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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 999)
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
(626) 302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No |_|
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes |X|
No |_|
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class Outstanding at August 12, 2003
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Common Stock, no par value 325,811,206
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Page
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, 2003 and 2002 1
Consolidated Balance Sheets - June 30, 2003
and December 31, 2002 2
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2003 and 2002 4
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2003 and 2002 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk 76
Item 4. Controls and Procedures 76
Part II. Other Information:
Item 1. Legal Proceedings 77
Item 4. Submission of Matters to a Vote of Security Holders 78
Item 6. Exhibits and Reports on Form 8-K 79
Signatures
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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 2003 2002 2003 2002
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(Unaudited)
Electric utility $ 2,394 $ 2,133 $ 4,217 $ 4,041
Nonutility power generation 716 673 1,399 1,209
Financial services and other 23 18 48 63
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Total operating revenue 3,133 2,824 5,664 5,313
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Fuel 293 279 627 536
Purchased power 722 581 1,174 835
Provisions for regulatory adjustment clauses - net 506 (359) 811 314
Other operation and maintenance 830 823 1,614 1,538
Asset impairment 251 -- 251 --
Depreciation, decommissioning and amortization 252 261 541 503
Property and other taxes 51 36 102 75
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Total operating expenses 2,905 1,621 5,120 3,801
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Operating income 228 1,203 544 1,512
Interest and dividend income 47 62 93 178
Equity in income from partnerships and
unconsolidated subsidiaries - net 60 43 120 94
Other nonoperating income 19 7 53 23
Interest expense - net of amounts capitalized (289) (316) (589) (676)
Other nonoperating deductions (20) (23) (51) (33)
Dividends on preferred securities (26) (24) (51) (47)
Dividends on utility preferred stock (4) (6) (8) (11)
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Income from continuing operations before tax 15 946 111 1,040
Income tax (benefit) (11) 290 20 306
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Income from continuing operations 26 656 91 734
Income (loss) from discontinued operations - net of tax (2) 9 (2) 15
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Income before accounting change 24 665 89 749
Cumulative effect of accounting change - net of tax -- -- (9) --
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Net income $ 24 $ 665 $ 80 $ 749
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Weighted-average shares of common stock outstanding 326 326 326 326
Basic earnings per share:
Continuing operations $ 0.08 $ 2.01 $ 0.29 $ 2.25
Discontinued operations (0.01) 0.03 (0.01) 0.05
Cumulative effect of accounting change -- -- (0.03) --
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Total $ 0.07 $ 2.04 $ 0.25 $ 2.30
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Weighted-average shares, including
effect of dilutive securities 329 329 329 329
Diluted earnings per share:
Continuing operations $ 0.08 $ 1.99 $ 0.28 $ 2.23
Discontinued operations (0.01) 0.03 (0.01) 0.05
Cumulative effect of accounting change -- -- (0.03) --
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Total $ 0.07 $ 2.02 $ 0.24 $ 2.28
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Dividends declared per common share -- -- -- --
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 2003 2002
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(Unaudited)
ASSETS
Cash and equivalents $ 2,381 $ 2,468
Restricted cash 51 53
Receivables, less allowances of $39 and $49 for uncollectible
accounts at respective dates 1,223 1,111
Accrued unbilled revenue 594 437
Fuel inventory 111 124
Materials and supplies, at average cost 231 225
Accumulated deferred income taxes - net 238 270
Trading and price risk management assets 62 34
Regulatory assets - net -- 509
Prepayments and other current assets 240 227
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Total current assets 5,131 5,458
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Nonutility property - less accumulated provision for
depreciation of $1,126 and $924 at respective dates 7,209 6,923
Nuclear decommissioning trusts 2,348 2,210
Investments in partnerships and unconsolidated subsidiaries 2,119 2,011
Investments in leveraged leases 2,345 2,313
Other investments 290 235
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Total investments and other assets 14,311 13,692
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Utility plant, at original cost:
Transmission and distribution 14,539 14,202
Generation 1,461 1,457
Accumulated provision for depreciation and decommissioning (6,395) (8,094)
Construction work in progress 582 529
Nuclear fuel, at amortized cost 133 153
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Total utility plant 10,320 8,247
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Goodwill 776 661
Restricted cash 254 406
Regulatory assets - net 3,358 3,838
Other deferred charges 1,027 921
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Total deferred charges 5,415 5,826
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Assets of discontinued operations 15 61
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Total assets $ 35,192 $ 33,284
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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 2003 2002
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 298 $ 78
Long-term debt due within one year 1,502 2,761
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,056 866
Accrued taxes 884 855
Trading and price risk management liabilities 147 45
Regulatory liabilities - net 69 --
Other current liabilities 2,067 2,040
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Total current liabilities 6,032 6,654
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Long-term debt 12,358 11,557
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Accumulated deferred income taxes - net 5,760 5,842
Accumulated deferred investment tax credits 163 167
Customer advances and other deferred credits 1,434 1,841
Power-purchase contracts 242 309
Accumulated provision for pensions and benefits 483 461
Asset retirement obligations 2,107 --
Other long-term liabilities 171 161
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Total deferred credits and other liabilities 10,360 8,781
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Liabilities of discontinued operations 15 72
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Commitments and contingencies (Notes 2 and 3)
Minority interest 459 425
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Preferred stock of utility:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 141 147
Company-obligated mandatorily redeemable securities of subsidiaries
holding solely parent company debentures 951 951
Other preferred securities 147 131
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Total preferred securities of subsidiaries 1,368 1,358
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Common stock (325,811,206 shares outstanding at each date) 1,979 1,973
Accumulated other comprehensive loss (170) (247)
Retained earnings 2,791 2,711
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Total common shareholders' equity 4,600 4,437
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Total liabilities and shareholders' equity $ 35,192 $ 33,284
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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 2003 2002 2003 2002
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(Unaudited)
Net income $ 24 $ 665 $ 80 $ 749
Other comprehensive income, net of tax:
Foreign currency translation adjustments - net 42 63 63 79
Unrealized loss on investments - net (2) (7) (2) (7)
Cumulative effect of change in accounting
for derivatives -- 6 -- 6
Unrealized gain (loss) on cash flow hedges - net 25 (13) 22 28
Reclassification adjustment for gain (loss)
included in net income (5) 2 (6) 3
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Comprehensive income $ 84 $ 716 $ 157 $ 858
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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 2003 2002
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 82 $ 734
Adjustments to reconcile to net cash provided
(used) by operating activities:
Depreciation, decommissioning and amortization 541 503
Other amortization 54 53
Deferred income taxes and investment tax credits (85) (71)
Equity in income from partnerships and unconsolidated subsidiaries (120) (94)
Income from leveraged leases (42) (57)
Regulatory assets - long-term - net 147 220
Power contracts collateral (10) --
Asset impairment 251 --
Other assets (44) (9)
Other liabilities (155) 151
Changes in working capital:
Receivables and accrued unbilled revenue (225) (98)
Regulatory assets - short-term - net 579 25
Fuel inventory, materials and supplies (5) (2)
Prepayments and other current assets 6 (40)
Accrued interest and taxes 118 597
Accounts payable and other current liabilities 193 (2,454)
Distributions and dividends from unconsolidated entities 65 177
Operating cash flows from discontinued operations (17) 48
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Net cash provided (used) by operating activities 1,333 (317)
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Cash flows from financing activities:
Long-term debt issued 214 166
Long-term debt repaid (907) (1,022)
Bonds remarketed and funds held in trust -- 192
Redemption of preferred securities (5) (100)
Rate reduction notes repaid (115) (115)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net 303 (722)
Financing cash flows from discontinued operations -- (8)
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Net cash used by financing activities (510) (1,668)
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Cash flows from investing activities:
Additions to property and plant (619) (628)
Purchase of power sales agreement -- (80)
Purchase of common stock of acquired companies (275) --
Proceeds from sale of nonutility property -- 49
Net funding of nuclear decommissioning trusts (1) 7
Distributions from (investments in) partnerships and
unconsolidated subsidiaries (58) 90
Sales of investments in other assets 19 72
Investing cash flows from discontinued operations 5 1
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Net cash used by investing activities (929) (489)
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Effect of exchange rate changes on cash 19 19
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Net decrease in cash and equivalents (87) (2,455)
Cash and equivalents, beginning of period 2,468 4,055
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Cash and equivalents, end of period 2,381 1,600
Cash and equivalents - discontinued operations -- (33)
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Cash and equivalents, continuing operations $ 2,381 $ 1,567
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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, 2003
are not necessarily indicative of the operating results for the full year.
The quarterly report should be read in conjunction with Edison International's 2002 Annual Report on Form 10-K filed with the
Securities and Exchange Commission.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2002 Annual Report. Edison International follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the June 30, 2003 financial statement presentation.
New Accounting Principles
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or
liabilities as a result of timing differences between the recognition of costs in accordance with this standard and the recovery of
costs through the rate-making process. Regulatory assets and liabilities may also be recorded if it is probable that the asset
retirement obligation (ARO) will be recovered through the rate-making process.
Edison International's impact of adopting this standard was:
o Southern California Edison (SCE) adjusted its nuclear decommissioning obligation to reflect the fair value of
decommissioning its nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and $12 million to decommission
its share of a coal-fired generating plant, under accounting principles in effect at that time. Of these amounts, $298 million
to decommission its inactive nuclear facility was recorded in other long-term liabilities, and the remaining $2.0 billion was
recorded as a component of the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in
the 2002 Annual Report.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning, recorded the fair value of its
AROs of approximately $2.0 billion in the deferred credits and other liabilities section of the balance sheet, and increased its
unamortized nuclear investment by $303 million. The cumulative effect of a change in accounting principle from unrecognized
accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory liability, partially
offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and depreciation expense resulting from the
application of the new standard is expected to be approximately $143 million in 2003. This cost will reduce the regulatory
liability, with no impact on earnings. As of June 30, 2003, SCE's ARO for its nuclear facilities totaled approximately
$2.1 billion and its nuclear decommissioning trust assets had a fair value of $2.3 billion. If the new standard had been in
place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.97 billion collected through
rates for cost of removal of plant assets not considered to be legal obligations remain in accumulated depreciation and
decommissioning.
o As of January 1, 2003, Edison Mission Energy's (EME) ARO was $17 million and EME recorded a cumulative effect adjustment
that decreased net income by approximately $9 million, net of tax. If the new standard had been applied retroactively in the six
months ended June 30, 2002, it would not have had a material effect on EME's results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities (VIEs). The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. This interpretation applies to VIEs
created after January 31, 2003 and beginning July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it
acquired before February 1, 2003.
If an enterprise absorbs the majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns, or
both, it must consolidate the VIE. An enterprise that is required to consolidate the VIE is called the primary beneficiary.
Additional disclosure requirements are also applicable when an enterprise holds a significant variable interest in a VIE, but is not
the primary beneficiary. In addition, financial statements issued after January 31, 2003 must include certain disclosures if it is
reasonably possible that an enterprise will consolidate or disclose information about a VIE when this interpretation is effective.
Edison International has concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy Yard project
and Edison Capital's Storm Lake project, since it is at risk with respect to the majority of its losses and is entitled to receive
the majority of its residual returns. Accordingly, effective July 1, 2003, Edison International will consolidate these projects,
which will increase total assets by approximately $452 million and total liabilities by approximately $530 million. Edison
International expects to record a loss of approximately $78 million (of which $72 million is related to Brooklyn Navy Yard) in the
third quarter of 2003 as a cumulative accounting change as a result of consolidating these VIEs.
Edison International believes it is reasonably possible that certain partnership interests in energy projects are VIEs under this
interpretation, as discussed below:
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098 MW of power plants.
The maximum exposure to loss from EME's interest in these energy partnerships is $1.1 billion at June 30, 2003. Of this amount, $566
million represents EME's investment in the 1,230 MW Paiton project and $304 million represents EME's investment in the 540 MW
EcoElectrica project.
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another affiliated project
under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of
the obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to this
affiliated project. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot
be determined.
Edison International is in the process of reviewing the entities discussed above that have a reasonable possibility of being VIEs to
determine if it is the primary beneficiary.
A new accounting standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was
issued in May 2003 and requires issuers to classify certain freestanding financial instruments as liabilities. These freestanding
liabilities include mandatorily redeemable financial instruments, obligations to repurchase the issuer's equity shares by
transferring assets and certain obligations to issue a variable number of shares. The standard is effective for Edison International
on July 1, 2003. Upon implementation, Edison International will reclassify its company-obligated mandatorily redeemable securities,
its other mandatorily redeemable preferred securities and SCE's preferred stock subject to mandatory redemption to the liabilities
section of its consolidated balance sheets. These items are currently classified between liabilities and equity. In addition,
dividend payments on these instruments will be recorded as interest expense on Edison International's consolidated statements of
income. Edison International does not expect implementation of the new standard to have a material impact on its financial
statements.
In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Determining Whether an Arrangement Contains a Lease, which
provides guidance on how to determine whether an arrangement contains a lease that is within the scope of the standard, Accounting
for Leases. A lease is defined as an agreement conveying the right to use property, plant, or equipment (land and/or depreciable
assets) usually for a stated period of time. The guidance issued by the EITF could affect the classification of a power sales
agreement that meets specific criteria, such as a power sales agreement for substantially all of the output from a power plant to one
customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to the
lease accounting standard. The consensus is effective prospectively for arrangements entered into or modified after June 30, 2003.
In June 2003, clarifying guidance was issued related to derivative instruments and hedging activities. The guidance is related to
permitted pricing adjustments in a contract qualifying under the normal purchases and normal sales exception under derivative
instrument accounting. This implementation guidance becomes effective on October 1, 2003. EME is currently reevaluating which
contracts, if any, that have previously been designated as normal purchases or normal sales would now not qualify for this exception.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:
June 30, December 31,
In millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
PROACT - net $ 84 $ 574
Rate reduction notes - transition cost deferral 1,104 1,215
Unamortized nuclear investment - net 617 630
Unamortized coal plant investment - net 66 61
Other:
Flow-through taxes - net 1,303 1,336
Unamortized loss on reacquired debt 233 237
Environmental remediation 72 70
Asset retirement obligation (313) --
Regulatory balancing accounts and other - net 123 224
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Total $ 3,289 $ 4,347
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Stock-Based Employee Compensation
Edison International has three stock-based employee compensation plans, which are described more fully in Note 7 of "Notes to
Consolidated Financial Statements" included in its 2002 Annual Report. Edison International accounts for these plans using the
intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income, as all options granted
under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following
table illustrates the effect on net income and earnings per share if Edison International had used the fair-value accounting method.
Three Months Ended Six Months Ended
June 30, June 30,
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In millions, except per-share amounts 2003 2002 2003 2002
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Net income, as reported $ 24 $ 665 $ 80 $ 749
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 2 2 4 4
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 2 1 5 2
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Pro forma net income $ 24 $ 666 $ 79 $ 751
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Basic earnings per share:
As reported $ 0.07 $ 2.04 $ 0.25 $ 2.30
Pro forma $ 0.07 $ 2.04 $ 0.24 $ 2.30
Diluted earnings per share:
As reported $ 0.07 $ 2.02 $ 0.24 $ 2.28
Pro forma $ 0.07 $ 2.02 $ 0.24 $ 2.28
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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 2003 2002
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Non-cash investing and financing activities:
Details of assets acquired:
Fair value of assets acquired $ (333) $ --
Liabilities assumed 58 --
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Cash paid for acquisitions $ (275) $ --
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Details of senior secured credit facility transaction:
Retirement of credit facility $ -- $ (1,650)
Senior secured credit facility replacement -- 1,600
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Cash paid on retirement of credit facility $ -- $ (50)
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Details of long-term debt exchange offer:
Variable rate notes redeemed $ (966) $ --
First and refunding bonds issued 966 --
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Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources (CDWR) power purchases
and revenue requirements, generation procurement and utility-retained generation, is described in Note 2 of "Notes to Consolidated
Financial Statements" included in Edison International's 2002 Annual Report.
California Public Utilities Commission (CPUC) Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that SCE is entitled to
full recovery of its past procurement-related costs. A key element of the settlement agreement was the establishment of a $3.6
billion regulatory balancing account called the procurement-related obligations account (PROACT) as of August 31, 2001. The Utility
Reform Network (TURN), a consumer advocacy group, and other parties appealed to the federal court of appeals seeking to overturn the
stipulated judgment of the district court that approved the settlement agreement. On March 4, 2002, the court of appeals heard
argument on the appeal, and on September 23, 2002 the court issued its opinion. In the opinion, the court affirmed the district
court on all claims, with the exception of the challenges founded upon California state law, which the appeals court referred to the
California Supreme Court. In sum, the appeals court concluded that none of the substantive arguments based on federal statutory or
constitutional law compelled reversal of the district court's approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement agreement violated state
law, both in substance and in the procedure by which the CPUC agreed to it. The appeals court added that if the settlement agreement
violated state law, the CPUC lacked capacity to consent to the stipulated judgment, and the stipulated judgment would need to be
vacated. The appeals court indicated that, on a substantive level, the stipulated judgment appears to violate California's electric
industry restructuring statute providing for a rate freeze. The appeals court also indicated that,
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
on a procedural level, the stipulated judgment appears to violate California laws requiring open meetings and public hearings.
Because federal courts are bound by the pronouncements of the state's highest court on applicable state law, and because the federal
appeals court found no controlling precedents from California courts on the issues of state law in this case, the appeals court
issued a separate order certifying those issues in question form to the California Supreme Court and requested that the California
Supreme Court accept certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had requested, and set a
briefing schedule. After the completion of the filing of briefs by the respective parties, including supplemental briefs at the
request of the California Supreme Court about an issue related to California's open meeting laws, the parties made oral arguments
before the California Supreme Court at a hearing on May 27, 2003. SCE expects the California Supreme Court to issue its decision on
the certified questions by August 25, 2003. Once the California Supreme Court rules, the matter will return to the federal court of
appeals for final disposition. In the meantime, the case is stayed in the federal appellate court. SCE continues to operate under
the settlement agreement, and also continues to believe it is probable that SCE's ultimate recovery of its past procurement costs
through regulatory mechanisms, including the PROACT, will be validated. However, SCE cannot predict with certainty the outcome of
the pending legal proceedings.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground electric line
maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection and Safety Division (CPSD), which
alleged a pattern of noncompliance with the CPUC's general orders for the maintenance of electric lines over the period 1998-2000.
The order also alleged that noncompliant conditions were involved in 37 accidents resulting in death, serious injury or property
damage. The CPSD identified 4,817 alleged violations of the general orders during the three-year period; and the order put SCE on
notice that it could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief on
October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC administrative law judge issued a presiding officer's decision (POD) fining SCE $576,000 for alleged
violations involving death, injury or property damage, failure to identify unsafe conditions or exceeding required inspection
intervals. The POD imposes no fines for over 98% of the alleged violations and does not find that any of the alleged violations
compromised the integrity or safety of SCE's electric system or were excessive compared to other utilities. The POD orders SCE to
consult with the CPSD and refine SCE's maintenance priority system consistent with the discussion in the POD. On July 21, 2003, SCE
filed an appeal opposing the POD's interpretation that all general order non-conformances are violations subject to potential
penalty. The CPSD also filed an appeal, challenging the fact that the POD did not, in fact, penalize SCE for the 4,721 violations
alleged by the CPSD in the OII. SCE, Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E) and the California Cable and
Telecommunications Association filed responses challenging the CPSD's appeal. The CPSD filed a response objecting to the
intervention and appeals of PG&E, SDG&E and the California Cable and Telecommunications Association.
Holding Company Proceeding
In April 2001, the CPUC issued an OII that reopens the past CPUC decisions authorizing utilities to form holding companies and
initiates an investigation into, among other things: whether the holding
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
companies violated CPUC requirements to give first priority to the capital needs of their respective utility subsidiaries; any
additional suspected violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other changes to
the holding company decisions are necessary. On January 9, 2002, the CPUC issued an interim decision on the first priority
condition. The decision stated that, at least under certain circumstances, the condition includes the requirement that holding
companies infuse all types of capital into their respective utility subsidiaries when necessary to fulfill the utility's obligation
to serve. The decision did not determine if any of the utility holding companies had violated this condition, reserving such a
determination for a later phase of the proceedings. On February 11, 2002, SCE and Edison International filed an application before
the CPUC for rehearing of the decision. On July 17, 2002, the CPUC affirmed its earlier decision on the first priority condition and
also denied Edison International's request for a rehearing of the CPUC's determination that it had jurisdiction over Edison
International in this proceeding. On August 21, 2002, Edison International and SCE jointly filed a petition requesting a review of
the CPUC's decisions with regard to first priority considerations, and Edison International filed a petition for a review of the CPUC
decision asserting jurisdiction over holding companies, both in state court as required. PG&E and SDG&E and their respective holding
companies filed similar challenges, and all cases have been transferred to the First District Court of Appeals in San Francisco. The
CPUC filed briefs in opposition to the writ petitions. Edison International, SCE and the other petitioners filed reply briefs on
March 6, 2003. No hearings have been scheduled. The court may rule without holding hearings. Edison International cannot predict
with certainty what effects this investigation or any subsequent actions by the CPUC may have on Edison International or any of its
subsidiaries.
Mohave Generating Station Proceeding
As discussed in Note 2 of "Notes to Consolidated Financial Statements" included in Edison International's 2002 Annual Report, on May
17, 2002, SCE filed with the CPUC an application to address certain issues (mainly coal and slurry-water supply issues) facing the
future extended operation of Mohave. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave
co-owners from starting to make approximately $1.1 billion (SCE's share is $605 million) of Mohave-related investments if Mohave's
operations are to be extended past 2005. The CPUC issued a ruling on January 7, 2003 requesting further written testimony on
specified issues related to Mohave and its coal and slurry-water supply issues to determine whether it is in the public interest to
extend Mohave operations post 2005. SCE submitted supplemental testimony on January 30, 2003 stating, among other things, that the
currently available information is not sufficient for the CPUC to make such a determination at this time.
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in the proceeding,
most recently on July 1, 2003. The Navajo Nation and Hopi Tribe and the coal mining company, Peabody Western Coal Company, currently
take the position that the CPUC should, among other things, require SCE to fund a study of a possible alternative water supply, and
require SCE to commence a CPUC proceeding for authorization of the Mohave pollution controls and other plant investments. Certain
other parties have taken the position that SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. To date there
has been no substantive decision by the CPUC, and it is possible that further written filings or hearings will be required.
Negotiations also have continued among the relevant parties in an effort to resolve the coal and water supply issues, so far without
any resolution.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Wholesale Electricity and Gas Markets
In response to a consolidated proceeding related to the justness and reasonableness of rates charged by sellers in the California
Power Exchange and Independent System Operator markets as described in Note 2 of "Notes to Consolidated Financial Statements"
included in Edison International's 2002 Annual Report, the FERC issued orders that initiated procedures for determining additional
refunds arising from market manipulation by energy suppliers. A FERC staff report issued on March 26, 2003 found that there was
pervasive gaming and market manipulation of the electric and gas markets in California and in the west coast and also described many
of the techniques and effects of electric and gas market manipulation. In a March 26, 2003 order, clarified on April 22, 2003, the
FERC adopted a recommendation of the FERC staff's final report to modify the ALJ's initial decision of December 12, 2002 to reflect
the fact that the gas indices used in the market manipulation formula overstated the cost of gas used to generate electricity. SCE,
as a member of the California parties, sought rehearing of the March 26 and April 22 orders. On June 25, 2003, the FERC issued two
sets of enforcement orders. The first set orders 54 entities, including SCE, to show cause concerning gaming or anomalous market
behavior during the period January 1, 2001 to June 20, 2001. The second set orders 25 entities to show cause concerning gaming and
anomalous market behavior in concert with Enron entities. Under both sets of orders, the remedy for tariff violations will be the
disgorgement of unjust profits and possibly other non-monetary remedies. On June 25, 2003, the FERC also opened a new investigation
into anomalous bidding behavior during the period May 1, 2000 to October 2, 2000, focused primarily on economic withholding by
bidding above $250/MWh with disgorgement of profits as the possible penalty. SCE cannot, at this time, determine the timing or
amount of any potential refunds. Under the settlement agreement with the CPUC, 90% of any refunds will be given to ratepayers and
10% would be given to shareholders. The CPUC issued an order instituting rulemaking on July 10, 2003, to account for the
consideration received by regulated gas and electric utilities under a settlement with El Paso Natural Gas Company, et al. Under the
terms of the rulemaking, SCE will refund amounts (net of legal and consulting costs) through its energy resource recovery account as
they are received from El Paso under the terms of the settlement. In addition, amounts El Paso refunds to the CDWR will result in
equivalent reductions in the CDWR's revenue requirement from SCE's ratepayers.
