implemented would be December 31, 2005. Edison International is evaluating the potential impact of the proposal on its
financial statements.
On July 14, 2005, the FASB issued an exposure draft on accounting for a change or projected change in the timing of cash flows
relating to income taxes generated by a leveraged lease transaction. The proposed accounting guidance would require a lessor to
perform a recalculation of a leveraged lease
Page 80
when there is a change in the timing of the realization of tax benefits generated by that lease. It would also require a lessor to
reevaluate the lease's classification as a leveraged lease when a recalculation of the lease is performed. The comment period for
the exposure draft ends on September 12, 2005; the earliest the guidance would be implemented would be December 31, 2005. Edison
International is evaluating the potential impact of the proposal on its financial statements.
COMMITMENTS, GUARANTEES AND INDEMNITIES
The following is an update to Edison International's commitments, guarantees and indemnities. See the "Commitments, Guarantees and
Indemnities" section of the year-ended 2004 MD&A for a detailed discussion.
Fuel Supply Contracts
Midwest Generation and EME Homer City have entered into additional fuel purchase commitments with various third-party suppliers
during the first six months of 2005. These additional commitments are currently estimated to be $25 million for 2005, $61 million for
2006, $108 million for 2007, $34 million for 2008, and $53 million for 2009.
Beginning in 2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis,
Inc. Unionvale and Genesis claimed that alleged geologic conditions at the Genesis No. 17 Mine in Pennsylvania, which is one source
of coal under these multi-source coal contracts, constituted force majeure and excused contract performance. These two agreements
together provide for the delivery to EME Homer City of approximately 20% of EME Homer City's clean coal requirements in 2005 and
2006, and approximately 10% in 2007.
On December 21, 2004, Unionvale and Genesis gave notice of termination of one of the agreements, which was scheduled to run through
December 2007, under a provision that they claim allows either party to the agreement to terminate if an event of force majeure lasts
30 days or more. Unionvale and Genesis allege that the geologic problems encountered at the Genesis No. 17 Mine have continued beyond
a 30-day period and excuse their obligation to deliver coal under the agreement. The parties' second agreement with a term through
December 2006 does not contain the same termination provision, and the suppliers have sought contract modifications to the term,
quantity, quality and price provisions of this agreement. On April 26, 2005, Unionvale and Genesis informed EME Homer City that the
Genesis No. 17 Mine had been shut down and that no delivery of coal from that mine would be made under either agreement.
EME Homer City disputes the force majeure claim and the suppliers' reliance upon this claim to excuse their performance under the
multi-source coal agreements. EME Homer City has filed suit against Unionvale and Genesis in Pennsylvania state court seeking, among
other things, equitable relief by way of an order requiring the defendants to fulfill their contractual obligations and other
monetary relief. The parties have reached an agreement in principle to settle the dispute and are continuing settlement negotiations.
Contracts have been awarded to alternate suppliers, and inventory strategies adjusted, to reflect and offset the delivery shortfall
for 2005.
During the second quarter of 2005, SCE amended one of its coal fuel contracts which reduced the term of the contract. As a result of
this modification, the fuel supply contract payments for the thereafter period decreased by $152 million.
Gas and Coal Transportation
Midwest Generation has entered into additional coal transportation commitments during the first six months of 2005. Based on the
committed coal volumes in the fuel supply contracts mentioned above,
Page 81
these additional commitments are currently estimated to be $32 million for 2005, $50 million for 2006, $109 million for 2007,
$37 million for 2008, and $74 million for 2009.
Power-Purchase Contracts
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's revised purchased-power capacity
payment commitments under these contracts are currently estimated to be $32 million for 2005, $95 million for 2006, $101 million for
2007 and $84 million for 2008.
Leases
During the first quarter of 2005, SCE entered into new power contracts in which SCE takes virtually all of the power. In accordance
with an accounting standard, these power contracts are classified as operating leases. SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million for 2007 and $43 million for 2008.
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 28 identified sites at SCE (22 sites) and EME (6 sites
related to Midwest Generation) is $86 million, $84 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 $113 million, all of which is related to SCE. The upper limit of this range of
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costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In
addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has
33 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $31 million of its recorded liability,
through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to
recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $57 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 $12 million to $25 million. Recorded costs for the twelve months ended June 30, 2005 were
$12 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental
remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
Edison International has reached a settlement with the IRS on tax issues and pending affirmative claims relating to its 1991-1993 tax
years. This settlement, which was signed by Edison International in March 2005 and approved by the United States Congress Joint
Committee on Taxation on July 27, 2005, will result in a third quarter 2005 net earnings benefit for Edison International of
approximately $56 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. Many of the asserted tax
deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would be
deductible on future tax returns of Edison International.
As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income
taxes in audits of the 1994-1996 and 1997-1999 tax years associated with Edison Capital's cross-border leases. The IRS is
challenging Edison Capital's foreign power plant and electric locomotive sale/leaseback transactions (termed a sale-in/lease-out or
SILO transaction). The estimated federal and state taxes deferred from these leases were $44 million in the 1994-1996 and 1997-1999
audit periods and $32 million in subsequent years through 2004.
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The IRS is also challenging Edison Capital's foreign power plant and electric transmission system lease/leaseback transactions
(termed a lease-in, lease-out or LILO transaction). The estimated federal and state income taxes deferred from these leases were
$558 million in the 1997-1999 audit period and $565 million in subsequent years through 2004. The IRS has also proposed interest and
penalties in its challenge to each SILO and LILO transaction.
Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in
effect at the time the transactions were entered into. Written protests were filed to appeal the 1994-1996 audit adjustments
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 International also filed protests in March 2005 to appeal the issues raised
in the 1997-1999 audit. Edison International intends to contest these proposed deficiencies through administrative appeals and
litigation, if necessary.
Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (termed a
Service Contract). The IRS did not assert an adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge
this lease in subsequent audit cycles similar to positions asserted against the SILOs discussed above. The estimated federal and
state taxes deferred from this lease are $221 million through 2004.
If Edison International is not successful in its defense of the tax treatment for the SILOs, LILOs and the Service Contract, the
payment of taxes, exclusive of any interest or penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow. However, the FASB is currently considering changes to the accounting for
leases. If the proposed accounting changes are adopted and Edison International's tax treatment for the SILOs, LILOs and Service
Contract is significantly altered as a result of IRS challenges, there could be a material effect on reported earnings by requiring
Edison International to reverse earnings previously recognized as a current period adjustment and to report these earnings over the
remaining life of the leases. At this time, Edison International is unable to predict the impact of the ultimate resolution of these
matters.
The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to 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. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits
relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these
tax losses are sustained.
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 and the SCE subsidiary contingent liability company transaction described above. Edison International
filed these amended returns under protest retaining its appeal rights.
Page 84
EDISON INTERNATIONAL
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, under the supervision and 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 that 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 that 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 85
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
There were no significant developments with respect to litigation of Edison International or its subsidiaries that may be material to
Edison International during the quarterly period ended June 30, 2005. See Note 4, "Contingencies - Navajo Nation Litigation" of
Notes to Consolidated Financial Statements for minor updates on litigation involving SCE and the Navajo Nation which was previously
reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K for the year ended December 31, 2004, and in Part II,
Item 1 of Edison International's Quarterly Report on Form 10-Q for the period ending March 31, 2005.
Page 86
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser
(as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International's equity
securities that is registered pursuant to Section 12 of the Exchange Act.
(c) Total (d) Maximum
Number of Shares Number (or
(or Units) Approximate
Purchased Dollar Value)
as Part of of Shares
(a) Total Publicly (or Units) that May
Number of Shares (b) Average Announced Yet Be Purchased
(or Units) Price Paid per Plans or Under the Plans or
Period Purchased(1) Share (or Unit)(1) Programs Programs
--------------------------------------------------------------------------------------------------------------
April 1, 2005 to 1,365,212 $35.69 -- --
April 30, 2005
May 1 to 2,487,648 $36.66 -- --
May 31, 2005
June 1, 2005 to 2,028,639 $38.93 -- --
June 30, 2005
--------------------------------------------------------------------------------------------------------------
Total 5,881,499 $37.22 -- --
--------------------------------------------------------------------------------------------------------------
-------------------
(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 Direct 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 87
Item 4. Submission of Matters to a Vote of Security Holders
At Edison International's Annual Meeting of Shareholders on May 19, 2005, two matters were put to a vote of the shareholders: the
election of ten directors, and a shareholder proposal on "Future Golden Parachutes."
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 275,203,301 9,749,519
France A. Cordova 281,025,664 3,927,156
Bradford M. Freeman 273,336,533 11,616,287
Bruce Karatz 276,415,431 8,537,389
Luis G. Nogales 279,308,159 5,644,661
Ronald L. Olson 267,758,773 17,194,047
James M. Rosser 274,212,351 10,740,469
Richard T. Schlosberg, III 274,942,487 10,010,333
Robert H. Smith 274,824,271 10,128,549
Thomas C. Sutton 268,929,361 16,023,459
----------------------------------------------------------------------------------
The shareholder proposal on "Future Golden Parachutes," which received the affirmative vote of a majority of the votes cast, was
adopted. The proposal received the following numbers of votes:
For Against Abstentions Broker Non-Votes
-------------------------------------------------------------------------
139,589,433 99,030,265 4,264,144 42,068,978
-------------------------------------------------------------------------
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Item 6. Exhibits
Edison International
10.1 2005 Performance Goals for the Edison International Executive Incentive Compensation Plan, as adopted May 19,
2005 (File No. 1-9936, attached as Exhibit 99.1 to Edison International Form 8-K dated May 25, 2005)*
10.2 Edison International Director Compensation Schedule, as adopted May 19, 2005 (File No. 1-9936, attached as
Exhibit 99.2 to Edison International Form 8-K dated May 25, 2005)*
10.3 Edison International Director Nonqualified Stock Options 2005 Terms and Conditions (File No. 1-9936, attached as
Exhibit 99.3 to Edison International Form 8-K dated May 25, 2005)*
10.4 First Amendment, dated as of May 20, 2005, to Credit Agreement, dated as of February 1, 2005, among Edison
International and JPMorgan Chase Bank, N.A., as Administrative Agent, Citicorp North America, Inc., as
Syndication Agent, and Credit Suisse First Boston, Lehman Commercial Paper Inc., and Union Bank of California,
N.A., as Documentation Agents (File No. 1-9936, attached as Exhibit 10.1 to Edison International Form 8-K dated
June 8, 2005)*
10.5 Form of Indemnity Agreement between Edison International and its Directors and any officer, employee or other
agent designated by the Board of Directors
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 herein by reference pursuant to Rule 12b-32.
Page 89
SIGNATURE
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/ LINDA G. SULLIVAN
-----------------------------
LINDA G. SULLIVAN
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Dated: August 8, 2005