Note 3. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings
before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International
believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has leased three aircraft to American Airlines. American Airlines is reporting significant operating losses. If
American Airlines defaults in making its lease payments, the lenders with a security interest in the aircraft or leases may exercise
remedies that could lead to a loss of some or all of Edison Capital's investment in the aircraft plus any accrued interest. The
total maximum loss exposure to Edison Capital is $48 million. A voluntary restructure of the leases could also result in a loss of
some or all of the investment. At June 30, 2003, American Airlines was current in its lease payments to Edison Capital.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 42 identified sites at SCE (39 sites) and EME (3 sites)
is $103 million, $101 million of which is related to SCE. The sites include SCE's divested gas-fueled generation plants, for which
SCE retained some liability after their sale. 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
$280 million, $277 million of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least
favorable to Edison International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $40 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 $72 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable
estimate of cleanup costs can be made for these sites.
Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next
several years are expected to range from $15 million to $30 million. Recorded costs for the twelve months ended June 30, 2003 were
$19 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental
remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
In August 2002, Edison International received a notice from the Internal Revenue Service (IRS) asserting deficiencies in federal
corporate income taxes for its 1994 to 1996 tax years. The vast majority of the tax deficiencies are timing differences and,
therefore, amounts ultimately paid, if any, would benefit Edison International as future tax deductions. Edison International
believes that it has meritorious legal defenses to those deficiencies and believes that the ultimate outcome of this matter will not
result in a material impact on Edison International's consolidated results of operations or financial position.
Among the issues raised by the IRS in the 1994 to 1996 audit was Edison Capital's treatment of the EPZ and Dutch electric locomotive
leases. Written protests were filed against these deficiency notices, as well as other alleged deficiencies, asserting that the
IRS's position misstates material facts, misapplies the law and is incorrect. Edison Capital will contest the assessment through
administrative appeals and litigation, if necessary. Edison Capital believes it will ultimately prevail.
The IRS is also currently examining the tax returns for Edison International, which includes Edison Capital, for years 1997 through
1999. Edison Capital expects the IRS to also challenge several of its other leveraged leases based on a recent Revenue Ruling
addressing a specific type of leveraged lease (termed a lease in/lease out or LILO transaction). Edison Capital believes that the
position described in the Revenue Ruling is incorrectly applied to Edison Capital's transactions and that its leveraged leases are
factually and legally distinguishable in material respects from that position. Edison Capital intends to defend, and litigate if
necessary, against any challenges based on that position.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to Mohave. In June 1999, the Navajo Nation filed a
complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody and certain of its
affiliates, Salt River Project Agricultural Improvement and Power District, and SCE. The complaint asserts claims against the
defendants for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual
relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The complaint seeks
damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion, as well as a
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated.
In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation had breached a
settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.
The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of Interior, alleging that
the Government had breached its fiduciary duty concerning contract negotiations including the Navajo Nation and the defendants. In
February 2000, the Court of Claims issued a decision in the Government's favor, finding that while there had been a breach, there was
no available redress from the Government. Following appeal of that decision by the Navajo Nation, an appellate court ruled that the
Court of Claims did have jurisdiction to award damages and remanded the case to the Court of Claims for that purpose. On June 3,
2002, the Government's request for review of the case by the United States Supreme Court was granted. On March 4, 2003, the Supreme
Court reversed the appellate court and held that the Government is not liable to the Navajo Nation as there was no breach of a
fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court's
analysis, on April 28, 2003, SCE filed a motion to dismiss or, in the alternative, for summary judgment in the D.C. District Court
action. The motion remains pending.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact on this complaint or
the Supreme Court's decision on the outcome of the Navajo Nation's suit against the government, or the impact of the complaint on the
operation of Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion ($10.9 billion as of August 20, 2003). SCE and
other owners of the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance
available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to
every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the
primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for
each nuclear incident is $88 million ($101 million as of August 20, 2003) 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
$175 million ($199 million as of August 20, 2003) per nuclear incident. However, it would have to pay no more than $20 million per
incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and
are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further
revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. The U.S.
Congress has extended the expiration date of the applicable law until December 31, 2003 and is considering amendments that, among
other things, are expected to extend the law beyond 2003.
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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the
arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium
adjustments of up to $38 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and development of a facility for disposal of
spent nuclear fuel and high-level radioactive waste. Such a facility was to be in operation by January 1998. However, the DOE did
not meet its obligation. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or from other
nuclear power plants. Extended delays by the DOE could lead to consideration of costly alternatives involving siting and
environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through
April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1(cent)per kWh of
nuclear-generated electricity sold after April 6, 1983.
SCE, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. The spent
nuclear fuel is stored in the San Onofre Units 1, 2 and 3 spent fuel pools. The Units 2 and 3 spent fuel pools currently contain
Unit 1 spent fuel in addition to spent fuel from Units 2 and 3. Current capability to store spent fuel in the Units 2 and 3 spent
fuel pools is adequate through 2005. SCE plans to begin moving the Unit 1 spent fuel to a dry cask interim spent fuel storage
facility at San Onofre by the third quarter of 2003. By late 2004, the spent fuel pool storage capacity for Units 2 and 3 will then
accommodate needs until 2007 for Unit 2 and 2008 for Unit 3. SCE expects to begin using an interim spent fuel storage facility for
Units 2 and 3 spent fuel by early 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage
facility. Arizona Public Service Company (APS), operating agent for Palo Verde, has loaded five casks for Unit 2 and one for Unit 1.
APS plans to continually load casks on a schedule to maintain full core off-load capability for all three units.
Storm Lake
As of June 30, 2003, Edison Capital had an investment of approximately $77 million in Storm Lake Power, a project developed by Enron
Wind, a subsidiary of Enron Corporation. As of June 30, 2003, Storm Lake had outstanding loans of approximately $65 million;
however, a loan payment was made on August 1, 2003, reducing the outstanding loans to approximately $60 million. Enron and its
subsidiary provided certain guarantees related to the amount of power that would be generated from Storm Lake. The lenders have sent
a notice to Storm Lake claiming that Enron's bankruptcy, among other things, is an event of default under the loan agreement. In the
event of default, the lenders may exercise certain remedies, including acceleration of the loan balance, repossession and foreclosure
of the project, which could result in the loss of some or all of Edison Capital's investment in Storm Lake. While expressly
reserving their rights, the lenders have not taken any steps to exercise their remedies beyond issuing the notices of default. On
behalf of Storm Lake, Edison Capital is also engaged in regular, ongoing discussions with the lenders in which Edison Capital expects
to demonstrate to the lenders that Storm Lake's ability to meet its loan obligations is not impaired and that the noticed events of
default can be worked out with the lenders. Edison Capital believes that Storm Lake will oppose any attempt by the lenders to
exercise remedies that could result in a loss of Edison Capital's investment.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison Capital has concluded that it is the primary beneficiary in this project, since it is at risk with respect to the majority of
its losses and is entitled to receive the majority of its residual returns. Accordingly, effective July 1, 2003, Edison Capital will
consolidate this project, which will increase total assets by approximately $90 million and total liabilities by approximately $96
million. Edison Capital expects to record a loss of approximately $6 million as a cumulative accounting change as a result of
consolidating this project (see "New Accounting Principles" in Note 1).
Note 4. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), a nonutility power
generation segment (EME), and a financial services provider segment (Edison Capital).
Segment information for the three and six months ended June 30, 2003 and 2002 was:
Three Months Ended Six Months Ended
June 30, June 30,
- -----------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenue:
Electric utility $ 2,394 $ 2,133 $ 4,217 $ 4,041
Nonutility power generation 716 673 1,399 1,209
Financial services 22 14 44 45
Corporate and other 1 4 4 18
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 3,133 $ 2,824 $ 5,564 $ 5,313
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 225 $ 695 $ 327 $ 841
Nonutility power generation(2) (167) 3 (184) (33)
Financial services 12 12 27 31
Corporate and other (46) (45) (90) (90)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 24 $ 665 $ 80 $ 749
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock.
(2) Includes a loss of $9 million from the cumulative effect of an accounting change for the six months ended June 30, 2003.
Also, includes losses from discontinued operations of $2 million for both the three and six months ended June 30, 2003 and
earnings from discontinued operations of $9 million and $15 million, respectively, for the three and six months ended June
30, 2002.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment. The net loss of
$46 million and $90 million, respectively, reported for the three and six months ended June 30, 2003 also includes Mission Energy
Holding Company's net loss of $24 million and $49 million, respectively, for the same periods. The net loss of $45 million and $90
million, respectively, reported for the three and six months ended June 30, 2002 also includes Mission Energy Holding Company's net
loss of $24 million and $46 million, respectively, for the same periods.
Total segment assets as of June 30, 2003 were: electric utility, $20 billion; nonutility power generation, $12 billion; and,
financial services, $4 billion.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Acquisitions and Disposition
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen, to acquire
Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands, California. This acquisition
requires regulatory approval from both the CPUC and the Federal Energy Regulatory Commission (FERC). SCE has filed an application
with the CPUC proposing a power-purchase agreement between SCE and Mountainview Power Company LLC. If approved by the CPUC, SCE will
seek FERC approval of the power-purchase agreement. SCE does not expect to exercise the option without CPUC and FERC approvals. The
option must be exercised prior to February 29, 2004. If SCE exercises the option, SCE would recommence full construction of the
project. Under the option agreement, Sequoia may elect to terminate the option agreement at any time prior to SCE's exercise of the
option. In such event, Sequoia must return all previously tendered option payments.
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki
combined cycle power station and related interests. Consideration for the Taranaki station consisted of a cash payment of
approximately $275 million, which was initially financed with bridge loan facilities. The bridge loan facilities were subsequently
repaid with proceeds from the issuance of long-term U.S. dollar denominated notes. The Taranaki station is a 357 MW combined cycle,
natural gas-fired plant located near Stratford, New Zealand.
In July 2003, EME agreed to sell its 50% interest in the Gordonsville project to a third party. Completion of the sale, currently
expected during the fourth quarter of 2003, is subject to closing conditions, including obtaining regulatory approval. Net proceeds
from the sale, including distribution of a debt service reserve fund, are expected to be approximately $32 million. EME recorded an
impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this investment.
During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects
and its 30% interest in the Harbor project. Proceeds received from the sales were $44 million. During 2001, EME recorded asset
impairment charges of $32 million related to these projects based on the expected sales proceeds. No gain or loss was recorded from
the sale of EME's interests in these projects during the first quarter of 2002.
Note 6. Asset Impairment
During second quarter 2003, EME recorded an asset impairment charge resulting from a revised long-term outlook for capacity revenue
from its small peaking plants in Illinois due to a number of factors, including the effect of higher long-term natural gas prices on
the competitiveness of these units and the current oversupply of generation. Since capacity value represents a key revenue component
for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets from $286 million to
their estimated fair market value of $41 million. The estimated fair value was determined based on discounting estimated future cash
flows using a 17.5% discount rate. In addition, EME recorded an asset impairment charge associated with the planned disposition of
its investment in the Gordonsville project (see Note 5). These amounts are included in the asset impairment line item of the June
30, 2003 consolidated statements of income.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7. Discontinued Operations
The results of the Lakeland project, the Fiddler's Ferry and Ferrybridge coal stations and Edison Enterprises subsidiaries sold
during 2001 have been reflected as discontinued operations in the consolidated financial statements in accordance with an accounting
standard related to the impairment and disposal of long-lived assets. The consolidated financial statements have been restated to
conform to the discontinued operations presentation for both periods presented. For the three and six months ended June 30, 2002,
revenue from discontinued operations was $17 million and $38 million, respectively, and pre-tax income was $9 million and $14
million, respectively. For both the three and six months ended June 30, 2003, pre-tax loss was $1 million.
Page 20
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three- and six-month
periods ended June 30, 2003, discusses material changes in the results of operations, financial condition and other developments of
Edison International since December 31, 2002, and as compared to the three- and six-month periods ended June 30, 2002. This
discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2002 (the year-ended
2002 MD&A), which was included in Edison International's 2002 annual report to shareholders and incorporated by reference into Edison
International's Annual Report on Form 10-K for the year ended December 31, 2002.
This MD&A contains forward-looking statements. These statements are based on Edison International's knowledge of present facts,
current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of
performance; they are subject to risks, uncertainties and assumptions that could cause actual future activities and results of
operations to be materially different from those set forth in this MD&A. Important factors that could cause actual results to differ
include, but are not limited to, risks discussed below under "Financial Condition," "Market Risk Exposures" and "Forward-Looking
Information and Risk Factors." The following discussion provides updated information about material developments since the issuance
of the year-ended 2002 MD&A and should be read in conjunction with the financial statements contained in this quarterly report and
Edison International's Annual Report on Form 10-K for the year ended December 31, 2002.
This MD&A includes information about Edison International and its principal subsidiaries, Southern California Edison Company (SCE),
Edison Mission Energy (EME), Edison Capital and Mission Energy Holding Company (MEHC). Edison International is a holding company.
SCE is a regulated public utility company providing electricity to retail customers in central, coastal, and southern California.
EME is an independent power producer engaged in owning or leasing and operating electric power generation facilities worldwide and in
energy trading and price risk management activities. Edison Capital is a global provider of capital and financial services in
energy, affordable housing, and infrastructure projects focusing primarily on investments related to the production and delivery of
electricity. MEHC was formed in June 2001, as a holding company for EME. In this MD&A, except when stated to the contrary,
references to each of Edison International, SCE, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a
consolidated basis. References to Edison International (parent) or parent company mean Edison International on a stand-alone basis,
not consolidated with its subsidiaries. References to SCE, MEHC, EME or Edison Capital followed by (stand alone) mean each such
company alone, not consolidated with its subsidiaries.
CURRENT DEVELOPMENTS
SCE Developments
As discussed in detail in "SCE's Regulatory Matters--CPUC Litigation Settlement Agreement," SCE entered into a settlement agreement
with the California Public Utilities Commission (CPUC) that allowed SCE to recover $3.6 billion in past procurement-related costs.
The Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the federal court of appeals seeking to
overturn the district court judgment that approved the settlement agreement. In September 2002, an appeals court opinion affirmed
the district court on all claims, with the exception of challenges founded upon California state law, which the appeals court
referred to the California Supreme Court. On May 27, 2003, the parties made oral arguments before the California Supreme Court. SCE
expects the California Supreme Court to issue its decision on the certified questions of state law by August 25, 2003.
Page 21
As discussed in "SCE's Regulatory Matters--PROACT Regulatory Asset and--Customer Rate-Reduction Plan," SCE fully recovered the
procurement-related obligations account (PROACT) balance during July 2003. As a result of recovering the PROACT balance, SCE
implemented a CPUC-approved customer rate-reduction plan effective August 1, 2003. The customer rate-reduction plan reduces SCE's
annual rates by $1.2 billion (with no impact to earnings) and will reduce bills by 8% for residential customers, 18% for small
businesses, 13% for medium businesses and 19% for large businesses.
MEHC and EME Developments
A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of
major integrated energy companies that sell a sizable portion of their generation into the wholesale energy market (sometimes
referred to as merchant generators), including several of EME's subsidiaries. These developments included lower prices and greater
volatility in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of
most major market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the
energy markets due to growing concern about the ability of counterparties to perform their obligations. Since the beginning of 2003,
several merchant generators reached agreements to extend existing bank credit facilities and at least three merchant generators have
filed for Chapter 11 protection under the United States Bankruptcy Code.
EME's largest subsidiary, Edison Mission Midwest Holdings, has $911 million of debt maturing on December 11, 2003, which will need to
be repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million
debt due on December 11, 2003. EME has $275 million of debt maturing on September 16, 2003, which will also need to be repaid,
extended or refinanced. During the second quarter, EME and Edison Mission Midwest Holdings commenced discussions with their lenders
regarding restructuring their respective indebtedness. There is no assurance that either EME or Edison Mission Midwest Holdings will
be able to extend or refinance their respective debt obligations on similar terms and rates as the existing debt, on commercially
reasonable terms, on the terms permitted under the financing documents entered into in July 2001 by MEHC, or at all. A failure to
repay, extend, or refinance the Edison Mission Midwest Holdings or EME obligations is likely to result in, or in the case of EME
would result in, a default under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME,
or both, to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. The independent accountants'
audit opinions on the year-end 2002 financial statements of MEHC, EME and Midwest Generation contain an explanatory paragraph that
indicates the consolidated financial statements have been prepared on the basis that these companies will continue as going concerns
and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend, or refinance this obligation raises
substantial doubt about their ability to continue as going concerns. Accordingly, the consolidated financial statements do not
include any adjustments that might result from the resolution of this uncertainty.
The lenders under MEHC's $385 million term loan due in 2006 have the right to require MEHC to repurchase up to $100 million of
principal amount at par on July 2, 2004 (referred to as the Term Loan Put-Option). In order for MEHC to have sufficient cash in the
event of an exercise of a significant portion, or all, of the Term Loan Put-Option, MEHC would require additional cash from dividends
from EME, or would need to either extend the effective date of the Term Loan Put-Option or extend or refinance the term loan. The
timing and amount of dividends from EME and its subsidiaries may be affected by many factors beyond MEHC's control. Dividends from
EME are currently limited as described in "Financial Condition--MEHC's Liquidity Issues and--EME's Liquidity Issues--Ability of EME to
Pay Dividends."
Page 22
Edison International, MEHC and EME are exploring alternatives to address the substantial amount of consolidated debt and near-term
debt maturities of MEHC and its subsidiaries, including restructuring of their existing indebtedness, bankruptcy, asset sales or a
sale of MEHC. Edison International's investment in MEHC, through a wholly owned subsidiary, as of June 30, 2003, was $723 million.
MEHC's investment in EME, as of June 30, 2003, was $1.7 billion. Edison International does not intend to make an additional capital
investment in MEHC or its subsidiaries, unless it concludes that such investment would be in the best interest of Edison
International's shareholders.
RESULTS OF OPERATIONS
Edison International recorded earnings of $24 million, or $0.07 per share, for the three-month period ended June 30, 2003, compared
to $665 million, or $2.04 per share, for the three-month period ended June 30, 2002, and earnings of $80 million, or $0.25 per share,
for the six-month period ended June 30, 2003, compared to $749 million, or $2.30, per share for the six-month period ended June 30,
2002. Edison International's 2003 results include a charge of $150 million, after tax, or $0.46 per share, by EME for the impairment
of eight small peaking plants in Illinois.
Edison International's 2002 results include a $480 million or $1.47 per share, after tax, gain from the implementation of a
regulatory decision for SCE's utility retained generation (URG). Edison International's core earnings include the impairment charge
at EME, and exclude the impact of the URG decision at SCE in 2002 and discontinued operations. The table below presents Edison
International's earnings per share and net income for the three- and six-month periods ended June 30, 2003 and 2002, and the relative
contributions by its subsidiaries.
In millions, except per-share amounts Earnings (Loss) Per Share Earnings (Loss)
- ---------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings (Loss):
SCE $ 0.69 $ 0.66 $ 225 $ 215
EME (0.50) (0.02) (165) (6)
Edison Capital 0.04 0.04 12 12
Mission Energy Holding Company (stand alone) (0.08) (0.07) (24) (24)
Edison International (parent) and other (0.07) (0.07) (22) (21)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Core Earnings 0.08 0.54 26 176
SCE Implementation of URG decision -- 1.47 -- 480
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 0.08 2.01 26 656
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Earnings (Loss)
from Discontinued Operations (0.01) 0.03 (2) 9
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings $ 0.07 $ 2.04 $ 24 $ 665
- ---------------------------------------------------------------------------------------------------------------------------------------
Page 23
In millions, except per-share amounts Earnings (Loss) Per Share Earnings (Loss)
- ---------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
Core Earnings (Loss):
SCE $ 1.00 $ 1.11 $ 327 $ 361
EME (0.52) (0.15) (173) (47)
Edison Capital 0.08 0.09 27 31
Mission Energy Holding Company (stand alone) (0.15) (0.14) (49) (46)
Edison International (parent) and other (0.12) (0.13) (41) (44)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Core Earnings 0.29 0.78 91 255
SCE Implementation of URG decision -- 1.47 -- 480
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 0.29 2.25 91 735(1)
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Earnings (Loss)
from Discontinued Operations (0.01) 0.05 (2) 14(1)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (0.03) -- (9) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings $ 0.25 $ 2.30 $ 80 $ 749
- ---------------------------------------------------------------------------------------------------------------------------------------
(1) Amounts are different from those reported on the consolidated income statement due to rounding.
Earnings (Loss) from Continuing Operations
Edison International's second quarter 2003 earnings from continuing operations were $26 million, compared with $656 million in the
comparable period in 2002; year-to-date 2003 earnings from continuing operations were $91 million, compared with $734 million in the
same period in 2002.
SCE earnings from continuing operations for the three- and six-month periods ended June 30, 2003 were $225 million and $327 million,
respectively, compared with $695 million and $841 million for the same periods in 2002. Excluding the $480 million adjustment
related to the URG decision in 2002, SCE's second quarter and year-to-date 2002 earnings were $215 million and $361 million,
respectively. Excluding the URG adjustment, earnings from continuing operations for second quarter 2003 increased $10 million over
second quarter 2002, primarily due to the impact of two items that occurred in second quarter 2002 that did not occur in second
quarter 2003: a refueling outage at San Onofre Nuclear Generating Station (San Onofre) Unit 2 and a one-time positive adjustment
related to the implementation of a sales adjustment mechanism. Excluding the $480 million gain to implement the URG decision, SCE's
earnings from continuing operations in the first half of 2003 decreased by $34 million, compared to the same period in 2002. The
decrease primarily reflects the impact of a one-time positive adjustment relating to the implementation of a sales adjustment
mechanism that occurred in the second quarter of 2002. Additionally, SCE had higher operating and maintenance expenses, including
health care and storm damage costs, which were offset by higher revenue.
EME's loss from continuing operations was $165 million and $173 million, respectively, for the three- and six-month periods ended
June 30, 2003, compared with losses of $6 million and $47 million, respectively, for the same periods in 2002. The decreases in
earnings were primarily due to the asset impairment charge of $150 million, a reduction in revenue from the Illinois power plants
which reflects the release of certain power and capacity in 2003 under the power purchase agreements, higher interest and rent
expense from the decline in EME's and its subsidiaries' credit ratings, and lower ancillary revenue at the First Hydro project. The
decrease in earnings was partially offset by higher U.S. energy prices, higher earnings from oil and gas activities and lower state
income taxes. On an annual basis, EME's earnings are seasonal with higher earnings expected during the summer months.
The impairment charge at EME during the second quarter of 2003 resulted from a revised long-term outlook for capacity revenue from
its small peaking plants in Illinois due to a number of factors, including the effect of higher long-term natural gas prices on the
competitiveness of these units and the
Page 24
current oversupply of generation. Since capacity value represents a key revenue component for these small peaking plants, the
revised outlook resulted in a write-down of the book value of these assets from $286 million to their estimated fair market value of
$41 million. The small peaking power plants range in size from 64 megawatts (MW) to 163 MW, and total 899 MW.
In addition to the impairment charge related to the small peaking plants, EME's indirect subsidiary, Midwest Generation, will report
in its second quarter 2003 separate financial statements an impairment charge of $475 million, after tax, related to the long-term
lease of the 2,698-MW gas-fired Collins Station. The impairment charge results from a write-down of the book value of capitalized
assets related to the Collins Station from $858 million to their estimated fair market value of $78 million. The impairment charge
by Midwest Generation is not reflected in the operating results of EME, MEHC or Edison International as the Collins Station is
treated in their financial statements as an operating lease and not as an asset, and therefore is not subject to impairment for
accounting purposes.
Edison Capital's earnings for the three and six months ended June 30, 2003 were $12 million and $27 million, respectively, compared
with $12 million and $31 million, respectively, in the comparable periods in 2002. The year-to-date 2003 decline of $4 million from
the comparable period in 2002 is primarily due to a maturing investment portfolio which produces lower income, partially offset by
lower net interest expense and higher tax benefits.
Earnings for the three- and six-month periods ended June 30, 2003, for MEHC (stand alone) and Edison International (parent) and other
were substantially unchanged from the results for the same periods in 2002.
Operating Revenue
SCE's retail sales represented approximately 91% of electric utility revenue for both the second quarter and year-to-date ended June
30, 2003, and 96% of electric utility revenue for the same periods in 2002. Retail rates are regulated by the CPUC and wholesale
rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warmer weather and higher electricity usage during the summer months, electric utility revenue during the third quarter of
each year is significantly higher than other quarters.
Electric utility revenue increased for the three- and six-month periods ended June 30, 2003, compared to the same periods in 2002,
primarily due to increased revenue from wholesale and retail customers. Wholesale revenue increased due to the resale of SCE's
excess energy, compared to no excess energy sales in 2002. As a result of the California Department of Water Resources (CDWR)
contracts allocated to SCE, excess energy from SCE sources may exist at certain times and is resold in the energy markets. Retail
sales revenue increased mainly due to recognition of revenue from amortization of the temporary surcharge that was collected in 2002
and authorized by the CPUC to be used to recover costs incurred in 2003 (see "SCE's Regulatory Matters--Surcharge Decisions" in the
year-ended 2002 MD&A for further discussion) and higher revenue resulting from a net 1(cent)per kilowatt hour (kWh) decrease in credits
given to direct access customers. During the period January 1, 2002 through July 27, 2002, direct access customers were given an
average credit of 11(cent)per kWh. This average credit was reduced to 8.3(cent)per kWh on July 27, 2002, to collect a nonbypassable
historical procurement charge, causing SCE's revenue to increase by 2.7(cent)per kWh through the end of 2002. Beginning on January 1,
2003, SCE's share of the nonbypassable historical procurement charge was reduced to 1(cent)per kWh, with the remaining 1.7(cent)per kWh
allocated and remitted to CDWR for its costs associated with direct access customers (see discussion below). The increases were
partially offset by an increase in amounts remitted to CDWR for energy purchases, including an allocation adjustment during the
six-month period ended June 30, 2003,
Page 25
bond-related charges (beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003).
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an energy service provider
other than SCE (thus becoming direct access customers) or continue to have SCE purchase power on their behalf. On March 21, 2002,
the CPUC issued a decision affirming that new direct access arrangements entered into by SCE's customers after September 20, 2001
were invalid. Direct access arrangements entered into prior to September 20, 2001 remain valid. Direct access customers continue to
be given an average credit of 8.3(cent)per kWh, for the generation costs SCE saves by not serving them. Electric utility revenue is
reported net of this credit. See "SCE's Regulatory Matters--Direct Access Proceedings" discussion.
Amounts SCE bills and collects from its customers for electric power purchased and sold by CDWR to SCE's customers (beginning
January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003) are
remitted to CDWR and are not recognized as revenue by SCE. These amounts were $421 million and $845 million for the three- and
six-month periods ended June 30, 2003, respectively, compared to $255 million and $596 million for the three- and six-month periods
ended June 30, 2002, respectively.
Nonutility power generation revenue increased for both the three- and six-month periods ended June 30, 2003, compared to the same
periods in 2002, primarily due to increased electric revenue from EME's Homer City facilities and Contact Energy, partially offset by
decreased revenue from EME's Illinois plants. The increases at EME's Homer City facilities were primarily due to increased
generation and higher energy prices. The increases at EME's Contact Energy were primarily due to higher wholesale energy prices,
higher generation and an increase in the average exchange rate during the second quarter and year-to-date ended June 30, 2003,
compared to the corresponding periods in 2002. The decrease at EME's Illinois plants was primarily due to lower capacity revenue
from the reduction in MW contracted under the power purchase agreements (see below), offset by an increase in energy revenue,
primarily in the first quarter of 2003, from increased merchant generation at higher average realized energy prices.
In accordance with power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power
purchase agreements at EME's Illinois plants. Of the generating capacity released by Exelon Generation, EME's subsidiary suspended
operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, EME's Illinois plants have 3,133 MW available for
sale as merchant energy. Exelon Generation is obligated, under the power purchase agreements, to make capacity payments for the
Illinois plants under contract (4,739 MW during 2003) and energy payments for electricity produced by these plants. As a result of
the decline in contracted generating capacity under the power purchase agreements, EME's revenue from Exelon Generation was $162
million and $274 million for the second quarters of 2003 and 2002, respectively. EME's revenue from Exelon Generation was $293
million and $436 million for the six-month periods ended June 30, 2003 and 2002, respectively. This represents 23% and 41% of
nonutility power generation revenue for the second quarters of 2003 and 2002, respectively, and 21% and 36% for the six-month periods
ended June 30, 2003 and 2002, respectively. See "Illinois Plants" in "Market Risk Exposures--EME's Market Risks--Commodity Price Risk"
for further discussion.
Nonutility power generation revenue during the third quarter is materially higher than revenue related to other quarters of the year
because warmer weather during the summer months results in higher revenue being generated from EME's Homer City facilities and
Illinois plants. By contrast, EME's First Hydro plants have higher revenue during their winter months. During 2002 and the first
quarter of 2003, there was further downward pressure on wholesale prices but some recovery in the peak/off peak differentials for the
upcoming winter period. This gradual recovery in the forwards market has continued through the second quarter, reflecting an
expected reduction in the excess of available physical generating capacity
Page 26
over expected electrical demand for the upcoming winter period. EME believes that if market and trading conditions experienced thus
far in 2003 are sustained, EME's First Hydro will continue to be compliant with the requirements of its bond financing documents.
This compliance is, however, subject to market conditions for electric energy and ancillary services, which are beyond EME's control.
Financial services and other revenue decreased for the six-month period ended June 30, 2003, compared to the same period in 2002,
primarily due to Edison Capital's maturing lease portfolio and no nonutility real estate sales in 2003, as compared to 2002.
Operating Expenses
Fuel expense increased for the six-month period ended June 30, 2003, compared to the same period in 2002, primarily due to increased
generation from EME's Homer City facilities and EME's coal plants in Illinois. The 2003 increases from EME's Homer City facilities
were primarily the result of outages experienced during the first two quarters of 2002.
Purchased-power expense increased for both the quarter and year-to-date ended June 30, 2003, compared to the same periods in 2002,
mainly due to higher expenses related to power purchased by SCE from qualifying facilities (QFs), as discussed below, as well as
higher expenses related to SCE's bilateral contracts and interutility contracts.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments
to gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002, energy payments for most renewable QFs were
converted to a fixed price of 5.37(cent)per kWh, compared with an average of 3.1(cent)per kWh during the period between January and April
2002. During 2003, spot natural gas prices were higher compared to the same period in 2002. The 2003 increase in purchased-power
expense related to SCE's bilateral and interutility contracts was also due to the increase in spot natural gas prices, as well as an
increase in the number of bilateral contracts entered into during 2003.
Provisions for regulatory adjustment clauses - net increased for both the three- and six-month periods ended June 30, 2003, compared
to the same periods in 2002. The three- and six-month period increases were mainly due to SCE's reestablishment of regulatory assets
related to its unamortized nuclear facilities, purchased-power settlements and flow-through taxes recorded in 2002, partially offset
by a decrease in overcollections used to recover the PROACT balance resulting primarily from higher QF costs. The six-month period
ended June 30, 2003 increase was also partially offset by an allocation adjustment for CDWR energy purchases.
Other operating and maintenance expense did not change overall for the three-month period ended June 30, 2003, compared to the same
period in 2002; however SCE's other operating and maintenance expense decreased for the three-month period, which was almost entirely
offset by an increase in other operating and maintenance expense at EME. Other operating and maintenance increased during the
six-month period ended June 30, 2003, as compared to the same period in 2002.
SCE's other operating and maintenance expense decreased for the three-month period ended June 30, 2003 mainly due to higher
Independent System Operator (ISO) administrative costs during 2002. Other operating and maintenance expense increased during the
six-month period ended June 30, 2003, as compared to the same period in 2002, mainly due to higher health-care costs, higher storm
damage expenses, and higher spending on certain CPUC-authorized programs, partially offset by lower ISO administrative costs.
Page 27
EME's operating and maintenance expense increased for the three- and six-month periods ended June 30, 2003, as a result of higher
transmission costs primarily due to higher retail sales generated at EME's Contact Energy.
Depreciation, decommissioning and amortization expense decreased during the second quarter of 2003, compared to the same period in
2002, mainly due to a decrease in SCE's nuclear decommissioning expense, a decrease in amortization due to the change in the
amortization period of SCE's nuclear facilities based on the URG decision received in the second quarter of 2002, partially offset by
an increase in depreciation expense associated with SCE's additions to transmission and distribution assets, higher amortization
expense at EME's Contact Energy project, and an increase in amortization expense at Edison Capital resulting from a change from the
cost method to the equity method of accounting for its fund investments in 2002.
Asset impairment expense in 2003 consisted of $245 million related to the impairment of eight small peaking plants owned by EME's
wholly owned subsidiary, Midwest Generation, and $6 million related to EME's write-down of its investment in the Gordonsville project
due to its planned disposition (see "Acquisitions and Dispositions" for further discussion). The impairment charge related to the
peaking plants resulted from a revised long-term outlook for capacity revenue from the peaking plants. The lower capacity revenue
outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity
in the Mid-America Interconnected Network (MAIN) region market. See Financial Condition--EME's Liquidity Issues--EME's Recourse Debt
to Recourse Capital Ratio The book value of these assets was written down from $286 million to an estimated fair market value of
$41 million. The estimated fair market value was determined based on discounting estimated future cash flows using a 17.5 % discount
rate. No comparable amount was recorded for the first six months of 2002.
Other Income and Deductions
Interest and dividend income decreased for both the three- and six-month periods ended June 30, 2003, compared to the same periods in
2002, mainly due to lower interest income from a lower PROACT balance at SCE. The six-month period decrease also reflects lower
interest income from lower average cash balances at SCE and lower interest rates.
Equity in income from partnerships and unconsolidated subsidiaries - net increased in the second quarter and year-to-date ended June
30, 2003, compared to the same periods in 2002, primarily due to an increase in EME's share of income from its Big 4 projects from
higher energy prices, Four Star Oil & Gas from higher natural gas prices and Paiton project from lower project depreciation and
interest expense and inclusion of subordinated debt interest income. EME's third quarter equity in income from its domestic energy
projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer
months and because a number of EME's domestic energy projects, located on the west coast, have power sales contracts that provide for
higher payments during the summer months.
Other nonoperating income increased for both the three- and six-month periods ended June 30, 2003, compared to the same periods in
2002. The increases were mainly due to SCE's recognition of performance rewards related to the Palo Verde Nuclear Generating Station
(Palo Verde) approved by the CPUC during second quarter 2003. The six-month increase also reflects SCE's accrual of 2002
performance-based ratemaking (PBR) revenue under the PBR sharing mechanism filed with the CPUC during first quarter 2003.
Interest expense - net of amounts capitalized decreased for the six-month period ended June 30, 2003, compared to the same period in
2002, primarily due to lower interest expense at SCE related to the
Page 28
suspension of payments for purchased power during 2001 and early 2002. These obligations were paid in March 2002. In addition, the
decrease was due to lower interest expense at SCE resulting from lower short-term and long-term debt balances and lower interest
rates.
Other nonoperating deductions increased for the year-to-date period ended June 30, 2003, mainly due to accruals for regulatory
matters at SCE.
Income Taxes
Income taxes decreased for both the three- and six-month periods ended June 30, 2003, compared to the same periods in 2002, primarily
due to a decrease in pre-tax income, partially offset by a reduction in SCE's tax expense in 2002 related to the income tax benefit
associated with the reestablishment of generation-related regulatory assets upon implementation of the URG decision.
Edison International's composite federal and state statutory rate was approximately 40.5% for both periods presented. The lower
effective tax rate of (75.9)% and 18.4% realized for the three- and six-month periods ended June 30, 2003 was primarily due to
low-income housing and production credits at Edison Capital and favorable state tax adjustments, offset by foreign income costs at
EME. In addition, the six-month period decrease was partially offset by an increase in property-related flow-through taxes at SCE.
Loss from Discontinued Operations
Edison International's discontinued operations for the three- and six-month periods ended June 30, 2003 reflect a loss of $2 million
resulting from adjustments related to EME's sale of the Fiddler's Ferry and Ferrybridge and Lakeland projects. Edison
International's discontinued operations for the three- and six-month periods ended June 30, 2002 reflect operating results from EME's
Lakeland project and the recovery of an insurance claim related to the operation of EME's Fiddler's Ferry and Ferrybridge project
prior to its sale in 2001. On May 14, 2003, a third party completed the purchase of the Lakeland power plant from the administrative
receiver for(pound)24 million (approximately $39 million). The proceeds from the sale and existing cash were used to fund partial
repayment of the outstanding debt owed to secured creditors of the project.
Cumulative Effect of Accounting Change - Net
Edison International's results for the six-month period ended June 30, 2003 include a $9 million charge at EME for the cumulative
effect of an accounting change related to the new accounting standard for recording asset retirement obligations adopted by Edison
International in January 2003. As SCE follows accounting principles for rate-regulated enterprises, implementation of this new
standard did not affect its earnings.
FINANCIAL CONDITION
The liquidity of Edison International is affected primarily by debt maturities, access to capital markets, external financings,
dividend payments, capital expenditures, lease obligations, asset purchases and sales, investments in partnerships and unconsolidated
subsidiaries, utility regulation and energy market conditions. Capital resources primarily consist of cash from operations, asset
sales and external financings. California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.
A summary of current liquidity issues is provided below. A detailed discussion of liquidity issues is included in the "Financial
Condition" section in the year-ended 2002 MD&A.
Page 29
Cash Flows from Operating Activities
Net cash provided (used) by operating activities:
In millions Six Months Ended June 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ 1,350 $ (365)
Discontinued operations (17) 48
- ------------------------------------------------------------------------------------------------------------------------------
$ 1,333 $ (317)
- ------------------------------------------------------------------------------------------------------------------------------
The change in cash provided (used) by operating activities from continuing operations was mainly due to SCE's March 2002 repayment of
past-due obligations, partially offset by lower accrued interest and taxes in 2003 as compared to 2002. The change was also due to
timing of cash receipts and disbursements related to working capital items at both SCE and EME.
Cash Flows from Financing Activities
Net cash used by financing activities:
In millions Six Months Ended June 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (510) $ (1,660)
Discontinued operations -- (8)
- ------------------------------------------------------------------------------------------------------------------------------
$ (510) $ (1,668)
- ------------------------------------------------------------------------------------------------------------------------------
Cash used by financing activities from continuing operations in 2002 mainly consisted of long- and short-term debt payments at SCE
and EME.
During the first quarter of 2003, Edison International (parent only) repurchased approximately $132 million of the outstanding $750
million of its 6-7/8% notes due September 2004. No repurchases were made during the second quarter of 2003. During the six-month
period ended June 30, 2003, SCE repaid $300 million of a one-year term loan due March 3, 2003, and $300 million on its revolving line
of credit, both of which were part of the $1.6 billion financing that took place in the first quarter of 2002. In addition, SCE
repaid $125 million of its 6.25% first and refunding mortgage bonds. EME's financing activity in the six-month period ended June 30,
2003 consisted of net borrowings of $275 million on EME's $487 million corporate credit facility, $275 million in borrowings by
Contact Energy, EME's 51% owned subsidiary, used to finance Contact Energy's acquisition of the Taranaki Combined Cycle power station
(see "Acquisitions and Dispositions" for further discussion of the acquisition), and a debt service payment of $23 million made in
March 2003 related to one of EME's subsidiaries.
During the six-month period ended June 30, 2002, SCE repaid $531 million of commercial paper, $400 million of its maturing principal
on its senior unsecured notes, and remarketed $196 million of the $550 million of pollution-control bonds repurchased during December
2000 and early 2001. Also during the first quarter of 2002, SCE replaced the $1.65 billion credit facility with a $1.6 billion
financing and made a payment of $50 million to retire the remainder of the $1.65 billion credit facility. EME's financing activity
during the six-month period ended June 30, 2002 consisted of a $100 million payment at maturity on senior notes, net payments of
$80 million on EME's corporate credit facility, debt service payments of $22 million, payments of $86 million on debt related to its
Coal and Capex facility and $84 million in borrowings under a note purchase agreement in January 2002 by a subsidiary of EME. EME
also received $54 million from a swap agreement with a bank related to lease payments for its Homer City facilities. Edison Capital
financing activity in the first quarter of 2002 included a $94 million pay-off of debt.
Page 30
Cash Flows from Investing Activities
Net cash provided (used) by investing activities:
In millions Six Months Ended June 30, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (934) $ (490)
Discontinued operations 5 1
- ------------------------------------------------------------------------------------------------------------------------------
$ (929) $ (489)
- ------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities are affected by additions to property and plant, EME's sales of assets and SCE's funding of
nuclear decommissioning trusts.
Additions to SCE's property and plant for the six-month period ended June 30, 2003, were approximately $540 million, primarily for
transmission and distribution assets. EME's capital additions for the six-month period ended June 30, 2003 were $79 million
primarily for new plant and equipment related to EME's Illinois plants, its Homer City facilities, and Contact Energy. EME's
year-to-date 2003 investing activity also included $275 million paid by Contact Energy for the acquisition of Taranaki Combined Cycle
power station (see "Acquisitions and Dispositions" for further discussion of the acquisition), and $39 million in equity contribution
to EME's Sunrise and CBK projects.
Additions to SCE's property and plant for the six-month period ended June 30, 2002, were approximately $463 million, primarily for
transmission and distribution assets. EME's capital additions in the six-month period ended June 30, 2002 were $115 million
primarily for new plant and equipment related to EME's Valley Power peaker project in Australia, Illinois plants, and the Homer City
facilities. EME's investing activity for the six-month period ended June 30, 2003, also included an $80 million payment for the
purchase of a power sales agreement, $147 million in payments for three turbines and termination of its Master Turbine Lease, $44
million in proceeds from EME's sale of its ownership interests in three energy projects, $78 million in distributions from EME's
projects, and $53 million used to meet EME's lease payment obligations.
Edison International's (parent only) Liquidity Issues
At June 30, 2003, Edison International (parent) had approximately $100 million of cash and equivalents on hand. The parent company's
liquidity and its ability to pay interest, debt principal, operating expenses and dividends to common shareholders are affected by
dividends from subsidiaries, tax-allocation payments under its tax-allocation agreement with its subsidiaries, and access to capital
markets or external financings.
During the first quarter of 2003, Edison International repurchased approximately $132 million of the outstanding $750 million of its
6-7/8% notes due September 2004. No repurchases were made during the second quarter of 2003. The ability of Edison International to
pay its 6-7/8% notes due September 2004 may be substantially dependent, among other things, on subsidiary dividends.
The management of Edison International has stated that it is the company's goal to pay a dividend to the holders of common stock in
early 2004. For a dividend to be paid, it must be declared by the board of directors of Edison International. The board generally
would declare a dividend at least 22 days before the payment date to allow time for notices and processing. The ability of the board
of directors to declare a common stock dividend will depend on the company's financial condition and liquidity, including payment of
all previously deferred interest on its quarterly income debt securities described below, the outcome of the litigation described
under "SCE's Regulatory Matters--CPUC Litigation Settlement Agreement," and the resumption of dividends to Edison International from
SCE.
Page 31
Since May 2001, Edison International has deferred the interest payments in accordance with the terms of its outstanding $825 million
quarterly income debt securities, due 2029, issued to an affiliate. This caused a corresponding deferral of distributions on
quarterly income preferred securities issued by that affiliate. Interest payments may be deferred for up to 20 consecutive
quarters. Edison International cannot declare and pay cash dividends on or purchase its common stock as long as interest is being
deferred. Returning to quarterly payments under the terms of these securities will require a one-time catch-up payment of the
deferred interest (approximately $166 million as of June 30, 2003), which is significantly dependent upon receipt of subsidiary
dividend payments to Edison International.
The CPUC regulates SCE's capital structure by requiring that SCE maintain a prescribed percentage of common equity, preferred stock
and long-term debt in the utility's capital structure. SCE may not make any distributions to Edison International that would reduce
the common equity component of SCE's capital structure below the prescribed level. SCE's settlement agreement with the CPUC also
precluded SCE from declaring or paying dividends or other distributions on its common stock (all of which is held by its parent,
Edison International) prior to the earlier of the date on which SCE has recovered all of its procurement-related obligations or
January 1, 2005, with certain exceptions. SCE fully recovered the PROACT balance during July 2003. Other factors at SCE that affect
the amount and timing of dividend payments to Edison International include, among other things, the outcome of the pending appeal of
the stipulated judgment approving SCE's settlement agreement with the CPUC (see "SCE's Regulatory Matters--CPUC Litigation Settlement
Agreement"), SCE's access to capital markets and actions by the CPUC.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At June 30, 2003, its interest coverage
ratio was 1.32 to 1. See "--MEHC's Liquidity Issues--MEHC's Interest Coverage Ratio." MEHC did not declare or pay a dividend in the
first six months of 2003. MEHC's ability to pay dividends is dependent on EME's ability to pay dividends to MEHC.
EME and its subsidiaries have certain dividend restrictions as discussed in "--EME's Liquidity Issues" section below. EME did not pay
or declare a dividend during the first six months of 2003.
Edison International's investment in MEHC, through a wholly owned subsidiary, as of June 30, 2003, was $723 million. MEHC's
investment in EME, as of June 30, 2003, was $1.7 billion. The independent accountants' audit opinions on the year-end 2002 financial
statements of MEHC, EME and Midwest Generation contain an explanatory paragraph that indicates the consolidated financial statements
have been prepared on the basis that these companies will continue as going concerns and that the uncertainty about Edison Mission
Midwest Holdings' ability to repay, extend, or refinance this obligation raises substantial doubt about their ability to continue as
going concerns. For an expanded discussion, see "Current Developments--MEHC and EME Developments."
Edison Capital's ability to make dividend payments is restricted by debt covenants, which require Edison Capital to maintain a
specified minimum net worth. Edison Capital currently exceeds the threshold amount. Edison Capital did not declare or pay a
dividend in the first six months of 2003.
SCE's Liquidity Issues
SCE expects to meet its continuing obligations in 2003 from cash and equivalents on hand and operating cash flows. SCE had $994
million in cash and equivalents as of June 30, 2003.
In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE. Based on the rights to recover its past
procurement-related costs, SCE repaid its undisputed past-due obligations and near-term debt maturities in March 2002, using cash on
hand resulting from the proceeds of the $1.6 billion credit facilities and the remarketing of $196 million in pollution-control
bonds. The
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$1.6 billion credit facilities included a $600 million, one-year term loan due on March 3, 2003. SCE prepaid $300 million of this
loan on August 14, 2002 and the remaining $300 million on February 11, 2003. The $1.6 billion credit facilities also included a $300
million revolving line of credit with a March 2004 maturity and a $700 million term loan with a March 2005 final maturity. On April
16, 2003, SCE fully repaid the $300 million drawn under its revolving line of credit. Under the term loan, net-cash proceeds from
the issuance of capital stock or new indebtedness must be used to reduce the term loan subject to certain exceptions.
On February 24, 2003, SCE completed an exchange offer for its 8.95% variable rate notes due November 2003. A total of $966 million
of these notes was exchanged for $966 million of a new series of first and refunding mortgage bonds due February 2007. As a result
of the exchange offer, SCE's remaining significant debt maturity in 2003 is $34 million, comprising of the 8.95% variable rate notes
due November 2003 that were not exchanged. In addition, approximately $131 million of rate reduction notes are due in the remainder
of 2003. These notes have a separate cost recovery mechanism approved by state legislation and CPUC decisions.
SCE fully recovered the PROACT balance during July 2003. As a result of recovering the PROACT balance, SCE implemented a CPUC
approved customer rate-reduction plan effective August 1, 2003. The customer rate-reduction plan reduces SCE's annual rates by $1.2
billion, but has no impact on earnings. See "SCE Regulatory Matters--Other Regulatory Matters--Customer Rate-Reduction Plan" for
further details.
As of June 30, 2003, SCE's common equity to total capitalization ratio, for rate-making purposes, was approximately 64%. The
CPUC-authorized level is 48%. SCE expects to rebalance its capital structure to CPUC-authorized levels in the future by paying
dividends to its parent, Edison International, and issuing debt as necessary. Factors that affect the amount and timing of such
actions include, among other things, the outcome of the pending appeal of the stipulated judgment approving SCE's settlement
agreement with the CPUC (see "SCE's Regulatory Matters--CPUC Litigation Settlement Agreement"), SCE's access to the capital markets
and actions by the CPUC.
SCE resumed procurement of its residual net short (the amount of energy needed to serve SCE's customers from sources other than its
own generating plants, power purchase contracts and CDWR contracts) on January 1, 2003 and as of June 30, 2003, has approximately
$118 million posted as collateral to secure its obligations under power purchase contracts and to transact through the ISO for
imbalance power.
SCE's liquidity may be affected by, among other things, matters described in "SCE's Regulatory Matters--CPUC Litigation Settlement
Agreement,--CDWR Power Purchases and Revenue Requirement Proceedings, and--Generation Procurement Proceedings" sections.
MEHC's Liquidity Issues
At June 30, 2003, MEHC and its subsidiaries had cash and cash equivalents of $910 million (including $801 million from EME and its
subsidiaries) and EME had available a total of $71 million of borrowing capacity under its $487 million corporate credit facility.
MEHC's consolidated debt at June 30, 2003 was $7.9 billion, including $275 million of EME debt maturing on September 16, 2003 and
$911 million of debt maturing on December 11, 2003 that is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In
addition, EME's subsidiaries have $7 billion of long-term lease obligations that are due over periods ranging up to 32 years.
The $275 million of debt at EME maturing on September 16, 2003 will need to be repaid, extended or refinanced. In addition, the
$911 million of debt of Edison Mission Midwest Holdings maturing on
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December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient
cash to repay the $911 million debt due on December 11, 2003. During the second quarter, EME and Edison Mission Midwest Holdings
commenced discussions with their lenders regarding restructuring their respective indebtedness. There is no assurance that either
EME or Edison Mission Midwest Holdings will be able to extend or refinance their respective debt obligations on similar terms and
rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by
MEHC in July 2001, or at all. A failure to repay, extend, or refinance the Edison Mission Midwest Holdings or EME obligations is
likely to result in, or in the case of EME would result in, a default under the MEHC senior secured notes and term loan. These
events could make it necessary for MEHC or EME, or both, to file a petition for reorganization under Chapter 11 of the United States
Bankruptcy Code. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory
paragraph that indicates the consolidated financial statements have been prepared on the basis that MEHC will continue as a going
concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises
substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not
include any adjustments that might result from the resolution of this uncertainty.
The remainder of this section discusses MEHC's liquidity issues on a stand alone basis. See "--EME's Liquidity Issues" for further
discussion of EME related items that may impact MEHC on a consolidated basis.
MEHC's ability to honor its obligations under the senior secured notes and the term loan after the two year interest reserve period
(which expired July 2, 2003 for the term loan and July 15, 2003 for the senior secured notes) and to pay overhead is substantially
dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, a wholly owned subsidiary
of Edison International, and ultimately Edison International. Part of the proceeds from the senior secured notes and the term loan
were used to fund escrow accounts to secure the first four interest payments due under the senior secured notes and the interest
payments for the first two years under the term loan. Other than the dividends received from EME and funds received pursuant to
MEHC's tax-allocation arrangements (see--Intercompany Tax-Allocation Payments) with MEHC's affiliates, MEHC will not have any other
source of funds to meet its obligations under the senior secured notes and the term loan. Dividends from EME are limited based on
its earnings and cash flow, terms of restrictions contained in EME's contractual obligations (including its corporate credit
facility), EME's charter documents, business and tax considerations, and restrictions imposed by applicable law. MEHC did not
receive any distributions from EME during the first six months of 2003.
At June 30, 2003, MEHC had cash and cash equivalents of $109 million and restricted cash of $80 million (excluding amounts held by
EME and its subsidiaries). Restricted cash represented monies deposited into the interest escrow accounts described above. The
funds collected in the accounts were used to make the interest payments due under the senior secured notes and the term loan through
July 15, 2003. The lenders under MEHC's $385 million term loan due in 2006 have the right to require MEHC to repurchase up to $100
million of principal amount at par on July 2, 2004 (referred to as the Term Loan Put-Option). In order for MEHC to have sufficient
cash in the event of an exercise of a significant portion, or all, of the Term Loan Put-Option, MEHC would require additional cash
from dividends from EME, or would need to either extend the effective date of the Term Loan Put-Option or extend or refinance the
term loan (see "Current Developments--MEHC and EME Developments"). The timing and amount of dividends from EME and its subsidiaries
may be affected by many factors beyond MEHC's control. Dividends from EME are currently limited as described in "--EME's Liquidity
Issues--Ability of EME to Pay Dividends."
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MEHC's Interest Coverage Ratio
The following details of MEHC's interest coverage ratio are provided as an aid to understanding the components of the computations
that are set forth in the indenture governing MEHC's senior secured notes. This information is not intended to measure the financial
performance of MEHC and, accordingly, should not be used in lieu of the financial information set forth in MEHC's consolidated
financial statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture
and are not the same as would be determined in accordance with generally accepted accounting principles.
MEHC's interest coverage ratio is comprised of interest income and expense related to its holding company activities and the
consolidated financial information of EME. For a complete discussion of EME's interest coverage ratio, see "Edison Mission Energy's
Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage ratio:
Twelve Months Ended Year Ended
In millions June 30, 2003 December 31,2002
- -----------------------------------------------------------------------------------------------------------------------------------
Funds Flow From Operations:
EME $ 597 $ 692
Operating cash flow from
unrestricted subsidiaries (1) (17)
Outflows of funds from
operations of projects sold (17) 2
MEHC 3 7
- -----------------------------------------------------------------------------------------------------------------------------------
$ 582 $ 684
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Expense:
EME $ 280 $ 293
EME - affiliate debt 1 2
MEHC interest expense 160 159
- -----------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 441 $ 454
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 1.32 1.51
- -----------------------------------------------------------------------------------------------------------------------------------
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's
senior secured notes and the credit agreement governing the term loan. The interest coverage ratio prohibits MEHC, EME and its
subsidiaries from incurring additional indebtedness, except as specified in the indenture and the financing documents, unless MEHC's
interest coverage ratio exceeds 1.75 to 1 for the immediately preceding four fiscal quarters prior to June 30, 2003 and 2.0 to 1 for
periods thereafter.
MEHC's Intercompany Tax-Allocation Payments
MEHC is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to
participate in tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison
International continuing to own, directly or indirectly, at least 80% of the voting power of the stock of MEHC and at least 80% of
the value of such stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison
International, MEHC, EME and other Edison International subsidiaries. The agreements to which MEHC is a party may be terminated by
the immediate parent company of MEHC at any time, by notice given before the first day of the first tax year with respect to which
the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year
beginning prior to the notice. MEHC became a party to the tax-allocation agreement with a wholly owned
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subsidiary of Edison International on July 2, 2001, when it became part of the Edison International consolidated filing group. MEHC
has historically received tax-allocation payments related to domestic net operating losses incurred by MEHC. The right of MEHC to
receive and the amount and timing of tax-allocation payments are dependent on the inclusion of MEHC in the consolidated income tax
returns of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC, its
subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC
receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates
sufficient taxable income in order to be able to utilize MEHC's tax losses in the consolidated income tax returns for Edison
International and its subsidiaries. During the six-month period ended June 30, 2003, MEHC received $25 million in tax-allocation
payments from Edison International. In the future, based on the application of the factors cited above, MEHC may be obligated during
periods they generate taxable income to make payments under the tax-allocation agreements.
EME's Liquidity Issues
The discussions below include the following matters that affect EME's liquidity: EME's credit ratings, EME's corporate liquidity,
historical distributions received by EME, the ability of EME to pay dividends, EME's interest coverage and recourse debt to recourse
capital ratios, EME subsidiary financing plans, and EME's intercompany tax-allocation payments.
EME's Credit Ratings
Credit ratings for EME and its subsidiaries, Edison Mission Midwest Holdings and Edison Mission Marketing & Trading, are as follows:
Moody's
Rating S&P Rating
- ------------------------------------------------------------------------------------------------------------------------------
EME (senior unsecured) B2 BB-
Edison Mission Midwest Holdings (bank facility) Ba3 BB-
Edison Mission Marketing & Trading (senior unsecured) Not Rated BB-
- ------------------------------------------------------------------------------------------------------------------------------
Moody's Investors Service and Standard & Poor's Rating Service have assigned a negative rating outlook for each of these entities.
The credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and
letters of credit for the benefit of counterparties for its price risk management and domestic trading activities related to accounts
payable and unrealized losses ($56 million as of August 8, 2003). EME has also provided collateral for a portion of its United
Kingdom trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash
collateralized credit facility, under which letters of credit totaling(pound)19 million have been issued as of July 31, 2003.
EME anticipates that sales of power from its Illinois plants, Homer City facilities and First Hydro plants in the United Kingdom may
require additional credit support, depending upon market conditions and the strategies adopted for the sale of this power. Changes
in forward market prices and margining requirements could further increase the need for credit support for the price risk management
and trading activities related to these projects. EME currently projects the potential working capital required to support its price
risk management and trading activity to be between $100 million and $200 million from time to time during 2003.
EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any
given period of time or that one or more of these ratings will not be lowered
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further. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any
time by a rating agency.
Credit Ratings of Edison Mission Midwest Holdings
As a result of the downgrade of Edison Mission Midwest Holdings below investment grade in October 2002, provisions in the agreements
binding on Edison Mission Midwest Holdings and Midwest Generation restrict the ability of Edison Mission Midwest Holdings to make
distributions to its parent company, thereby eliminating distributions to EME.
The following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related
changes in the cost of borrowing by Edison Mission Midwest Holdings under the applicable financing agreements. The currently
applicable provisions are those set forth in the same row as the Standard & Poor's rating "BB-."
Cost of Borrowing
S&P Rating Moody's Rating Margin (basis points) Cash Trap
- -------------------------------------------------------------------------------------------------------------------------------------
(based on LIBOR)
BBB- or higher Baa3 or higher 150 No cash trap
BB+ Ba1 225 50% of excess cash flow trapped until six
month debt service reserve is funded
BB Ba2 275 100% of excess cash flow trapped
BB- Ba3 325 100% of excess cash flow trapped
B+ B1 325 100% of excess cash flow trapped and
used to repay debt
- -------------------------------------------------------------------------------------------------------------------------------------
Based on its current credit ratings, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit,
on a quarterly basis, 100% of its excess cash flow as defined in the agreements into a cash flow recapture account held and
maintained by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited $50 million into
the cash flow recapture account on October 31, 2002, and another $28 million on January 27, 2003. The funds in the cash flow
recapture account may be used only to meet debt service obligations of Edison Mission Midwest Holdings if funds are not otherwise
available from working capital. There is no assurance that Edison Mission Midwest Holdings' current credit rating will not be
lowered again, in which case Edison Mission Midwest Holdings would be required to use the funds from time to time on deposit in the
cash flow recapture account to repay indebtedness.
As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.4 billion) to EME
in exchange for promissory notes in the same aggregate amount. Debt service payments by EME on the promissory notes may be used by
Midwest Generation to meet its payment obligations under these leases in whole or part. Furthermore, EME has guaranteed the lease
obligations of Midwest Generation under these leases. EME's obligations under the promissory notes payable to Midwest Generation are
general corporate obligations of EME and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See
"--Restricted Assets of EME's Subsidiaries--Edison Mission Midwest Holdings Co. (Illinois Plants)" for a discussion of implications for
the Powerton and Joliet leases.
Credit Rating of Edison Mission Marketing & Trading
Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading
restricts the ability of EME Homer City Generation L.P. (EME Homer City) to enter into permitted trading activities, as defined in
the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities. These documents
include a
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requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be
investment grade. EME currently sells all of the output from the Homer City facilities through Edison Mission Marketing & Trading,
which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell
forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to
permit EME Homer City to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission
Marketing & Trading must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has
obtained consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified
conditions, through December 31, 2004. EME is permitted to sell the output of the Homer City facilities into the Pennsylvania-New
Jersey-Maryland Power Pool (PJM) market at any time on a spot-market basis. See "Market Risk Exposures--EME's Market Risks--Homer City
Facilities."
EME Corporate Liquidity
EME has a $487 million corporate credit facility which includes a $275 million component, Tranche A, that expires on September 16,
2003, and a $212 million component, Tranche B, that expires on September 17, 2004. As of June 30, 2003, EME had borrowed $275
million under Tranche A in order to improve its short-term liquidity. At June 30, 2003, EME had borrowing capacity under Tranche B
of $71 million and corporate cash and cash equivalents of $302 million.
Cash distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused
capacity under its corporate credit facilities represent EME's major sources of liquidity to meet its cash requirements. In
addition, EME is engaged in the Sunrise project financing which it plans to complete during the next three months, which, if
completed, will result in the receipt by EME of approximately $150 million of capital previously invested in this project. See "--EME
Subsidiary Financing Plans." EME expects its 2003 cash requirements to be primarily comprised of:
o interest payments on its indebtedness, including interest payments to Midwest Generation related to intercompany loans,
o collateral requirements in the form of letters of credit or cash margining in support of forward contracts for the sale of
power from its merchant energy operations,
o general administrative expenses, and
o equity contribution obligations.
The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "--Historical
Distributions Received by EME--Restricted Assets of EME's Subsidiaries." In addition, the right of EME to receive tax-allocation
payments, and the timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See
"--EME's Intercompany Tax-Allocation Payments." If Tranche A of the corporate facility is not extended and the Sunrise project
financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel related
to its merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the
number of counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely
on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining
requirements if forward prices for power increase significantly. Failure to meet a margining requirement would permit the
counterparty to terminate the related bilateral contract early and demand immediate payment of damages incurred by reason of such
termination.
Page 38
EME's corporate credit facility provides credit available in the form of cash advances or letters of credit. At June 30, 2003,
Tranche A consisted of borrowings of $275 million, and $141 million of letters of credit were outstanding under Tranche B. In
addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (0.875% and 1.00% at June 30,
2003 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.
Under the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash
received by EME, including tax-allocation payments, cash disbursements and interest paid. At June 30, 2003, EME met this interest
coverage ratio. The interest coverage ratio in the ring-fencing provisions of EME's certificate of incorporation and bylaws remains
relevant for determining EME's ability to make distributions. See "--EME's Interest Coverage Ratio."
Historical Distributions Received by EME
The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies which
depend on distributions from subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse
debt. Distributions for the first six months of each year are not necessarily indicative of annual distributions due to the seasonal
fluctuations in EME's business.
In millions Six Months Ended June 30, 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) $ 127 $ --
Holding companies of other consolidated operating projects 53 4
Distributions from Non-Consolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 projects)(1) 20 82
Four Star Oil & Gas Company -- 21
Holding companies of other non-consolidated operating projects 31 30
- -----------------------------------------------------------------------------------------------------------------------------------
Total Distributions $ 231 $ 137
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Distributions do not include either capital contributions made during the California energy crisis or the subsequent
return of such capital. Distributions reflect the amount received by EME after debt service payments by Edison Mission
Energy Funding Corp.
Total distributions to EME increased due to:
o Distributions from Homer City due to high energy prices. The project did not make any distributions in the first half of
2002 because of a major unplanned outage in February 2002;
o Distribution of $18 million from the First Hydro project in May 2003. The project did not make any distributions in the
first half of 2002 due to restrictions under its bond indenture;
o Increased shareholder dividends from Contact Energy; and
o Distributions of $12 million from the Loy Yang B project in January 2003. Restrictions on distributions from the Loy Yang B
project were removed following completion of the refinancing of the Valley Power peaker project construction loan in 2002.
Partially offset by:
o Lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due accounts receivable
that accrued during the California energy crisis); and
o No Four Star dividends in the first half of 2003 due to the repayment of project level debt.
Page 39
Restricted Assets of EME's Subsidiaries
Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries.
Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries.
However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of
financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to
its subsidiary holding companies. Set forth below is a description of covenants binding EME's principal subsidiaries that may
restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned
by EME.
Edison Mission Midwest Holdings Co. (Illinois Plants)
Edison Mission Midwest Holdings Co. is the borrower under a $1.9 billion credit facility with a group of commercial banks. The funds
borrowed under this facility were used to fund the acquisition of the Illinois plants and provide working capital to such operations.
Midwest Generation, a wholly owned subsidiary of Edison Mission Midwest Holdings, owns or leases and operates the Illinois plants.
As part of the original acquisition, Midwest Generation entered into a sale-leaseback transaction for the Collins Station, which
Edison Mission Midwest Holdings guarantees, and then subsequently entered into sale-leaseback transactions for the Powerton Station
and the Joliet Station in August 2000. In order for Edison Mission Midwest Holdings to make a distribution, Edison Mission Midwest
Holdings and Midwest Generation must be in compliance with the covenants specified in these agreements, including maintaining a
minimum credit rating. Because Edison Mission Midwest Holdings' credit rating is below investment grade, no distributions can
currently be made by Edison Mission Midwest Holdings to its parent company and ultimately to EME, at this time. See "--EME's Credit
Ratings."
Edison Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50
to 1 as long as the power purchase agreements with Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and
its subsidiaries' revenue. If the power purchase agreements with Exelon Generation represent less than 50% of Edison Mission Midwest
Holdings' and its subsidiaries' revenue, it must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that
revenue for 2003 from Exelon Generation will represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenue.
In addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater than 0.60 to 1. Failure to meet the
historical debt service coverage ratio and the debt-to-capital ratio are events of default under the credit agreement and Collins
lease agreements, which, upon a vote by a majority of the lenders, could cause an acceleration of the due date of the obligations of
Edison Mission Midwest Holdings and those associated with the Collins lease. Such acceleration would result in an event of default
under the Powerton and Joliet leases. During the 12 months ended June 30, 2003, the historical debt service coverage ratio was 3.46
to 1 and the debt-to-capital ratio was 0.53 to 1.
There are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its
affiliate Edison Mission Overseas Co. (which is also a subsidiary of Edison Mission Midwest Holdings) or to make distributions
directly to Edison Mission Midwest Holdings.
Page 40
EME Homer City Generation L.P. (Homer City facilities)
EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a
distribution, EME Homer City must be in compliance with the covenants specified in the lease agreements, including the following
financial performance requirement measured on the date of distribution:
o At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (taken as a whole) must
be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of EME Homer City less
amounts paid for operating expenses, required capital expenditures, taxes and financing fees divided by the aggregate amount of
the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service
reserve letter of credit.
At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The senior rent service
coverage ratio (discussed in the bullet point above) projected for each of the prospective two twelve-month periods must be greater
than 1.7 to 1. No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the
failure to pay the equity portion of the rent within five business days of when it is due.
During the 12 months ended June 30, 2003, the senior rent service coverage ratio was 4.32 to 1.
First Hydro Holdings
A subsidiary of First Hydro Holdings, First Hydro Finance plc, has issued of(pound)400 million of Guaranteed Secured Bonds due in 2021.
In order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture,
including an interest coverage ratio. When measured for the twelve-month period ended December 31, 2002, First Hydro Holdings met
the interest coverage ratio and made a distribution of $18 million on May 7, 2003. When measured for the twelve-month period ended
June 30, 2003, First Hydro Holdings' interest coverage ratio was approximately 1.49 to 1.
On March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds, requesting that First Hydro
Finance engage in a process to determine whether an early redemption option in favor of the bondholders has been triggered under the
terms of the First Hydro bonds. This letter states that, given requests made of the trustee by a group of First Hydro bondholders,
the trustee needs to satisfy itself whether the termination of the pool system in the United Kingdom (replaced with the new
electricity trading arrangements, referred to as NETA), was materially prejudicial to the interests of the bondholders. If this were
the case, it could provide the First Hydro bondholders with an early redemption option. In this regard, on August 29, 2000, First
Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the foundation for NETA, would result,
after its implementation, in a so-called restructuring event under the terms of the First Hydro bonds. However, First Hydro Finance
did not believe then, nor does it believe now, that this event was materially prejudicial to the First Hydro bondholders. Since NETA
implementation, First Hydro Finance has continued to meet all of its debt service obligations and financial covenants under the bond
documentation, including the required interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First Hydro
Finance had not received a response from the trustee to its August 29, 2000 notice. First Hydro Finance will dispute any attempt to
have the early redemption option deemed applicable due to NETA implementation.
Neither the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee constitutes an event of
default under the terms of the First Hydro bonds, and there is no recourse to EME for the obligations of First Hydro Finance in
respect of the First Hydro bonds. However, if the bondholders were entitled to an early redemption option, First Hydro Finance would
be obligated to
Page 41
purchase all First Hydro bonds put to it by bondholders at par plus an early redemption premium. If all bondholders opted for the
early redemption option, it is unlikely that First Hydro Finance would have sufficient financial resources to so purchase the bonds.
There is no assurance that First Hydro Finance would be able to obtain additional financing to fund the purchase of the First Hydro
bonds. Therefore, an exercise of the early redemption option by the bondholders could lead to administration proceedings as to First
Hydro Finance in the United Kingdom, which are similar to Chapter 11 bankruptcy proceedings in the United States. If these events
were to occur, they would have a material adverse effect upon First Hydro Finance and could have a material adverse effect upon EME.
Edison Mission Energy Funding Corp. (Big 4 Projects)
EME's subsidiaries, which EME refers to in this context as the guarantors, that hold EME's interests in the Big 4 projects completed
a $450 million secured financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation,
issued notes ($260 million) and bonds ($190 million), the net proceeds of which were lent to the guarantors in exchange for a note.
The guarantors have pledged their cash proceeds from the Big 4 projects to Edison Mission Energy Funding as collateral for the note.
All distributions receivable by the guarantors from the Big 4 projects are deposited into trust accounts from which debt service
payments are made on the obligations of Edison Mission Energy Funding and from which distributions may be made to EME if the
guarantors and Edison Mission Energy Funding are in compliance with the terms of the covenants in their financing documents,
including the following requirements measured on the date of distribution:
o The debt service coverage ratio for the preceding four fiscal quarters is at least 1.25 to 1.
o The debt service coverage ratio projected for the succeeding four fiscal quarters is at least 1.25 to 1.
The debt service coverage ratio is determined primarily based upon the amount of distributions received by the guarantors from the
Big 4 projects during the relevant quarter divided by the debt service (principal and interest) on Edison Mission Energy Funding's
notes and bonds paid or due in the relevant quarter. During the 12 months ended June 30, 2003, the debt service coverage ratio was
2.37 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no
effect on the ability of the guarantors to make distributions to EME.
CBK Project
EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with
National Power Corporation for the 756 MW Caliraya-Botocan-Kalayaan hydro electric complex, located in the Republic of the
Philippines, which EME refers to as the CBK project. On April 23, 2003, the President of the Republic of the Philippines signed into
law the 2003 General Appropriations Act which includes a provision that prohibits payments by agencies of the Philippine government
to CBK Power with respect to two of its units until National Power Corporation submits a report based upon a review of "overpayments"
to the CBK project, if any, and until the project documentation has been amended to provide for recovery by National Power
Corporation of any "overpayments." The assertion regarding "overpayment" stems from a supplemental agreement entered into during
1999 which modified the original build-rehabilitate-operate-transfer agreement by adjusting the schedule for completion of two units
of the CBK complex.
Under the supplemental agreement, the schedule for the rehabilitation of existing Kalayaan Units 1 and 2 was brought forward because
of National Power Corporation's concern about the possibility of transformer failure and other risks affecting the reliability of
these units. Under the original schedule, Kalayaan Units 1 and 2 were to be operated by CBK Power for operation and maintenance fees
only during the lengthy construction of new Kalayaan Units 3 and 4, and upon completion of these units, Kalayaan Units 1 and 2 were
to be taken out of service for rehabilitation. Under the build-rehabilitate-operate-transfer agreement, National Power Corporation
is obligated to pay capital recovery fees to CBK
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Power upon completion of the construction or rehabilitation of each unit, as the case may be. EME understands the term "overpayment"
as used in the Special Provision of the General Appropriations Act, refers to the payments of capital recovery fees for Kalayaan
Units 1 and 2 arising from the earlier than initially scheduled rehabilitation of these units. At the time EME made its investment
in CBK Power, the decision to accelerate the work on Kalayaan Units 1 and 2 had been made and incorporated in the supplemental
agreement, and all appropriate Philippine government approvals of the supplemental and other project agreements with National Power
Corporation had been obtained. Subsequently, some parties in the Philippines have contended that payments made to CBK Power as a
result of the earlier than initially scheduled rehabilitation of Kalayaan Units 1 and 2 were unreasonable in comparison to the amount
of additional work required to rehabilitate the units.
On May 22, 2003, CBK Power and National Power Corporation, with the concurrence of Power Sector Assets and Liabilities Management
Corporation (PSALM), entered into a settlement agreement. PSALM is a Philippine government-owned entity with responsibility for the
electric power sector. The settlement agreement provides for certain concessions to National Power Corporation which have been
deemed by the parties to satisfy the requirements of the Special Provision. In addition, on May 23, 2003, National Power Corporation
submitted a report to the Congress of the Philippines as required by the provisions of the 2003 General Appropriations Act.
Subsequently, the Secretary of Management and Budget confirmed to National Power Corporation that payments could be made to CBK using
funds provided by the 2003 General Appropriations Act based on National Power Corporation's determination that the requirements of
those provisions have been met. National Power Corporation has cleared all arrears owing to CBK Power and has made all payments
since the signing of the settlement agreement in a timely manner.
The effectiveness of the settlement agreement is subject to certain conditions precedent. For CBK Power, the primary requirement is
approval by its lenders. That approval is currently pending. National Power Corporation was required to obtain, and has obtained,
approval from the National Economic Development Authority - Investment Coordinating Committee. The outstanding items required of
Philippine Government parties include opinions of counsel from National Power Corporation and PSALM and a confirmation from the
Department of Finance that the Government Undertaking remains in full force and effect. The parties originally set a deadline of
June 22, 2003 to complete all required conditions. That deadline has, by mutual agreement, been extended to August 20, 2003. Given
the complexities of the outstanding conditions, it may be necessary to extend the deadline for an additional 30 days. EME believes
that the parties will agree to an extension.
As of June 30, 2003, EME has invested $59 million in the CBK project and as of such date is committed to invest up to an additional
$19 million. EME believes that it will recover its entire investment. The indebtedness incurred by CBK Power is non-recourse to EME
and, except for EME's commitment to contribute up to an additional $19 million as equity, EME has no obligation with respect to CBK
Power's indebtedness. Further, these events do not constitute a default under any indebtedness incurred by EME or to which EME or
any of its affiliates is subject.
Ability of EME to Pay Dividends
EME's organizational documents contain restrictions on its ability to declare or pay dividends or distributions. These restrictions
require the unanimous approval of its board of directors, including at least one independent director, before it can declare or pay
dividends or distributions, unless either of the following is true:
o EME then has investment grade ratings with respect to its senior unsecured long-term debt and receives rating agency
confirmation that the dividend or distribution will not result in a downgrade; or
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o such dividends and distributions do not exceed $32.5 million in any fiscal quarter and EME then meets an interest coverage ratio of
not less than 2.2 to 1 for the immediately preceding four fiscal quarters.
EME's interest coverage ratio for the twelve months ended June 30, 2003 was 2.13 to 1. See further details of EME's interest
coverage ratio below. Accordingly, EME is not permitted to pay dividends in the next quarter under the "ring-fencing" provisions of
EME's certificate of incorporation and bylaws. EME did not pay or declare any dividends to MEHC during the first six months of 2003.
EME's Interest Coverage Ratio
During 2001, EME amended its organizational documents to include so-called "ring-fencing" provisions. These provisions require the
unanimous approval of EME's board of directors, including at least one independent director, before EME can do any of the following:
o declare or pay dividends or distributions unless either of the following are true: EME then has an investment grade credit
rating and receives rating agency confirmation that the dividend or distribution will not result in a downgrade; or the dividends
do not exceed $32.5 million in any fiscal quarter and EME meets an interest coverage ratio of not less than 2.2 to 1 for the
immediately preceding four fiscal quarters.
o institute or consent to bankruptcy, insolvency or similar proceedings or actions; or consolidate or merge with any entity or
transfer substantially all EME's assets to any entity, except to an entity that is subject to similar restrictions.
The following details of EME's interest coverage ratio are provided as an aid to understanding the components of the computations
that are set forth in EME's organizational documents. This information is not intended to measure the financial performance of EME
and, accordingly, should not be used in lieu of the financial information set forth in Edison International's consolidated financial
statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in EME's organizational
documents and are not the same as would be determined in accordance with generally accepted accounting principles.
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The following table sets forth the major components of the interest coverage ratio for the twelve months ended June 30, 2003 and the
year ended December 31, 2002:
June 30, December 31,
In millions 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois plants(3) $ 263 $ 294
Homer City 111 51
First Hydro 2 47
Other consolidated operating projects 153 158
Price risk management and energy trading 15 16
Distributions from non-consolidated Big 4 projects 75 137
Distributions from other non-consolidated operating projects 104 120
Interest income 6 8
Operating expenses (132) (139)
- -----------------------------------------------------------------------------------------------------------------------------------
Total funds flow from operations $ 597 $ 692
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Expense:
From obligations to unrelated third parties $ 166 $ 178
From notes payable to Midwest Generation 114 115
- -----------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 280 $ 293
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 2.13 2.36
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid and project debt service. Operating
cash flow does not include capital expenditures or the difference between cash payments under EME's long-term leases and
lease expenses recorded in the income statement. EME expects its cash payments under its long-term power plant leases to be
higher than its lease expense through 2014.
(2) Consolidated operating projects are entities of which EME owns more than a 50% interest and, thus, include the operating
results and cash flows in the consolidated financial statements. Unconsolidated operating projects are entities of which
EME owns 50% or less and which EME accounts for on the equity method.
(3) Distribution to EME of funds flow from operations of the Illinois plants is currently restricted. See "--EME's Credit
Ratings--Credit Rating of Edison Mission Midwest Holdings."
The major factors affecting funds flow from operations during the twelve months ended June 30, 2003, compared to the year ended
December 31, 2002, were:
o lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due accounts receivable
that accrued during the California energy crisis);
o higher revenue at Homer City due to increased generation and higher energy prices;
o lower earnings at First Hydro in the second quarter of 2003; and
o lower earnings at the Illinois plants' primarily due to lower capacity revenue from the reduction in MW contracted under the
power purchase agreements.
Interest expense decreased by $13 million for the twelve months ended June 30, 2003, compared to the year ended December 31, 2002 due
to a lower average debt balance.
EME's interest coverage ratio for the twelve months ended June 30, 2003 was 2.13 to 1. Accordingly, under the "ring-fencing"
provisions of EME's certificate of incorporation and bylaws, without unanimous board approval, EME is not permitted to pay dividends
in the next quarter. EME did not pay or declare any dividends to MEHC during the first six months of 2003.
Page 45
The above interest coverage ratio is not determined in accordance with generally accepted accounting principles as reflected in the
Consolidated Statements of Cash Flows. Accordingly, this ratio should not be considered in isolation or as a substitute for cash
flows from operating activities or cash flow statement data set forth in the Consolidated Statement of Cash Flows. This ratio does
not measure the liquidity or ability of EME's subsidiaries to meet their debt service obligations. Furthermore, this ratio is not
necessarily comparable to other similarly titled captions of other companies due to differences in methods of calculations.
EME's Recourse Debt to Recourse Capital Ratio
Under the credit agreement governing its credit facility, EME has agreed to maintain a recourse debt to recourse capital ratio as
shown in the table below.
Actual at
Financial Ratio Covenant June 30, 2003 Description
- -------------------------------------------------------------------------------------------------------------------------------------
Recourse Debt to Less than or 66.3% Ratio of (a) senior recourse debt to (b) sum
Recourse Capital equal to of (i) shareholder's equity per EME's
Ratio 67.5% balance sheet adjusted by comprehensive income after
December 31, 1999, plus (ii) senior recourse debt
- -------------------------------------------------------------------------------------------------------------------------------------
Discussion of Recourse Debt to Recourse Capital Ratio
The recourse debt to recourse capital ratio of EME at June 30, 2003 and December 31, 2002 was calculated as follows:
June 30, December 31,
In millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Debt(1)
Corporate Credit Facilities $ 424 $ 140
Senior Notes 1,600 1,600
Guarantee of termination value of Powerton/Joliet
operating leases 1,461 1,452
Coal and Capex Facility 186 182
Other 33 30
- ------------------------------------------------------------------------------------------------------------------------------
Total Recourse Debt to EME $ 3,704 $ 3,404
- ------------------------------------------------------------------------------------------------------------------------------
Adjusted Shareholder's Equity(2) $ 1,884 $ 2,066
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Capital(3) $ 5,588 $ 5,470
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Debt to Recourse Capital Ratio 66.3% 62.2%
- ------------------------------------------------------------------------------------------------------------------------------
(1) Recourse debt means senior direct obligations of EME or obligations related to indebtedness or rental expenses
of one of its subsidiaries for which EME has provided a guarantee.
(2) Adjusted shareholder's equity is defined as the sum of total shareholder's equity and equity preferred
securities, less changes in accumulated other comprehensive gain or loss after December 31, 1999.
(3) Recourse capital is defined as the sum of adjusted shareholder's equity and recourse debt.
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During the six months ended June 30, 2003, the recourse debt to recourse capital ratio was increased due to:
o higher borrowings on corporate lines of credit; and
o reduction in adjusted shareholder's equity as a result of $184 million net loss for the six months ended June 30, 2003.
EME's indirect subsidiary, Midwest Generation, reported an asset impairment charge of $475 million, after tax, related to the 2,698
MW gas-fired Collins Station in the second quarter of 2003. The impairment charge resulted from a write-down of the book value of
capitalized assets related to the Collins Station from $858 million to an estimated fair market value of $78 million. The impairment
charge by Midwest Generation is not reflected in the operating results of EME because the lease related to the Collins Station is
treated in EME's financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for
accounting purposes. EME is evaluating a number of debt restructuring alternatives, some of which could result in the consolidation
of the Collins Station and recognition of a loss in the consolidated accounts of Edison International, MEHC and EME. A restructuring
alternative that resulted in the consolidation of the Collins Station would require EME to obtain modifications to net worth
covenants contained in its credit facilities and the guarantee it provides to the owner participants in the Powerton and Joliet
sale-leaseback.
EME Subsidiary Financing Plans
The estimated capital and construction expenditures of EME's subsidiaries for the remaining two quarters of 2003 total $41 million.
These expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations,
except with respect to the Homer City project. Under the Homer City sale-leaseback agreements, EME has committed to provide funds
for capital expenditures needed to complete the Homer City environmental improvement project. EME expects to contribute $24 million
in 2003 to fund the completion of this project, of which $14 million was contributed during the first half of 2003.
Edison Mission Midwest Holdings
EME's wholly owned subsidiary, Edison Mission Midwest Holdings, had debt with the following maturities at June 30, 2003:
Amount
(In millions) Due Date
- ----------------------------------------------------------------------------------------------------
$ 911 December 11, 2003
808 December 15, 2004
- ----------------------------------------------------------------------------------------------------
$ 1,719
- ----------------------------------------------------------------------------------------------------
In addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused at June 30, 2003) which is scheduled
to expire on December 15, 2004. At June 30, 2003, Edison Mission Midwest Holdings had cash and cash equivalents of $201 million, as
well as $78 million deposited into a restricted cash account. Edison Mission Midwest Holdings is not expected to have sufficient
cash to repay the $911 million debt due on December 11, 2003. Edison Mission Midwest Holdings plans to extend or refinance the
$911 million debt obligation prior to its expiration in December 2003. During the second quarter, Edison Mission Midwest Holdings
commenced discussions with its lenders regarding restructuring its indebtedness. Completion of an extension or refinancing is
subject to a number of uncertainties, including the ability of the Illinois plants to generate funds during the remainder of 2003 and
the availability of new credit from financial institutions on acceptable terms in light of industry
Page 47
conditions. Accordingly, there is no assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt
when it becomes due or that the terms will not be substantially different from those under the current credit facility.
Sunrise Project Financing
EME owns a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility in Kern County, California, which EME
refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle gas-fired facility (320 MW),
was completed on June 27, 2001. Phase 2, conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 572
MW), was completed on June 1, 2003. Sunrise Power Company entered into a long-term power purchase agreement with CDWR on June 25,
2001. The agreement was amended on December 31, 2002 as part of the settlement of several matters between Sunrise Power Company and
the State of California. The construction of the Sunrise project was funded with equity contributions by its partners, including
EME. Sunrise Power Company has engaged a financial advisor to assist with obtaining project financing. Completion of project
financing is subject to a number of uncertainties, including market uncertainties. EME believes that project financing will be
completed during the next three months, although no assurance can be provided in this regard. If project financing is completed as
planned, EME estimates a distribution of approximately $150 million from the proceeds of such financing.
EME's Intercompany Tax-Allocation Payments
EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to
participate in tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison
International continuing to own, directly or indirectly, at least 80% of the voting power of the stock of EME and at least 80% of the
value of such stock. A foreclosure by MEHC's financing parties on EME's stock would make EME ineligible to participate in the
tax-allocation payments. The arrangements are subject to the terms of tax allocation and payment agreements among Edison
International, MEHC, EME and other Edison International subsidiaries. The agreements to which EME is a party may be terminated by
the immediate parent company of MEHC at any time, by notice given before the first day of the first tax year with respect to which
the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year
beginning prior to the notice. EME has historically received tax-allocation payments related to domestic net operating losses
incurred by EME. The right of EME to receive and the amount and timing of tax-allocation payments are dependent on the inclusion of
EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated
taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its
subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME
receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates
sufficient taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison
International and its subsidiaries. During the six-month period ended June 30, 2003, EME received $89 million in tax-allocation
payments from Edison International. In the future, based on the application of the factors cited above, EME may be obligated during
periods it generates taxable income to make payments under the tax-allocation agreements.
Edison Capital's Liquidity Issues
Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation payments from the parent company and
expected cash flow from operating activities. As of June 30, 2003, Edison Capital had cash and cash equivalents of $371 million and
current liabilities of approximately $31 million. To the extent that specific funding conditions are satisfied, Edison Capital has
unfunded current and long-term commitments of $96 million for both affordable housing projects, and energy and
Page 48
infrastructure investments. Under the tax-allocation agreement, Edison Capital made net payments of approximately $58 million during
the six-month period ended June 30, 2003, as Edison International amended its 2001 federal income tax return, which deferred
realization of certain tax credits to future periods. See "Financial Condition--Edison Capital's Intercompany Tax-Allocation
Payments" section in the year-ended 2002 MD&A for further discussion of the tax-allocation agreement. At June 30, 2003, Edison
Capital's long-term debt had credit ratings of B2 and B- from Moody's and Standard & Poor's, respectively.
COMMITMENTS
Edison International's long-term debt maturities and sinking-fund requirements for the five twelve-month periods following June 30,
2003 are: 2004-- $1.5 billion; 2005-- $3.1 billion; 2006-- $763 million; 2007-- $1.8 billion; and 2008-- $335 million. These
amounts have been updated to reflect SCE's $966 million exchange offer that took place on February 24, 2003.
SCE has entered into six transition-capacity contracts during 2003, which contain capacity payment provisions. SCE's commitments
under these contracts for the five twelve-month periods following June 30, 2003 are: 2004-- $68 million; 2005-- $69 million; 2006--
$69 million; 2007-- $70 million; and 2008-- $37 million.
Midwest Generation has entered into additional fuel purchase agreements with several third-party suppliers during the first six
months of 2003. Midwest Generation's aggregate fuel purchase commitments under these agreements are estimated to be: 2003-- $39
million; 2004-- $105 million; and 2005-- $107 million.
MARKET RISK EXPOSURES
Edison International's primary market risk exposures include commodity price risk, interest rate risk and foreign currency exchange
risk that could adversely affect results of operations or financial position. Commodity price risk arises from fluctuations in the
market price of electricity, natural gas, , coal, and emission and transmission rights. Interest rate risk arises from fluctuations
in interest rates and foreign currency exchange risk arises from fluctuations in exchange rates. Edison International's risk
management policy allows the use of derivative financial instruments to manage its financial exposures, but prohibits the use of
these instruments for speculative or trading purposes, except at EME's trading operations unit.
SCE's Market Risks
SCE's primary market risk exposures include interest rate risk, generating fuel, commodity price and volume risk and credit risk.
Interest Rate Risk
SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity
purposes and to fund business operations, as well as to finance capital expenditures. The nature and amount of SCE's long-term and
short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. In
addition, SCE's authorized return on common equity is set based on forecasts of interest rates and other factors.
Commodity Price and Volume Risk
Under the CPUC settlement agreement, SCE was permitted full recovery of its past procurement-related costs. During July 2003, SCE
completed recovery of these costs. Currently, SCE expects to recover its
Page 49
reasonable power procurement costs in customer rates through regulatory mechanisms established by the CPUC. Assembly Bill (AB) 57,
which the Governor of California signed in September 2002, provides that the CPUC shall adjust rates, or order refunds, to amortize
undercollections or overcollections of power procurement costs. Until January 1, 2006, the CPUC must adjust rates if the
undercollection or overcollection exceeds 5% of SCE's prior year's procurement costs, excluding revenue collected for CDWR. As a
result of these regulatory mechanisms, changes in energy prices may impact SCE's cash flows but are not expected to have an impact on
earnings.
On January 1, 2003, SCE resumed procurement of its residual net short. SCE forecasts that its average 2003 residual net short, on an
energy basis, will be approximately 4% of the total energy needed to serve SCE's customers, with most of the short position occurring
during off-peak hours and on weekends. Factors that could cause SCE's residual net short to be larger than expected include: direct
access customers returning to utility service from their energy service provider; lower utility generation; lower deliveries from
QFs, CDWR or interutility contracts; and higher load requirements.
To reduce SCE's residual net short exposure, SCE entered into six transition capacity contracts with terms of up to five years.
Through fuel tolling arrangements, SCE is responsible for providing natural gas when the underlying contract facilities are called
upon to provide energy. SCE anticipates it will need to purchase additional capacity and/or ancillary services to hedge its peak
energy requirements.
During 2004, SCE's expects its residual net short to decline and its residual net long position to increase. SCE's growing residual
net long position arises from expected increases in deliveries under CDWR contracts allocated to SCE's customers. In its 2004
procurement plan, under review by the CPUC, SCE has incorporated a price and volume forecast from expected sales of residual net long
power. If actual prices or volumes vary from forecast, SCE's cash flow would be impacted. However, sales of residual power do not
affect SCE's earnings.
Pursuant to CPUC decisions, SCE arranges for natural gas and related services for CDWR contracts allocated by the CPUC to SCE.
Financial and legal responsibility for the allocated contracts remains with CDWR. CDWR, through the coordination of SCE, has hedged
a portion of its expected natural gas requirements for certain contracts allocated to SCE. To the extent the price of natural gas
were to increase above the levels assumed for cost recovery purposes, state law permits CDWR to recover its actual costs through
rates established by the CPUC.
SCE purchases power from QFs CPUC state-mandated contracts. The contract energy price for most non-renewable QFs is tied to the
southern California border price of natural gas established on a monthly basis. During 2003, SCE substantially hedged the risk of
increasing natural gas prices. In its 2004 procurement plan, SCE has requested CPUC authority to hedge its QF natural gas price
risk. A decision on SCE's procurement plan is not expected until late 2003.
Credit Risks
Credit risk arises primarily due to the chance that a counterparty will not perform as agreed under various purchase and sale
contracts or pay SCE for energy products delivered. SCE uses a variety of techniques to mitigate its exposure to credit risk. These
include restricting unsecured exposures to highly rated entities and securing collateral from all others whenever possible. Such
collateral may take many forms including cash from the counterparty itself, payment guarantees or letters of credit from highly rated
entities, and making purchases from the counterparty which act to offset sales. SCE has established a risk management committee
which regularly reviews procurement credit exposure and approves credit limits for transacting with counterparties. Despite these
efforts, there can be no assurance that SCE's actions to mitigate credit risk will be wholly successful or that collateral pledged
will be adequate. SCE believes that any losses which may occur, despite prudent credit management practices, should be fully
Page 50
recoverable from ratepayers if SCE follows the credit limits established in its CPUC-approved procurement plan.
EME's Market Risks
This subsection discusses commodity price risk at each of EME's market areas, as well as its risks associated with credit, interest
rates, foreign exchange rates and derivative financial instruments.
EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted
generating plants. These risks arise from fluctuations in electricity and fuel prices, emission allowances, transmission rights,
interest rates and foreign currency exchange rates. EME manages these risks in part by using derivative financial instruments in
accordance with established policies and procedures. See "Current Developments" and "Financial Condition--EME's Liquidity
Issues--EME's Credit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its
counterparties.
Commodity Price Risk
EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively
monitored to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerances for each EME
regional business unit. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk
management committee. In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of
its merchant plants, the output of which is not committed to be sold under long-term contracts. When appropriate, EME manages the
spread between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those
objectives. There is no assurance that contracts to hedge changes in market prices will be effective.
EME's revenue and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy,
ancillary services, fuel oil, coal and natural gas and associated transportation costs and emission credits in the market areas where
EME's merchant plants are located. Among the factors that influence the price of power in these markets are:
o prevailing market prices for fuel oil, coal and natural gas and associated transportation costs;
o the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market
entrants, including the development of new generation facilities;
o transmission congestion in and to each market area;
o the market structure rules to be established for each market area;
o the cost of emission credits or allowances;
o the availability, reliability and operation of nuclear generating plants, where applicable, and the extended operation of
nuclear generating plants beyond their presently expected dates of decommissioning;
o weather conditions prevailing in surrounding areas from time to time; and
o the rate of electricity usage as a result of factors such as regional economic conditions and the implementation of
conservation programs.
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A discussion of each market area is set forth below.
Illinois Plants
Electric power generated at the Illinois plants has historically been sold under three power purchase agreements between EME's wholly
owned subsidiary, Midwest Generation, and Exelon Generation Company, under which Exelon Generation purchases capacity and has the
right to purchase energy generated by the Illinois plants. The agreements, which began on December 15, 1999 and expire in
December 2004, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants
under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity
payments provide the revenue for fixed charges, and the energy payments compensate the Illinois plants for all, or a portion of,
variable costs of production.
Under each of the power purchase agreements, Exelon Generation, upon notice by given dates, has the option to terminate each
agreement with respect to all or a portion of the units subject to it. As a result of notices given in 2002, effective January 1,
2003, Exelon Generation released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements, thus
increasing Midwest Generation's reliance on sales into the wholesale markets. As a result, 4,739 MW of capacity remain subject to
power purchase agreements with Exelon Generation in 2003.
Exelon Generation notified Midwest Generation on June 25, 2003 of its exercise of its option to purchase 687 MW of capacity and
energy (out of a possible total of 1,265 MW subject to the option) during 2004 from Midwest Generation's coal-fired units in
accordance with the terms of the existing power purchase agreement related to Midwest Generation's coal-fired generation units. As a
result, 578 MW of the capacity of these units will no longer be subject to the power purchase agreement beginning January 1, 2004.
The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these generating units
for the balance of 2003. For 2004, Exelon Generation will have 2,383 MW of capacity related to its coal-fired generation units under
contract with Midwest Generation.
Under the power purchase agreements related to Midwest Generation's Collins Station and peaking units, Exelon Generation continues to
have a similar option to terminate, exercisable not later than 90 days prior to January 1, 2004, the power purchase agreements for
2004 with respect to all or a portion of the 1,084 MW of capacity from the Collins Station, and 694 MW of capacity from the peaking
units, that were retained for 2003.
The energy and capacity from any units which are not subject to one of the power purchase agreements with Exelon Generation will be
sold under terms, including price and quantity, to be negotiated with customers through a combination of bilateral agreements,
forward energy sales and spot market sales. These arrangements generally have a term of two years or less. Thus, EME is subject to
market risks related to the price of energy and capacity described above. EME expects that capacity prices for merchant energy sales
will, in the near term, be negligible in comparison to those Midwest Generation currently receives under its existing agreements with
Exelon Generation (the possibility of minimal revenue is due to the current oversupply conditions in this marketplace). EME further
expects that the lower revenue resulting from this difference will be offset in part by energy prices, which EME believes will, in
the near term, be higher for merchant energy sales than those Midwest Generation currently receives under its existing agreements, as
indicated below in the table of forward-looking prices. EME intends to manage this price risk, in part, by accessing both the
wholesale customer and over-the-counter markets described below as well as using derivative financial instruments in accordance with
established policies and procedures.
During 2003, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants are
expected to be "wholesale customer" and "over-the-counter." The most liquid
Page 52
over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into Cinergy," and, to a
lesser extent, sales into the control area of Commonwealth Edison, referred to as "Into ComEd" (due to geographic proximity, "Into
ComEd" has been the primary market for Midwest Generation). "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or
purchase of electrical energy for future delivery. Performance of transactions in these markets is subject to contracts that
generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit
assessment, Midwest Generation's parent company guarantees, letters of credit and cash margining arrangements.
The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and "Into Cinergy" for the
first six months of 2003:
Into ComEd* Into Cinergy*
----------------------------------- -------------------------------------
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- -------------------------------------------------------------------------------------------------------------------------------------
January $ 42.62 $ 20.77 $ 30.81 $ 44.38 $ 21.46 $ 32.00
February 54.43 23.13 37.81 58.09 24.00 39.99
March 47.96 22.35 33.92 51.68 24.34 36.69
April 39.12 15.05 26.67 41.12 15.96 28.11
May 29.59 10.80 19.57 28.89 10.68 19.18
June 30.27 8.17 19.22 28.41 8.31 18.36
- -------------------------------------------------------------------------------------------------------------------------------------
Six Month Average $ 40.67 $ 16.71 $ 28.00 $ 42.10 $ 17.46 $ 29.06
- -------------------------------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday, excluding North
American Electric Reliability Council (NERC) holidays. All other hours of the week are referred to as off-peak.
* Source: Energy prices were determined by obtaining broker quotes and other public price sources, for both "Into
ComEd" and "Into Cinergy" delivery points.
The following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into ComEd" and "Into Cinergy"
at June 30, 2003. These forward prices will continue to fluctuate as a result of a number of factors, including gas prices,
electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. The
actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.
Into ComEd* Into Cinergy*
----------------------------------- -------------------------------------
Forward Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- -------------------------------------------------------------------------------------------------------------------------------------
2003
July $ 47.75 $ 19.50 $ 32.87 $ 44.25 $ 19.50 $ 31.21
August 48.00 21.00 33.19 46.00 21.00 32.29
September 33.38 18.50 25.44 34.00 18.50 25.73
October 32.75 17.25 24.92 33.50 18.00 25.67
November 33.25 18.25 24.58 34.00 19.00 25.33
December 34.25 19.25 26.35 35.00 20.00 27.10
2004 Calendar "strip"(2) 36.59 19.42 27.46 37.25 20.42 28.30
- -------------------------------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday, excluding NERC
holidays. All other hours of the week are referred to as off-peak.
(2) Market price for energy purchases for the entire calendar year, as quoted for sales "Into ComEd" and
"Into Cinergy."
* Source: Energy prices were determined by obtaining broker quotes and other public price sources, for both "Into
ComEd" and "Into Cinergy" delivery points.
Page 53
Midwest Generation intends to hedge a portion of its merchant portfolio risk through its marketing affiliate. To the extent it does
not do so, the unhedged portion will be subject to the risks and benefits of spot market price movements. The extent to which
Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several factors. First,
Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently
attractive compared to assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into
hedging transactions will depend upon its and its marketing affiliate's credit capacity and upon the over-the-counter forward sales
markets' having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into
hedging transactions with it. Due to factors beyond Midwest Generation's control, market liquidity decreased significantly during
2002 and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their
trading activities. See "--Credit Risks" below.
In addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the
released units will be affected by the cost of production, including costs incurred to comply with environmental regulations. The
costs of production of the released units vary and, accordingly, depending on market conditions, the amount of generation that will
be sold from the released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of
Will County Units 1 and 2 and Collins Station Units 4 and 5 at the end of 2002 pending improvement in market conditions. If market
conditions were to be depressed for an extended period of time, Midwest Generation would need to consider decommissioning Will County
Units 1 and 2, which would result in a charge against income. Collins Station Units 4 and 5 are subject to a long-term lease which
requires that for the term of the lease, these units be maintained in condition for return to service, should market conditions
improve. Thus, in the absence of an agreement with the lessor under the lease, Midwest Generation cannot decommission these units.
In addition to the price risks described previously, Midwest Generation's ability to transmit energy to counterparty delivery points
to consummate spot sales and hedging transactions may also be affected by transmission service limitations and constraints and new
standard market design proposals proposed by and currently pending before the FERC. Although the FERC and the relevant industry
participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will
be resolved. Currently, transmission must be obtained from Commonwealth Edison under its open-access tariff filed with the FERC. In
2002, Commonwealth Edison applied to the FERC for approval to join PJM in conjunction with American Electric Power, thereby creating
an enlarged, contiguous regional transmission organization encompassing a broad regional market. Approval of this application was
granted by the FERC on April 1, 2003. Concurrently, the ability of American Electric Power to join PJM has been brought into
question by the enactment of legislation in Virginia requiring the approval of Virginia state authorities for any transfer of control
from American Electric Power to PJM of American Electric Power transmission assets located in Virginia. On April 16, 2003,
Commonwealth Edison and PJM issued a joint press release stating that the integration of Commonwealth Edison into PJM would proceed
separately from that of American Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth
Edison between its service territory and the existing PJM. In response to this announcement, EME and other affected parties filed
with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested the appropriateness of
Commonwealth Edison joining PJM on an "islanded" basis. Commonwealth Edison and PJM had stated their intentions to proceed with
integration beginning June 1, 2003, and EME requested expedited treatment of its request for clarification or rehearing. The FERC
indicated in subsequent orders that it would act on the request by July 14, 2003, but has not done so. In the meantime, it clarified
that a series of pre-conditions imposed by an order issued on July 31, 2002, tentatively approving the stated decisions of
Commonwealth Edison and American Electric Power to join PJM together continue to be applicable to the separate application of
Commonwealth Edison to join PJM standing alone. Those conditions include (a) the elimination of multiple transmission rates between
PJM
Page 54
and the Midwest Independent System Operator (Midwest ISO), which controls the transmission markets surrounding the service territory
of Commonwealth Edison, and (b) an agreement between PJM and the Midwest ISO regarding the management of operations across their
"seams," which are required to be done in such a manner as to segregate utility customers of the Midwest ISO in Wisconsin and Michigan
from the adverse effects of congestion and loop flows caused by the membership of Commonwealth Edison in PJM. On July 23, 2002, the
FERC issued an order rejecting the regional wheeling rates proposed by the Midwest ISO and PJM for "through" and "out" transactions
(also known as "RTORs") for power delivered into the areas served by the Midwest ISO and PJM (the Midwest ISO/PJM footprint) and
directed them to make a compliance filing eliminating the charges in question. The FERC also set for hearing the question of whether
similar RTOR wheeling rates established by the former Alliance companies for power deliveries into the Midwest ISO/PJM footprint
should be modified. On August 1, 2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order and the June 4, 2003
order on rehearing with the U.S. Court of Appeals for the D.C. Circuit. EME is unable to predict the outcome of these efforts or the
effect of any final integration configuration on the markets into which Midwest Generation sells its power.
Homer City Facilities
Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power
marketers pursuant to transactions with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets,
which establish an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically
connected to high-voltage transmission lines serving both the PJM and NYISO markets.
The following table depicts the average market prices per megawatt-hour in PJM during the first six months of 2003 and 2002:
24-Hour PJM
Historical Energy Prices*
- ---------------------------------------------------------------------------------------------------------------
2003 2002
- ---------------------------------------------------------------------------------------------------------------
January $ 36.56 $ 20.52
February 46.13 20.62
March 46.85 24.27
April 35.35 25.68
May 32.29 21.98
June 27.26 24.98
- ---------------------------------------------------------------------------------------------------------------
Six Month Average $ 37.41 $ 23.01
- ---------------------------------------------------------------------------------------------------------------
* Energy prices were calculated at the Homer City busbar (delivery point) using historical
hourly prices provided on the PJM-ISO web-site.
As shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during the first six
months of 2003 were significantly higher than the average historical market prices during the first six months of 2002. Forward
market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in
market rules, electricity demand which is affected by weather and economic growth, and the amount of existing and planned power plant
capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.
Sales made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In order to mitigate price
risk from changes in spot prices at the Homer City busbar, EME may enter into forward contracts with counterparties for forecasted
generation in future periods. Currently, there is not a liquid market for entering into forward contracts at the Homer City busbar.
A liquid market does exist
Page 55
for delivery to a collection of delivery points known as PJM West Hub, which EME's price risk management activities use to enter into
forward contracts. EME's revenue with respect to such forward contracts includes:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot prices at the Homer
City busbar, plus or minus,
o sales to third parties under such forward contracts at designated delivery points (generally the PJM West Hub) less the cost
of purchasing power at spot prices at the same designated delivery points to fulfill obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of raising prices at those
delivery points affected by transmission congestion. During the past 12 months, an increase in transmission congestion at delivery
points east of the Homer City facilities has resulted in prices at the PJM West Hub (which includes delivery points east of the Homer
City facilities) being higher than those at the Homer City busbar. Thus, while forward prices at PJM West Hub have historically been
higher than the prices at the Homer City busbar by less than 5%, increased congestion during the last 12 months at delivery points
east of the Homer City facilities has resulted in prices at PJM West Hub being on average 10% higher than those at the Homer City
busbar.
By entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk," which occurs when
forward contracts are executed on a different basis (in this case PJM West Hub) than the actual point of delivery (Homer City
busbar). In order to mitigate basis risk resulting from forward contracts using PJM West Hub as the delivery point, EME has
participated in purchasing firm transmission rights in PJM, and may continue to do so in the future. A firm transmission right
provides the holder with a financial instrument to receive actual spot prices at one point of delivery and pay spot prices at another
point of delivery. Accordingly, EME's price risk management activities include using firm transmission rights alone or in
combination with forward contracts to manage the risks associated with changes in prices within the PJM market.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at
June 30, 2003:
24-Hour PJM West
Forward Energy Prices*
- ---------------------------------------------------------------------------------------------------------------
July 2003 $ 44.17
August 2003 45.90
September 2003 36.18
October 2003 34.17
November 2003 33.12
December 2003 34.57
2004 Calendar "strip"(1) 34.34
- ---------------------------------------------------------------------------------------------------------------
(1) Market price for energy purchases for the entire calendar year, as quoted for sales
into the PJM West Hub.
* Energy prices were determined by obtaining broker quotes and other public sources for
the PJM West Hub delivery point. Forward prices at PJM West are generally higher
than the prices at the Homer City busbar.
The ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the
sale-leaseback transaction discussed under "Off-Balance Sheet Transactions--EME's Off-Balance Sheet Transactions--Sale-Leaseback
Transactions," in the year-ended 2002 MD&A,
Page 56
depends on revenue generated by the Homer City facilities, which depend in part on the market conditions for the sale of capacity and
energy. These market conditions are beyond EME's control.
New Zealand
Contact Energy generates about 30% of New Zealand's electricity and is the largest retailer of natural gas and electricity in New
Zealand. A substantial portion of Contact Energy's generation output is matched with the demand of its retail electricity customers
or sold through forward contracts with other wholesale electricity counterparties. The forward contracts and/or option contracts
have varying terms that expire on various dates through June 30, 2010, although the majority of the forward contracts expire in less
than two years.
The New Zealand government released a government policy statement in December 2001, which called for the industry to rationalize the
three existing industry codes, form a single governance structure and address transmission investment and pricing issues. An
amendment to New Zealand's Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry did
not heed the government's call.
Throughout 2002, the industry developed a proposed rulebook with the aim of meeting the New Zealand government's call for
rationalization. The adoption of the rulebook required a two-thirds majority vote from each industry sector (i.e., wholesale,
networks, and end users). The vote was held in April/May of 2003 and failed to meet the prescribed majorities for introduction.
Subsequently, the New Zealand government has stepped in and is proceeding to establish a new governance body to be known as the
Electricity Commission along with a set of rules to govern the market. The rules are expected to be largely based on the rule book
developed by the industry.
While the industry governance arrangements were developing, several events in the months preceding the winter of 2003 in New Zealand
led to concerns about the security of supply in the country. Wholesale electricity prices increased significantly in response to
lower hydro inflows, higher demand, and anticipated restrictions on the availability of thermal fuel. The New Zealand government
responded by calling for nationwide energy savings in the order of 10%. Heavy rains in June and July have lessened the short-term
concerns about supply security, and the savings program has now ended.
However, there are ongoing concerns that new investment in generation has not been forthcoming and that there is a significant risk
that similar events may arise in subsequent years. In March 2003, the New Zealand government's initial response to the concerns was
to notify the industry that significant changes may be required to the electricity market to avoid the risk of insufficient supply in
the future.
Further, on May 20, 2003, the New Zealand government announced a policy statement confirming that substantial changes would be made
to the electricity market. The main elements were:
o confirmation that an Electricity Commission would be established by legislation to be the new governance body for the
industry;
o the Electricity Commission would be given responsibility for managing dry-year reserve, expected to be through the
procurement of reserve capacity; and
o the Electricity Commission would be given additional reserve powers ranging from information disclosure to imposing hedge
obligations on major users and generators.
Submissions have been made in respect of the policy, which are currently being considered by the New Zealand government. Final
details of the policy are currently expected to be developed in the latter half of 2003, and it is expected that legislation will be
passed by early 2004.
Page 57
Credit Risks
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and
financial institutions. Due to factors beyond EME's control, market liquidity has decreased significantly since the beginning of
2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their
trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the
decrease in market liquidity may require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which
may also increase EME's credit risk. While various industry groups and regulatory agencies have taken steps to address market
liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market
confidence. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss
associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting
liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products
delivered prior to the time such counterparty defaulted.
To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME
would record if its counterparties failed to perform pursuant to the terms of their contractual obligations. EME has established
controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to
mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to
manage the credit in its portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed
information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit
levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is
reviewed regularly by EME's risk management committee. In addition to continuously monitoring its credit exposure to its
counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that
EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) generally 60 days of
accounts receivable, (ii) current fair value of open positions; and (iii) a credit value at risk. EME's subsidiaries enter into
master agreements and other arrangements in conducting price risk management and trading activities which typically provide for a
right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from
counterparties is based on net exposure under these agreements. The credit ratings supporting the credit risk exposure from
counterparties of merchant energy activities were as follows:
In millions June 30, 2003
- -------------------------------------------------------------------------------------------------------------
S&P Credit Rating:
A or higher $ 61
A- 14
BBB+ 64
BBB 51
BBB- 6
Below investment grade 6
- -------------------------------------------------------------------------------------------------------------
Total $ 202
- -------------------------------------------------------------------------------------------------------------
Exelon Generation accounted for 21% and 36% of nonutility power generation revenue for the first half of 2003 and 2002, respectively.
The percentage is less in 2003 because a smaller number of plants are subject to contracts with Exelon Generation. See "--Commodity
Price Risk--Illinois Plants." Any
Page 58
failure of Exelon Generation to make payments to Midwest Generation under the power purchase agreements could result in a shortfall
of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its obligations could
in turn have a material adverse effect on EME.
EME's contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest sell power under
long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a
counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would likely have a
material adverse affect on the operations of such power plant.
Edison Capital's Market Risks
Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance risk that could
adversely affect its results of operations or financial position.
Credit and Performance Risk
Edison Capital has leased three aircraft to American Airlines. American Airlines is reporting significant operating losses. If
American 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 2003 is $48 million. A voluntary restructure of the lease could also result in a loss of some or
all of the investment. At June 30, 2003, American Airlines was current in its lease payments to Edison Capital.
SCE'S REGULATORY MATTERS
This section of MD&A presents updates to SCE's regulatory matters using three main subsections: generation and power procurement,
transmission and distribution, and other regulatory matters.
Generation and Power Procurement
CPUC Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that SCE is entitled to
full recovery of its past procurement-related costs. A key element of the settlement agreement was the establishment of a $3.6
billion regulatory balancing account called the PROACT as of August 31, 2001. Other provisions of the settlement agreement are
described in the "CPUC Litigation Settlement Agreement" disclosure in the year-ended 2002 MD&A. TURN, a consumer advocacy group, and
other parties appealed to the federal court of appeals seeking to overturn the stipulated judgment of the district court that
approved the settlement agreement. On March 4, 2002, the United States Court of Appeals for the Ninth Circuit heard argument on the
appeal, and on September 23, 2002 the court issued its opinion. In its opinion, the federal court of appeals affirmed the district
court on all claims, with the exception of the challenges founded upon California state law, which the appeals court referred to the
California Supreme Court. In sum, the appeals court concluded that none of the substantive arguments based on federal statutory or
constitutional law compelled reversal of the district court's approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement agreement violated state
law, both in substance and in the procedure by which the CPUC agreed to it. The appeals court added that if the settlement agreement
violated state law, the CPUC lacked capacity to consent to the stipulated judgment, and the stipulated judgment would need to be
vacated. The appeals court indicated that, on a substantive level, the stipulated judgment appears to violate California's
Page 59
electric industry restructuring statute providing for a rate freeze. The appeals court also indicated that, on a procedural level,
the stipulated judgment appears to violate California laws requiring open meetings and public hearings. Because federal courts are
bound by the pronouncements of the state's highest court on applicable state law, and because the federal appeals court found no
controlling precedents from California courts on the issues of state law in this case, the appeals court issued a separate order
certifying those issues in question form to the California Supreme Court and requested that the California Supreme Court accept
certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had requested, and set a
briefing schedule. After the completion of the filing of briefs by the respective parties, including supplemental briefs at the
request of the California Supreme Court about an issue related to California's open meeting laws, the parties made oral arguments
before the California Supreme Court at a hearing on May 27, 2003. SCE expects the California Supreme Court to issue its decision on
the certified questions of state law by August 25, 2003. Once the California Supreme Court issues its decision on the certified
questions, the matter will return to the Ninth Circuit for final disposition. In the meantime, the case is stayed in the federal
appellate court. SCE continues to operate under the settlement agreement. SCE continues to believe it is probable that SCE's
ultimate recovery of its past procurement costs through regulatory mechanisms, including the PROACT, will be validated. However, SCE
cannot predict with certainty the outcome of the pending legal proceedings.
PROACT Regulatory Asset
In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, in the fourth quarter of 2001, SCE
established the PROACT regulatory balancing account, with an initial balance of approximately $3.6 billion reflecting the net amount
of past procurement-related liabilities to be recovered by SCE. Each month, SCE applied to the PROACT the positive or negative
difference between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC
to recover in retail electric rates. The balance in the PROACT regulatory balancing account was $574 million at December 31, 2002
and $84 million at June 30, 2003. At July 31, 2003, the PROACT regulatory balancing account was overcollected by $148 million.
Under a settlement described in the "--Customer Rate-Reduction Plan," on July 15, 2003, SCE filed with the CPUC to inform it of the
forecast recovery of the PROACT balance in July 2003, to implement post-PROACT rate levels and rate-making mechanisms effective
August 1, 2003, and to transfer the PROACT overcollection to a new energy resource recovery account (ERRA) regulatory balancing
account on August 1, 2003. No other party filed protests to SCE's filing within the required time and SCE expects approval of its
filing by the CPUC.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order signed by the governor, CDWR began making emergency power purchases for SCE's customers on
January 17, 2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by CDWR are remitted
directly to CDWR and are not recognized as revenue by SCE. In February 2001, AB 1X (First Extraordinary Session, AB 1X) was enacted
into law. AB 1X authorized CDWR to enter into contracts to purchase electric power and sell power at cost directly to SCE's retail
customers, and authorized CDWR to issue bonds to finance electricity purchases. In addition, the CPUC is responsible for allocating
CDWR's revenue requirement among the customers of SCE, PG&E and SDG&E.
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2002 MD&A, the CPUC
allocated to SCE's customers: $3.5 billion of total power procurement revenue requirement of $9 billion for 2001 and 2002; $331
million of the 2003 bond charge revenue requirement of $745 million; and approximately $1.9 billion of the total 2003 power
Page 60
procurement revenue requirement of $4.3 billion. On July 1, 2003, CDWR submitted the supplemental determination of its 2003 power
procurement revenue requirement to the CPUC, reducing that revenue requirement by $1 billion, to $3.3 billion. SCE's customers'
share of this reduction is approximately $420 million if it is allocated by the CPUC in the same proportion that CDWR's original 2003
power procurement revenue requirement was allocated to them. SCE has requested that this $420 million be retained by CDWR or,
alternatively, used by SCE to partially offset an anticipated increase in CDWR's 2004 power charge to SCE's customers. In September
2003, the CPUC is expected to issue a decision allocating the supplemental determination among the investor-owned utilities.
In July 2003, CDWR released its proposed revenue requirement for 2004 that, if adopted, would establish a total power procurement
revenue requirement of $5.47 billion statewide, which includes a power charge of $4.65 billion and a bond charge of $820 million.
Comments on the proposed 2004 revenue requirement are due on August 14, 2003. Once CDWR adopts the 2004 revenue requirement, it will
be submitted to the CPUC, which will allocate the revenue requirement among the investor-owned utilities. Any increase or decrease
in CDWR's bond and power charges will be directly passed through to SCE's customers. The CPUC has not yet ruled on issues relating
to the true-up of CDWR's 2001-2002 revenue requirement and the allocation to each utility.
Direct Access Proceedings
Direct Access - Historical Procurement Charge
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an energy service provider
other than SCE (thus becoming direct access customers) or continue to purchase power from SCE (customers who continue to purchase
power from SCE are referred to as bundled service customers). On March 21, 2002, in accordance with existing legislation directing
the CPUC to select a date for the suspension of the right of customers to purchase power from other energy service providers, the
CPUC issued a final decision affirming that new direct access arrangements entered into by SCE's customers after September 20, 2001
are invalid. This decision did not affect direct access arrangements in place before that date. Direct access customers receive a
credit for the generation costs SCE saves by not serving them. Electric utility revenue is reported net of this credit. Because of
this credit, direct access power purchases resulted in additional undercollected power procurement costs to SCE during 2000 and
2001. On July 17, 2002, the CPUC issued an interim decision to establish a nonbypassable historical procurement charge requiring
direct access customers to pay $391 million of SCE's past power procurement costs. In a recent proposed decision, a CPUC
administrative law judge (ALJ) approved a petition for modification of the interim decision filed by SCE raising direct access
customers' responsibility to $473 million. The CPUC could adopt or reject this proposed decision in its final opinion. Several
parties filed petitions for review of the interim decision with the California Supreme Court. SCE has filed responses to the
petitions, but cannot predict with certainty the outcome of the petitions before the California Supreme Court.
The historical procurement charge was initially set at 2.7(cent)per kWh, effective July 27, 2002. Subsequently, the CPUC implemented an
order establishing a surcharge for direct access customers' share of CDWR's costs, as discussed in the paragraph below. Once that
surcharge was implemented on January 1, 2003, the contribution by direct access customers to the historical procurement charge was
reduced from 2.7(cent)per kWh to 1(cent)per kWh for the collection of the $391 million, with the remainder of the 2.7(cent)per kWh utilized for
CDWR's costs associated with direct access customers. Historical procurement charges recovered from direct access customers are used
to reduce SCE's generation rates to bundled service customers and have no impact on SCE's earnings.
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Direct Access - Exit Fees
On November 7, 2002, the CPUC issued a decision assigning responsibility for a portion of energy crisis related costs to direct
access customers. The first category consists of CDWR's power procurement costs incurred between January 17, 2001 and September 30,
2001. CDWR sold approximately $11 billion in bonds in fourth quarter 2002 to finance a portion of the costs incurred during the
California energy crisis. The CPUC decision stated that direct access customers were responsible for paying a portion of CDWR bond
charge to recover the principal and financing costs associated with these bonds. The second category relates to CDWR's power
procurement costs for the fourth quarter of 2001 and the year 2002. The CPUC stated that direct access customers must pay a share of
these costs to make bundled service customers indifferent to suspension by the CPUC of the direct access program on September 20,
2001. The third category includes CDWR long-term contract costs for 2003 and beyond. The CPUC decision stated that a portion of
these costs must be paid by direct access customers to keep bundled service customers indifferent to the later suspension of direct
access on the premise that CDWR signed some of its long-term contracts with the expectation of serving the load that switched to
direct access after July 1, 2001. Finally, the last category relates to the above-market costs of SCE's utility retained generation
(e.g., QFs contract costs) that in accordance with AB 1890 are to be recovered from all customers on an ongoing basis. The CPUC
decision stated that: (1) the bond charge is applicable to all direct access customers except those who were continuously on direct
access and never used any CDWR power (less than 1% of SCE's load); (2) the next two categories of costs are applicable to direct
access customers who took bundled service at any time after February 1, 2001; and (3) the last category is applicable to all direct
access customers, including continuous direct access customers.
On July 10, 2003, the CPUC issued a decision establishing a 2.7(cent)per kWh cap on the amount of exit fees to be paid by direct access
customers. The exact amount of exit fees to be paid by direct access customers will be determined on an annual basis after CDWR
submits its requested revenue requirement to the CPUC. On July 10, 2003, the CPUC ordered the imposition of exit fees (the Cost
Responsibility Surcharges, or CRS) on so-called "Municipal Departing Load," consumers who depart investor-owned utility service in
favor of taking service from a publicly-owned utility. That decision states that consumers switching to municipal service after
February 1, 2001 will be responsible for paying CRS fees. The exact amount of the CRS obligation to be paid by direct access
customers will be determined by the end of 2003. Certain other parties have filed applications for rehearing of this decision. See
"--CDWR Power Purchases and Revenue Requirement Proceedings" for further discussion.
On April 3, 2003, in a separate decision, the CPUC adopted similar exit fees for customers who install onsite generation facilities
or arrange to purchase power from another entity that installs generation facilities on or adjacent to their property. In its
decision, the CPUC established three categories of customer generation. Each category has varying exit fee responsibilities ranging
from full exemption from the exit fees to full obligation for all exit fees provided that the amount of customer generation installed
statewide does not exceed CDWR's forecast of customer generation it used when negotiating the long-term power contracts. The CPUC
set an absolute cap of 3,000 MW on eligible customer generation departing load through the life of CDWR's long-term contracts. On
April 17, 2003, SCE filed proposed tariff changes necessary to comply with the April 3, 2003 decision. The CPUC has not yet approved
the utilities' tariffs implementing the customer generation departing load exit fees.
Direct Access - Switching Exemptions
On May 8, 2003, the CPUC issued a decision establishing an exception to its March 21, 2002 decision (as discussed in "--Historical
Procurement Charge" section above) prohibiting new direct access arrangements after September 20, 2001. This exception, referred to
as the "switching exemptions," permits direct access customers with a pre-September 20, 2001 contract with an energy service provider
to switch back and forth between bundled service and direct access. In its May 8, 2003 decision, the CPUC adopted three specific
exemptions:
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o A "grandfathering" exemption that permits customers with pre-September 20, 2001 direct access contracts who have already
returned to bundled utility service subsequent to September 20, 2001 to return to direct access during a 45-day transition period;
o A "safe harbor" exemption, under which direct access customers may return to bundled service on a transitional basis while
switching energy service providers. While in the safe harbor, these customers must pay all incremental short-term power costs
incurred on their behalf and the applicable direct access exit fees; and
o A third exemption allows direct access customers who have returned to bundled service for a minimum three-year period to
thereafter depart again to acquire direct access service.
Direct access customers returning to bundled service for other than transition purposes must provide a six-month advance notice and
remain on bundled service for a minimum term of three years. Similarly, if a customer intends to return to direct access after
satisfying its three-year minimum stay on bundled service, it must provide six-months advance notice. Direct access customers
returning to bundled service remain responsible for their share of direct access exit fees.
On June 23, 2003, SCE filed proposed tariff changes necessary to comply with the May 8, 2003 decision. Direct access customers will
continue to operate under current direct access provisions until the CPUC approves the tariff changes, which is anticipated to occur
in November 2003.
On July 9, 2003, SCE filed a petition with the California Supreme Court contending that the CPUC's May 8, 2003 decision is
inconsistent with the state law which suspended the right of retail customers to acquire direct access after the CPUC-determined date
for suspension (September 20, 2001). TURN has also filed a petition with the California Supreme Court, raising similar arguments.
Temporary Surcharge
As discussed in the "Surcharge Decisions" disclosure in the year-ended 2002 MD&A, the CPUC allowed a continuation of a 0.6(cent)-per-kWh
temporary surcharge that was scheduled to terminate in June 2002 and required SCE to track the associated revenue in a balancing
account for rate-making purposes, until the CPUC determined the use of the surcharge. A December 17, 2002 CPUC decision authorized
SCE to use the revenue associated with the surcharge to partially offset its higher 2003 revenue requirement. For financial
reporting purposes, $187 million of surcharge revenue billed in the last six months of 2002, was credited to a regulatory liability
account until it could be used to offset SCE's higher 2003 procurement revenue requirement. This account was partially amortized
into revenue through July 31, 2003, with the remaining balance of $37 million transferred to the ERRA balancing account as of
August 1, 2003.
Hedging Cost Recovery Decision
Pursuant to its authority mentioned in "--CPUC Litigation Settlement Agreement," SCE purchased $209 million in hedging instruments
(gas call options) in late 2001 to hedge a majority of its natural gas price exposure associated with QF contracts for 2002 and
2003. A February 13, 2003 CPUC decision allowed SCE to transfer the entire $209 million into the PROACT regulatory asset during
first quarter 2003.
Generation Procurement Proceedings
The CPUC's Order Instituting Rulemaking, issued in October 2001, establishes the policies and mechanisms necessary for SCE and the
other major California electric utilities to resume power procurement as of January 1, 2003. In 2002, the CPUC issued four
decisions: (1) on August 22, 2002,
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regarding transitional procurement contracts; (2) on September 19, 2002, regarding the allocation of contracts previously entered
into by CDWR among the three major California utilities; (3) on October 24, 2002, for the resumption of power procurement activities
by these utilities on January 1, 2003, and adoption of a regulatory framework for such activities which includes establishment of the
ERRA regulatory balancing account to track fuel and purchased power authorized revenue requirements against actual costs; and (4) on
December 19, 2002, concerning SCE's short-term procurement plan for 2003. See the "SCE's Regulatory Matters--Generation Procurement
Proceedings" in the year-ended 2002 MD&A for detailed discussion of these matters. The CPUC recently issued five decisions on
numerous applications for rehearing and petitions for modifications filed on those decisions. The five decisions clarify some of the
guidelines for procuring power and provide mechanisms for a more objective determination of the reasonableness of procurement costs
for transactions outside an approved procurement plan, including the establishment of a precise amount ($37 million) on the annual
maximum disallowance risk exposure for contract administration and least cost dispatch.
California law and CPUC decisions provide for SCE to recover its reasonably incurred power procurement costs in customer rates. A
California statute adopted in 2002 allows SCE to recover reasonable procurement costs recovered in compliance with an approved
procurement plan. As discussed above, the CPUC determined that SCE's maximum disallowance risk exposure for contract administration,
including administration of allocated CDWR contracts, and least cost dispatch is $37 million. Power purchases and sales not in
compliance with the approved procurement plan are subject to an expedited reasonableness review, and are not included in the
disallowance cap of $37 million.
On December 24, 2002 and January 14, 2003, SCE filed advice letters seeking CPUC approval of six renewable contracts provisionally
entered into by SCE pursuant to the August 22, 2002 decision on transitional procurement contracts. The CPUC approved five of the
six contracts. The sixth contract, which has not yet been approved, will automatically terminate unless the time for obtaining CPUC
approval is extended.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its long-term resource plan on April 15, 2003. SCE's long-term
resource plan included both a preferred plan and an interim plan. The preferred plan contains long-term commitments that will
encourage investment in new generation and transmission infrastructure, increase long-term reliability and decrease price
volatility. These commitments include:
o a significant increase in cost-effective energy efficiency and demand-response investments;
o renewable contracts that will meet or exceed the requirements of the Renewable Portfolio Standard (RPS), (see below);
o a substantial increment of new utility and third-party owned generation resources; and
o at least two new major transmission projects that will provide the state of California access to a diverse set of generating
resources and help facilitate a more competitive wholesale market.
The interim plan, by contrast, relies exclusively on new short- and medium-term contracts with no long-term resource commitments
(except for new renewable contracts). In its CPUC filing, SCE maintained that implementation of its preferred plan requires
resolution of various issues including: (1) stabilizing SCE's customer base; (2) restoring SCE's investment-grade creditworthiness;
(3) restructuring regulations regarding energy efficiency and demand-response programs; (4) removing barriers to transmission
development; (5) modifying prior decisions, which impede long-term
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procurement; and (6) adopting a commercially realistic cost-recovery framework that will enable utilities to obtain financing and
enable contracting for new generation.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its short-term resource plan on May 15, 2003. The purpose of the
short-term resource plan is to set defined boundaries for per se reasonable transactions. It incorporates elements required by
recent California legislation and CPUC decisions. The short-term plan is designed so that the following types of transactions are
deemed reasonable:
o procurement of electrical energy to meet a residual net short requirement;
o sales of surplus electrical energy to eliminate any residual net long position;
o procurement of additional electrical capacity to meet the combination of SCE's peak-bundled load plus the ISO's requirement
for ancillary services;
o gas procurement for non-QFs generating resources under contract to SCE (including gas procurement for new tolling contracts
that are needed, but have yet to be obtained);
o transactions to hedge the risk of energy payments to QFs which are tied to the price of natural gas;
o procurement of services, such as electric transmission, gas transportation, and gas-storage services, which are required to
support the foregoing transactions; and
o any other energy sales transactions that become necessary when surplus conditions arise.
Hearings on the short-term plan and certain key issues in the long-term plan commenced on July 21, 2003. A decision is expected
before the end of the year.
Procurement of Renewable Resources
As described in the year-ended 2002 MD&A, Senate Bill (SB) 1078 was signed into law in September 2002 and provides for SCE and other
California utilities to increase their procurement of renewable resources. Pursuant to a ruling of the CPUC's assigned ALJ, issues
related to implementation of RPS issues in SB 1078 are being determined on a separate, expedited schedule. Testimony on the
implementation of SB 1078 was filed and hearings were held in April 2003. On June 23, 2003, the CPUC issued its preliminary decision
on RPS issues. The decision addressed implementation of various facets of SB 1078, including preliminary rules for adopting a market
price of electricity, against which bids in solicitations for renewable power are to be judged; preliminary criteria for the rank
ordering and selection of "least-cost" and "best-fit" renewable resources; preliminary rules for "flexible compliance" with RPS
procurement targets, and the adoption of standard terms and conditions for contracts to be entered into as part of the RPS process.
The preliminary decision provides that the parties will initially be given an opportunity, through workshops to be arranged by the
CPUC and California Energy Commission staff to agree on standard contract terms. With respect to compliance with procurement
targets, the CPUC preliminarily determined that up-front, automatic penalties in the amount of 5(cent)per kWh for every kWh that falls
below each utility's annual targets (subject to exceptions set forth in the decision), with an annual penalty cap of $25 million,
would be assessed against utilities that fail to comply with procurement targets. The decision provides that noncreditworthy
utilities are exempt from procurement, but that procurement targets for such entities will nevertheless accrue during periods of
noncreditworthiness and must be achieved, subject to the flexible compliance rules, if and when the utility becomes creditworthy.
The decision contemplates additional proceedings in which the preliminary RPS implementation rules will be further developed. On
July 23, 2003, SCE applied for
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rehearing of the CPUC's June 23, 2003 decision, on the grounds, among others, that the imposition of up-front, automatic penalties is
contrary to legislative intent and deprives SCE of due process, that the CPUC violated the RPS statute and federal law in
establishing a capacity price for non-firm products and that the CPUC proposed methodology for determining the market price of
electricity effectively excludes broker quotes and other recognized sources of market price information. If, within sixty days, the
CPUC either denies or fails to act on the application, SCE can seek review of the underlying decision in the California Court of
Appeal.
CDWR Contracts
On December 19, 2002, the CPUC adopted an operating order under which SCE, PG&E and SDG&E perform the operational, dispatch, and
administrative functions for CDWR's long-term power purchase contracts, beginning January 1, 2003. The operating order sets forth
the terms and conditions under which the three utility companies administer CDWR contracts and requires the utility companies to
dispatch all the generating assets within their portfolios on a least-cost basis for the benefit of their ratepayers. PG&E and SDG&E
filed an emergency motion in which they sought to substitute their negotiated operating agreements with CDWR for the CPUC's operating
order. In March 2003, the CPUC approved the negotiated operating agreements with CDWR submitted by PG&E and SDG&E, subject to
certain modifications. Those modifications included eliminating provisions which would permit termination of the agreements by the
utilities, a provision which would permit additional guidance from CDWR as to the performance of the utilities' obligations, a
provision which would permit the direct collection from CDWR of fees for administering CDWR contracts and certain other provisions
that permit CDWR to direct the actions of the utilities under the contracts. The decision also required SCE, PG&E and SDG&E to file
gas supply plans for the purchase of natural gas for CDWR contracts allocated to the utilities by April 17, 2003, and subsequent
plans every six months thereafter for the term of the operating order. SCE's gas supply plan was filed on April 18, 2003.
The CPUC also approved amendments to the servicing agreements between the utilities and CDWR relating to transmission, distribution,
billing, and collection services for CDWR's purchased power. The servicing order issued by the CPUC identifies the formulas and
mechanisms to be used by SCE to remit to CDWR the revenue collected from SCE's customers for their use of energy from CDWR contracts
that have been allocated to SCE.
Mohave Generating Station Proceeding
As discussed in the "Mohave Generating Station Proceeding" disclosure in the year-ended 2002 MD&A, on May 17, 2002, SCE filed with
the CPUC an application to address certain issues (mainly coal and slurry-water supply issues) facing the future extended operation
of Mohave. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from starting to make
approximately $1.1 billion (SCE's share is $605 million) of Mohave-related investments if Mohave's operations are to be extended past
2005. The CPUC issued a ruling on January 7, 2003 requesting further written testimony on specified issues related to Mohave and its
coal and slurry-water supply issues to determine whether it is in the public interest to extend Mohave operations post 2005. SCE
submitted supplemental testimony on January 30, 2003 stating, among other things, that the currently available information is not
sufficient for the CPUC to make such a determination at this time.
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in the proceeding,
most recently on July 1, 2003. The Navajo Nation and Hopi Tribe and the coal mining company, Peabody Western Coal Company, currently
take the position that the CPUC should, among other things, require SCE to fund a study of a possible alternative water supply, and
require SCE to commence a CPUC proceeding for authorization of the Mohave pollution controls and other plant investments. Certain
other parties have taken the position that SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. To date there
has been no substantive decision by the CPUC, and it
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is possible that further written filings or hearings will be required. Negotiations also have continued among the relevant parties
in an effort to resolve the coal and water supply issues, so far without any resolution.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its formal application for the 2003 General Rate Case (GRC), requesting an increase of $286 million over
currently authorized revenue. The requested revenue increase is primarily related to capital additions, updated depreciation costs
and projected increases in pension and benefit expenses. In October 2002, the CPUC's Office of Ratepayer Advocates issued its
testimony and recommended a $172 million decrease in SCE's current base rates, some $458 million below SCE's GRC request. Several
other intervenors have also proposed further reductions to SCE's request or have made other substantive proposals regarding SCE's
operations. Evidentiary hearings were concluded in March 2003, and opening briefs and reply briefs have been filed. During the
course of this GRC, SCE has agreed to a series of revisions to its request that would reduce its GRC increase to $251 million, if
authorized by the CPUC. SCE's 2004 request is an increase of $137 million over the 2003 GRC request; however, it results in an
overall non-fuel revenue reduction of $54 million, primarily due to the expiration of the eight-year San Onofre incremental cost
incentive pricing mechanism and the return of its incremental costs to conventional cost-of-service rate-making on January 1, 2004.
SCE's GRC filing also requests an $85 million increase in revenue in 2005. The expiration of the incremental cost incentive pricing
mechanism on December 31, 2003, is expected to decrease SCE's 2004 earnings by approximately $100 million. A final decision on Phase
1 issues is expected in the fourth quarter of 2003.
After SCE filed its application, the CPUC's Office of Ratepayer Advocates requested and was granted a three-month extension to submit
its testimony. This had the effect of deferring the other procedural milestones by three months, including the expected date for a
final decision. In response to the extension of the proceeding schedule, SCE filed a motion requesting authorization to establish an
account tracking SCE's requested revenue requirement during the period between May 22, 2003 (the date a final decision would have
been rendered under the CPUC's Rate Case Plan) and the date a final decision is adopted. The amounts tracked in the memorandum
account would be subject to recovery or refund depending on the final outcome of the proceeding. On May 22, 2003, the CPUC approved
SCE's request to establish a memorandum account; accordingly the final revenue requirement approved in the final decision will be
effective May 22, 2003.
Phase 2 of the GRC proceeding will address revenue allocation and rate design issues. Hearings on this phase are scheduled to begin
in October 2003.
As part of the response to the September 11, 2001 terrorist attacks, on April 29, 2003, the Nuclear Regulatory Commission issued
further orders applicable to all commercial nuclear plant operators (including SCE's San Onofre) regarding security Design Basis
Threat (DBT), work hour rules for security personnel and training and fitness requirements for security personnel. SCE estimates
additional capital expenditures of approximately $50 million to meet the revised DBT requirements. Because most of these
expenditures fall outside test year 2003, but will be incurred during the three-year GRC cycle, on July 15, 2003, SCE requested that
the CPUC open a third phase of the GRC to consider SCE's request to track these nuclear-related costs in a memorandum account
effective January 1, 2004, for future cost recovery in 2005.
Cost of Capital Filing
SCE's annual cost of capital applications with the CPUC are required to be filed by May 8 of each year, with decisions rendered in
such proceedings becoming effective January 1 of the following year. On
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April 1, 2003, SCE filed a petition with the CPUC seeking to eliminate the 2004 proceeding. This would result in SCE's 2003 cost of
capital decision, issued on November 7, 2002, remaining in effect throughout 2004. The CPUC has granted a temporary extension of
SCE's filing deadline to September 8, 2003 while it considers SCE's request. On April 24, 2003, the CPUC's Office of Ratepayer
Advocates filed a response to SCE's petition supporting SCE's request for eliminating the 2004 proceeding. The CPUC has issued two
draft decisions on this matter. One decision would approve SCE's request to defer the 2004 cost of capital proceeding and maintain
its return on equity at its current 11.6% level. The other would deny SCE's petition and order it to file an application to set its
2004 cost of capital. A final CPUC decision on this matter is expected in the third quarter of 2003.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground electric line
maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection and Safety Division (CPSD), which
alleged a pattern of noncompliance with the CPUC's general orders for the maintenance of electric lines over the period 1998-2000.
The order also alleged that noncompliant conditions were involved in 37 accidents resulting in death, serious injury or property
damage. The CPSD identified 4,817 alleged violations of the general orders during the three-year period; and the order put SCE on
notice that it could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief on
October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC ALJ issued a presiding officer's decision (POD) fining SCE $576,000 for alleged violations involving death,
injury or property damage, failure to identify unsafe conditions or exceeding required inspection intervals. The POD imposes no
fines for over 98% of the alleged violations and does not find that any of the alleged violations compromised the integrity or safety
of SCE's electric system or were excessive compared to other utilities. The POD orders SCE to consult with the CPSD and refine SCE's
maintenance priority system consistent with the discussion in the POD. On July 21, 2003, SCE filed an appeal opposing the POD's
interpretation that all general order non-conformances are violations subject to potential penalty. The CPSD also filed an appeal,
challenging the fact that the POD did not, in fact, penalize SCE for the 4,721 violations alleged by CPSD in the OII. SCE, PG&E,
SDG&E and the California Cable and Telecommunications Association filed responses challenging the CPSD's appeal. The CPSD filed a
response objecting to the intervention and appeals of PG&E, SDG&E and the California Cable and Telecommunications Association.
Transmission Rate Case
In July 2000, the FERC issued a decision in SCE's 1998 transmission rate case in which it ordered a reduction of approximately $38
million to SCE's requested annual transmission revenue requirement of $213 million. Approximately $24 million of the ordered
reduction was associated with the FERC's rejection of SCE's proposed method for allocating overhead costs to transmission
operations. In August 2000, SCE filed for rehearing of the FERC decision, asking for reconsideration of its decision, assuming that
the CPUC does not allow SCE to recover the $24 million in CPUC jurisdictional rates. SCE continued to collect the $24 million
annually in FERC rates subject to refund until new transmission rates became effective on September 1, 2002. In February 2001, SCE
filed with the CPUC a request to recover in CPUC rates the overhead costs not permitted in FERC rates (amounting to $119 million as
of June 30, 2003). On May 6, 2003, the assigned CPUC ALJ issued a proposed decision rejecting the request. SCE filed comments
challenging the proposed decision on the grounds that the costs at issue were already found to be reasonable by the CPUC in SCE's
1995 general rate case, and SCE is being denied the recovery of these costs solely due to different methodologies employed by the
CPUC and the FERC for allocation of overhead costs which are not directly assignable to the transmission and distribution functions.
On August 7, 2003, a CPUC commissioner issued an alternate decision approving SCE's request to recover the overhead costs. Comments
are due on the alternate draft decision on
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August 14, 2003, with reply comments due August 18, 2003. A final CPUC decision on this matter is expected in the third quarter of
2003.
Wholesale Electricity and Gas Markets
In response to a consolidated proceeding related to the justness and reasonableness of rates charged by sellers in the California
Power Exchange and ISO markets as described in the "SCE's Regulatory Matters--Wholesale Electricity Markets" disclosure in the
year-ended 2002 MD&A, the FERC issued orders that initiated procedures for determining additional refunds arising from market
manipulation by energy suppliers. A FERC staff report issued on March 26, 2003, found that there was pervasive gaming and market
manipulation of the electric and gas markets in California and in the west coast and also described many of the techniques and
effects of electric and gas market manipulation. In a March 26, 2003 order, clarified on April 22, 2003, the FERC adopted a
recommendation of the FERC staff's final report to modify the ALJ's initial decision of December 12, 2002 to reflect the fact that
the gas indices used in the market manipulation formula overstated the cost of gas used to generate electricity. SCE, as a member of
the California parties, sought rehearing of the March 26 and April 22 orders. On June 25, 2003, the FERC issued two sets of
enforcement orders. The first set orders 54 entities, including SCE, to show cause concerning gaming or anomalous market behavior
during the period January 1, 2001 to June 20, 2001. The second set orders 25 entities to show cause concerning gaming and anomalous
market behavior in concert with Enron entities. Under both sets of orders, the remedy for tariff violations will be the disgorgement
of unjust profits and possibly other non-monetary remedies. On June 25, 2003, the FERC also opened a new investigation into
anomalous bidding behavior during the period May 1, 2000 to October 2, 2000, focused primarily on economic withholding by bidding
above $250/MWh with disgorgement of profits as the possible penalty. SCE cannot, at this time, determine the timing or amount of any
potential refunds. Under the settlement agreement with the CPUC, 90% of any refunds will be given to ratepayers and 10% would be
given to shareholders. The CPUC issued an order instituting rulemaking on July 10, 2003, to account for the consideration received
by regulated gas and electric utilities under a settlement with El Paso Natural Gas Company, et al. Under the terms of the
rulemaking, SCE will refund amounts (net of legal and consulting costs) through its ERRA balancing account as they are received from
El Paso under the terms of the settlement. In addition, amounts El Paso refunds to CDWR will result in equivalent reductions in
CDWR's revenue requirement from SCE ratepayers.
Other Regulatory Matters
Bark Beetle Proceeding
On March 7, 2003, the Governor of California issued a proclamation declaring a state of emergency in Riverside, San Bernardino and
San Diego counties where an infestation of bark beetles has created the potential for catastrophic forest fires. The proclamation
requested that the CPUC direct utilities with transmission lines in these three counties to ensure that all dead, dying and diseased
trees and vegetation are completely cleared from their utility rights-of-way to mitigate the potential fire damage. The CPUC has
authorized SCE to offset its incremental expenses associated with the bark beetle emergency in a regulatory balancing account called
the Catastrophic Event Memorandum Account (CEMA). SCE estimates that it will incur in excess of $100 million in incremental expenses
over the next several years, and anticipates that the expected CEMA undercollection will be recovered in future rates with no impact
on earnings.
Customer Rate-Reduction Plan
On January 17, 2003, SCE filed with the CPUC a detailed plan outlining how customer rates could be reduced later in 2003 when SCE
completed recovery of uncollected procurement costs incurred on behalf of its customers during the California energy crisis and
reflected in the PROACT. In its January 17,
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2003 filing, SCE proposed that the CPUC apply rate reductions of about $1.2 billion in the same manner it applied a series of rate
surcharges during the energy crisis in 2001.
On July 10, 2003, a CPUC decision reduced SCE's annual rates by $1.2 billion, beginning the month after the PROACT balance was
forecasted to be fully recovered. The decision approves an April 2003 settlement agreement between SCE and active parties in this
proceeding in which bills will be reduced by 8% for residential customers, 18% for small businesses, 13% for medium businesses and
19% for large businesses. In accordance with the settlement agreement, on July 15, 2003, SCE submitted an advice filing to the CPUC
to implement the rate reduction effective on August 1, 2003, and to transfer the July 31, 2003 balance in the PROACT account (a $148
million overcollection) and the temporary surcharge balancing account (a $37 million overcollection) to the ERRA regulatory balancing
account.
OTHER DEVELOPMENTS
Clean Air Act
A federal court ruled on August 7, 2003 that Ohio Edison Company violated the Clean Air Act by upgrading seven aging coal-fired power
plants located at one site without first obtaining the necessary preconstruction permits under the new source review program. This
decision is currently being reviewed by Edison International to assess what implications, if any, the decision would have on Edison
International's results of operations or financial position.
Employee Compensation and Benefit Plans
On July 31, 2003, the United States District Court for the Southern District of Illinois held that the formula used in IBM's cash
balance pension plan violated the age discrimination provisions of the Employee Retirement Income Security Act of 1974. The formula
for SCE cash balance pension plan does not meet the standard set forth in that District Court's decision. The IBM decision, however,
conflicts with the decisions from two other district courts and with the proposed regulations for cash balance plans issued by the
IRS in December 2002. IBM has announced that they will appeal the decision to the Seventh Circuit Court of Appeals. The effect of
the IBM decision on SCE's cash balance plan cannot be determined at this time.
Palo Verde Steam Generators
During the fall of 2003, Palo Verde Unit 2 steam generators are scheduled to be replaced. In addition, the Palo Verde owners have
approved the manufacturing of two additional sets of steam generators for installation in Units 1 and 3. The Palo Verde owners
expect that these steam generators will be installed in Units 1 and 3 in the 2005 to 2008 time frame. SCE's share of the costs of
manufacturing and installing all replacement steam generators at Palo Verde is approximately $106 million, and is expected to be
recovered through the ratemaking process.
San Onofre Steam Generators
Like other nuclear power plants with steam generators made of a certain alloy (Inconel 600 mill annealed alloy), San Onofre Units 2
and 3 have experienced degradation in their steam generators. Presently, 9% and 7%, respectively, of the tubes in the existing steam
generators of Unit 2 and Unit 3 have been plugged and removed from service. SCE presently estimates that the San Onofre Units 2
and 3 generator design allows for the plugging and removal from service of 21.4% of the tubes before the units must be shutdown or the
steam generators replaced. Industry experience is that the percentage of tubes requiring plugging accelerates as steam generators
made of this alloy age. Based on this industry experience, SCE has determined that the existing San Onofre Units 2 and 3 steam
generators may not be adequate to permit continued operation beyond the fuel cycle 16 refueling outages in 2009-2010. SCE and its
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co-owners at San Onofre Units 2 and 3 continue to evaluate the necessity of replacing the steam generators and the cost-effectiveness
of so doing.
ACQUISITIONS AND DISPOSITIONS
In July 2003, EME agreed to sell its 50% interest in the Gordonsville project to a third party. Completion of the sale, currently
expected during the fourth quarter of 2003, is subject to closing conditions, including obtaining regulatory approval. Net proceeds
from the sale, including distribution of a debt service reserve fund, are expected to be approximately $32 million. EME recorded an
impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this investment.
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen, to acquire
Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands, California. This acquisition
requires regulatory approval from both the CPUC and the FERC. SCE has filed an application with the CPUC proposing a power-purchase
agreement between SCE and Mountainview Power Company LLC. If approved by the CPUC, SCE will seek FERC approval of the power-purchase
agreement. SCE does not expect to exercise the option without CPUC and FERC approvals. The option must be exercised prior to
February 29, 2004. If SCE exercises the option, SCE would recommence full construction of the project. Under the option agreement,
Sequoia may elect to terminate the option agreement at any time prior to SCE's exercise of the option. In such event, Sequoia must
return all previously tendered option payments.
On July 10, 2003, the CPUC approved a joint application filed by SCE and Pacific Terminals LLC, requesting authorization for the sale
of certain oil storage and pipeline facilities by SCE to Pacific Terminals for $158 million. The sale closed on July 31, 2003, and
resulted in a $45 million after-tax gain to shareholders, to be recorded in the third quarter of 2003.
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki
Combined Cycle power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located
near Stratford, New Zealand. Consideration for the Taranaki station consisted of a cash payment of approximately $275 million, which
was initially financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from the
issuance of long-term U.S. dollar denominated notes.
During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects
and its 30% interest in the Harbor project. Proceeds received from the sales were $44 million. During 2001, EME recorded asset
impairment charges of $32 million related to these projects based on the expected sales proceeds. No gain or loss was recorded from
the sale of EME's interests in these projects during the first quarter of 2002.
NEW ACCOUNTING PRINCIPLES
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or
liabilities as a result of timing differences between the recognition of costs in accordance with this standard and the recovery of
costs through the rate-making process. Regulatory
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assets and liabilities may also be recorded if it is probable that the asset retirement obligation (ARO) will be recovered through
the rate-making process.
Edison International's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power
facilities. SCE also recognized AROs associated with the decommissioning of coal-fired generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and $12 million to decommission
its share of a coal-fired generating plant, under accounting principles in effect at that time. Of these amounts, $298 million
to decommission its inactive nuclear facility was recorded in other long-term liabilities, and the remaining $2.0 billion was
recorded as a component of the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in
the 2002 Annual Report.
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning, recorded the fair value
of its AROs of approximately $2.0 billion in the deferred credits and other liabilities section of the balance sheet, and
increased its unamortized nuclear investment by $303 million. The cumulative effect of a change in accounting principle from
unrecognized accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date was a
$354 million after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory
liability, partially offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and depreciation expense
resulting from the application of the new standard is expected to be approximately $143 million in 2003. This cost will reduce
the regulatory liability, with no impact on earnings. As of June 30, 2003, SCE's ARO for its nuclear facilities totaled
approximately $2.1 billion and its nuclear decommissioning trust assets had a fair value of $2.3 billion. If the new standard
had been in place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.97 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in accumulated
depreciation and decommissioning.
o As of January 1, 2003, EME ARO was $17 million and EME recorded a cumulative effect adjustment that decreased net income by
approximately $9 million, net of tax. If the new standard had been applied retroactively in the six months ended June 30, 2002,
it would not have had a material effect on EME's results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities (VIEs). The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. This interpretation applies to VIEs
created after January 31, 2003 and beginning July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it
acquired before February 1, 2003.
If an enterprise absorbs the majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns, or
both, it must consolidate the VIE. An enterprise that is required to consolidate the VIE is called the primary beneficiary.
Additional disclosure requirements are also applicable when an enterprise holds a significant variable interest in a VIE, but is not
the primary beneficiary. In addition, financial statements issued after January 31, 2003 must include certain disclosures if it is
reasonably possible that an enterprise will consolidate or disclose information about a VIE when this interpretation is effective.
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Edison International has concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy Yard project
and Edison Capital's Storm Lake project, since it is at risk with respect to the majority of its losses and is entitled to receive
the majority of its residual returns. Accordingly, effective July 1, 2003, Edison International will consolidate these projects,
which will increase total assets by approximately $452 million and total liabilities by approximately $530 million . Edison
International expects to record a loss of approximately $78 million (of which $72 million is related to Brooklyn Navy Yard) in the
third quarter of 2003 as a cumulative accounting change as a result of consolidating these VIEs.
Edison International believes it is reasonably possible that certain partnership interests in energy projects are VIEs under this
interpretation, as discussed below.
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098 MW of power plants.
The maximum exposure to loss from EME's interest in these energy partnerships is $1.1 billion at June 30, 2003. Of this amount, $566
million represents EME's investment in the 1,230 MW Paiton project and $304 million represents EME's investment in the 540 MW
EcoElectrica project.
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another affiliated project
under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of
the obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to this
affiliated project. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot
be determined.
Edison International is in the process of reviewing the entities discussed above that have a reasonable possibility of being VIEs to
determine if it is the primary beneficiary.
A new accounting standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was
issued in May 2003 and requires issuers to classify certain freestanding financial instruments as liabilities. These freestanding
liabilities include mandatorily redeemable financial instruments, obligations to repurchase the issuer's equity shares by
transferring assets and certain obligations to issue a variable number of shares. The standard is effective for Edison International
on July 1, 2003. Upon implementation, Edison International will reclassify its company-obligated mandatorily redeemable securities,
its other mandatorily redeemable preferred securities and SCE's preferred stock subject to mandatory redemption to the liabilities
section of its consolidated balance sheets. These items are currently classified between liabilities and equity. In addition,
dividend payments on these instruments will be recorded as interest expense on Edison International's consolidated statements of
income. Edison International does not expect implementation of the new standard to have a material impact on its financial
statements.
In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Determining Whether an Arrangement Contains a Lease, which
provides guidance on how to determine whether an arrangement contains a lease that is within the scope of the standard, Accounting
for Leases. A lease is defined as an agreement conveying the right to use property, plant, or equipment (land and/or depreciable
assets) usually for a stated period of time. The guidance issued by the EITF could affect the classification of a power sales
agreement that meets specific criteria, such as a power sales agreement for substantially all of the output from a power plant to one
customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to the
lease accounting standard. The consensus is effective prospectively for arrangements entered into or modified after June 30, 2003.
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In June 2003, clarifying guidance was issued related to derivative instruments and hedging activities. The guidance is related to
permitted pricing adjustments in a contract qualifying under the normal purchases and normal sales exception under derivative
instrument accounting. This implementation guidance becomes effective on October 1, 2003. EME is currently reevaluating which
contracts, if any, that have previously been designated as normal purchases or normal sales would now not qualify for this exception.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates, believes, predict, and other
similar expressions are intended to identify forward-looking information that involves risks and uncertainties. Actual results or
outcomes could differ materially from those anticipated. Risks, uncertainties and other important factors that could cause results
to differ or that otherwise could impact Edison International and its subsidiaries, include, among other things:
o the outcome of the pending appeal of the stipulated judgment approving SCE's settlement agreement with the CPUC, and the
effects of other legal actions, if any, attempting to undermine the provisions of the settlement agreement or otherwise adversely
affecting SCE;
o the substantial amount of debt and lease obligations of MEHC, EME and their subsidiaries, including $911 million of debt
maturing in December 2003, $275 million of a credit facility expiring in September 2003, and the Term Loan Put-Option which
present the risk that MEHC, EME, and their subsidiaries might not be able to repay or refinance their obligations, raise
additional financing for their future cash requirements, or provide credit support for ongoing operations;
o the actions of securities rating agencies, including the determination of whether or when to make changes in ratings
assigned to Edison International and its subsidiaries that are rated, the ability of Edison International, SCE, EME and Edison
Capital to regain investment-grade ratings, and the impact of current or lowered ratings and other financial market conditions on
the ability of the respective companies to obtain needed financing on reasonable terms and provide credit support;
o changes in prices and availability of wholesale electricity, natural gas, other fuels, and transmission services, and other
changes in operating costs, which could affect the timing of SCE's energy procurement cost recovery, or otherwise impact SCE's
and EME's operations and financial results;
o the operation of some of EME's power plants without long-term power purchase agreements, which may adversely affect EME's
ability to sell the plant's output at profitable terms;
o the substantial amount of EME's revenue derived under power purchase agreements with a single customer, which could
adversely affect EME's results of operations and liquidity;
o changing conditions in wholesale power markets, such as general credit constraints and thin trading volumes, that could make
it difficult for EME or SCE to buy or sell power or enter into hedging agreements;
o provisions in MEHC's, EME's and their subsidiaries' organizational and financing documents that limit their ability to,
among other things, incur and repay debt, pay dividends, sell assets, and enter into specified transactions that they otherwise
might enter into, which may impair their ability to compete effectively or to operate successfully under adverse economic
conditions;
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o the possibility that existing tax allocation agreements may be terminated or may not operate as contemplated, for example, if the
consolidated group does not have sufficient taxable income to use the tax benefits of each group member, or if any member ceases
to be a part of the consolidated group;
o actions by state and federal regulatory and administrative bodies setting rates, adopting or modifying cost recovery,
holding company rules, accounting and rate-setting mechanisms, or otherwise changing the regulatory and business environments
within which Edison International and its subsidiaries do business, as well as legislative or judicial actions affecting the same
matters;
o the effects of increased competition in energy-related businesses, including new market entrants and the effects of new
technologies that may be developed in the future;
o threatened attempts by municipalities within SCE's service territory to form public power entities and/or acquire SCE's
facilities for customers;
o the creditworthiness and financial strength of Edison Capital's counterparties worldwide in energy and infrastructure
projects, including power generation, electric transmission and distribution, transportation, and telecommunications;
o the effects of declining interest rates and investment returns on employee benefit plans and nuclear decommissioning trusts;
o general political, economic and business conditions in the countries in which Edison International and its subsidiaries do
business;
o political and business risks of doing business in foreign countries, including uncertainties associated with currency
exchange rates, currency repatriation, expropriation, political instability, privatization and other issues;
o power plant operation risks, including equipment failures, availability, output and labor issues;
o new or increased environmental requirements that could require capital expenditures or otherwise affect the operations and
cost of Edison International and its subsidiaries, and possible increased liabilities under new or existing requirements; and
o weather conditions, natural disasters, and other unforeseen events.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 3 is included in Item 2, Management's Discussion and Analysis of Results of Operations and Financial
Condition, under Market Risk Exposures, and is incorporated herein by reference.
Item 4. Controls and Procedures
Disclosure Controls and Procedures.
Edison International's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of Edison International's disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this
report. Based on such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such
period, Edison International's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
There have not been any changes in Edison International's internal control over financial reporting (as such term is defined in Rules
13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected,
or are reasonably likely to materially affect, Edison International's internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Edison International
None
Edison Mission Energy
Sunrise Proceedings
As previously reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K for the fiscal year ended December 31,
2002 (2002 Form 10-K), Sunrise Power Company, LLC (Sunrise), in which EME owns a 50% interest, sells all its output to the CDWR under
a power purchase agreement entered into on June 25, 2001. On May 15, 2002, Sunrise was served with a complaint filed in the Superior
Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general
public and as a representative taxpayer suit" against sellers of long-term power to the CDWR, including Sunrise. The lawsuit alleges
that the defendants, including Sunrise, engaged in unfair and fraudulent business practices by knowingly taking advantage of a
manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive
terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants.
Plaintiffs in several other lawsuits are seeking to have the Millar lawsuit consolidated with other class action suits pending in the
San Francisco area. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District
Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional
issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. On
July 7, 2003, the lawsuit was remanded to state court.
Southern California Edison Company
CPUC Litigation Settlement Agreement
As previously reported in Part I, Item 3 of Edison International's 2002 Form 10-K, and in Part II, Item 1 of Edison International's
Quarterly Report on Form 10-Q for the period ending March 31, 2003 (First Quarter 10-Q), SCE filed a lawsuit against the California
Public Utilities Commission (CPUC) in federal district court seeking a ruling that SCE is entitled to full recovery of its
electricity procurement costs incurred during the energy crisis in accordance with the tariffs filed with the Federal Energy
Regulatory Commission. See the discussion, which is incorporated herein by this reference, in Part 1, Item 2, Management's
Discussion and Analysis of Financial Condition and Results of Operations under "SCE'S REGULATORY MATTERS - CPUC Litigation Settlement
Agreement."
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
As previously reported in Part I, Item 3 of Edison International's 2002 Form 10-K, and in Part II, Item 1 of Edison International's
First Quarter 10-Q, on August 25, 2001, the CPUC issued an order instituting investigation regarding SCE's overhead and underground
electric line maintenance practices. See the discussion, which is incorporated herein by this reference, in Part 1, Item 2,
Management's Discussion and Analysis of Financial Condition and Results of Operations under "SCE'S REGULATORY MATTERS - Electric Line
Maintenance Proceedings."
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Item 4. Submission of Matters to a Vote of Security Holders
At Edison International's Annual Meeting of Shareholders on May 15, 2003, two matters were put to a vote of the shareholders: the
election of eleven directors, and a shareholder proposal on Edison International's Shareholder Rights Agreement.
Shareholders elected eleven 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 274,111,331 10,960,581
Bradford M. Freeman 274,555,427 10,516,485
Joan C. Hanley 275,984,009 9,087,903
Bruce Karatz 275,770,945 9,300,967
Luis G. Nogales 274,864,867 10,207,045
Ronald L. Olson 262,241,101 22,830,811
James M. Rosser 276,085,118 8,986,794
Richard T. Schlosberg, III 274,517,746 10,554,166
Robert H. Smith 274,406,624 10,665,288
Thomas C. Sutton 274,331,536 10,740,376
Daniel M. Tellep 274,404,589 10,667,323
- ------------------------------------------------------------------------------------------------------------------------------
The shareholder proposal on Edison International's Shareholder Rights Agreement was adopted by the shareholders. The proposal
received the following numbers of votes:
FOR AGAINST ABSTENTIONS BROKER NON-VOTES
- ------------------------------------------------------------------------------------------------------------------------------
152,599,932 90,166,622 5,592,530 36,712,828
- ------------------------------------------------------------------------------------------------------------------------------
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 9, 1996
(File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of Edison International
dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on January 1, 2002 (File No. 1-9936,
Form 10-K for the year ended December 31, 2001)*
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. 1350
- ----------------
* Incorporated by reference pursuant to Rule 12b-32.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 7, 2003 May 7, 2003 7 and 9
May 14, 2003 May 15, 2003 5
June 25, 2003 June 30, 2003 5
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By /s/ THOMAS M. NOONAN
---------------------------------
THOMAS M. NOONAN
Vice President and Controller
By /s/ KENNETH S. STEWART
---------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
August 12, 2003