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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
--------------------------------------------- ----------------------------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 976)
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
(626) 302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No |_|
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes |X|
No |_|
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class Outstanding at April 30, 2005
- ----------------------------------------------------- -------------------------------------------------------
Common Stock, no par value 325,811,206
=======================================================================================================================================
EDISON INTERNATIONAL
INDEX
Page
No.
------
Part I.Financial Information:
Item 1. Financial Statements:
Consolidated Statements of Income - Three Months
Ended March 31, 2005 and 2004 1
Consolidated Statements of Comprehensive Income -
Three Months Ended March 31, 2005 and 2004 2
Consolidated Balance Sheets - March 31, 2005
and December 31, 2004 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2005 and 2004 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 32
Item 3. Quantitative and Qualitative Disclosures About Market Risk 80
Item 4. Controls and Procedures 80
Part II. Other Information:
Item 1. Legal Proceedings 81
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 82
Item 6. Exhibits 83
Signature
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
March 31,
- -----------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2005 2004
- -----------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility $ 1,908 $ 1,696
Nonutility power generation 511 389
Financial services and other 27 31
- -----------------------------------------------------------------------------------------------------------------
Total operating revenue 2,446 2,116
- -----------------------------------------------------------------------------------------------------------------
Fuel 419 227
Purchased power 388 580
Provisions for regulatory adjustment clauses - net 65 (19)
Other operation and maintenance 815 787
Depreciation, decommissioning and amortization 259 256
Property and other taxes 52 45
- -----------------------------------------------------------------------------------------------------------------
Total operating expenses 1,998 1,876
- -----------------------------------------------------------------------------------------------------------------
Operating income 448 240
Interest and dividend income 21 10
Equity in income from partnerships and
unconsolidated subsidiaries - net 84 19
Other nonoperating income 18 81
Interest expense - net of amounts capitalized (214) (239)
Loss on early extinguishment of debt (24) --
Other nonoperating deductions (10) (14)
- ------------------------------------------------------------------------------------------------------------------
Income from continuing operations before tax and minority interest 323 97
Income tax 104 43
Dividends on utility preferred stock not subject to mandatory redemption 1 1
Minority interest 24 1
- ------------------------------------------------------------------------------------------------------------------
Income from continuing operations 194 52
Income from discontinued operations - net of tax 7 46
- ------------------------------------------------------------------------------------------------------------------
Income before accounting change 201 98
Cumulative effect of accounting change - net of tax -- (1)
- ------------------------------------------------------------------------------------------------------------------
Net income $ 201 $ 97
- ------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock outstanding 326 326
Basic earnings per common share:
Continuing operations $ 0.59 $ 0.16
Discontinued operations 0.02 0.14
Cumulative effect of accounting change -- --
- ------------------------------------------------------------------------------------------------------------------
Total $ 0.61 $ 0.30
- ------------------------------------------------------------------------------------------------------------------
Weighted-average shares, including
effect of dilutive securities 331 330
Diluted earnings per common share:
Continuing operations $ 0.59 $ 0.16
Discontinued operations 0.02 0.14
Cumulative effect of accounting change -- --
- ------------------------------------------------------------------------------------------------------------------
Total $ 0.61 $ 0.30
- ------------------------------------------------------------------------------------------------------------------
Dividends declared per common share $ 0.25 $ 0.20
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
- ------------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- ------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 201 $ 97
Other comprehensive income (expense), net of tax:
Foreign currency translation adjustments -- 22
Unrealized gains (losses) on cash flow hedges:
Other unrealized loss on cash flow hedges - net (70) (45)
Reclassification adjustment for gain (loss) included in net income (5) 21
- ------------------------------------------------------------------------------------------------------------------
Other comprehensive income (expense) (75) (2)
- ------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 126 $ 95
- ------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions 2005 2004
- -----------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 2,363 $ 2,688
Restricted cash 66 73
Receivables, less allowances of $33 and $31 for uncollectible
accounts at respective dates 851 846
Accrued unbilled revenue 299 320
Fuel inventory 81 73
Materials and supplies 238 231
Accumulated deferred income taxes - net 287 288
Trading and price risk management assets 35 41
Regulatory assets 847 553
Other current assets 451 336
- -----------------------------------------------------------------------------------------------------------------
Total current assets 5,518 5,449
- -----------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision for
depreciation of $1,354 and $1,311 at respective dates 3,948 3,922
Nuclear decommissioning trusts 2,726 2,757
Investments in partnerships and unconsolidated subsidiaries 636 608
Investments in leveraged leases 2,442 2,424
Other investments 295 197
- ----------------------------------------------------------------------------------------------------------------
Total investments and other assets 10,047 9,908
- ----------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 15,841 15,685
Generation 1,361 1,356
Accumulated provision for depreciation (4,603) (4,506)
Construction work in progress 860 789
Nuclear fuel, at amortized cost 151 151
- ----------------------------------------------------------------------------------------------------------------
Total utility plant 13,610 13,475
- ----------------------------------------------------------------------------------------------------------------
Restricted cash 97 155
Regulatory assets 3,257 3,285
Other deferred charges 921 875
- ----------------------------------------------------------------------------------------------------------------
Total deferred charges 4,275 4,315
- ----------------------------------------------------------------------------------------------------------------
Assets of discontinued operations 13 122
- ----------------------------------------------------------------------------------------------------------------
Total assets $ 33,463 $ 33,269
- ----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions, except share amounts 2005 2004
- ----------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 290 $ 88
Long-term debt due within one year 726 809
Preferred stock to be redeemed within one year 9 9
Accounts payable 641 749
Accrued taxes 237 226
Accrued interest 223 233
Customer deposits 173 168
Book overdrafts 194 232
Trading and price risk management liabilities 179 31
Regulatory liabilities 841 490
Other current liabilities 987 1,002
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 4,500 4,037
- ---------------------------------------------------------------------------------------------------------------
Long-term debt 9,366 9,678
- ---------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 5,303 5,233
Accumulated deferred investment tax credits 137 138
Customer advances and other deferred credits 1,139 1,109
Power-purchase contracts 102 130
Preferred stock subject to mandatory redemption 135 139
Accumulated provision for pensions and benefits 544 523
Asset retirement obligations 2,214 2,188
Regulatory liabilities 3,236 3,356
Other long-term liabilities 242 232
- ---------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 13,052 13,048
- ---------------------------------------------------------------------------------------------------------------
Liabilities of discontinued operations 15 15
- ---------------------------------------------------------------------------------------------------------------
Total liabilities 26,933 26,778
- ---------------------------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 2 and 4)
Minority interest 301 313
- ---------------------------------------------------------------------------------------------------------------
Preferred stock of utility not subject to mandatory redemption 129 129
- ---------------------------------------------------------------------------------------------------------------
Common stock (325,811,206 shares outstanding at each date) 1,985 1,975
Accumulated other comprehensive loss (79) (4)
Retained earnings 4,194 4,078
- ---------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 6,100 6,049
- ---------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 33,463 $ 33,269
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 4
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS Three Months Ended
March 31,
- -----------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- -----------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 194 $ 51
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax -- 1
Depreciation, decommissioning and amortization 259 256
Other amortization 22 23
Minority interest 24 1
Deferred income taxes and investment tax credits 34 135
Equity in income from partnerships and unconsolidated subsidiaries (84) (19)
Income from leveraged leases (18) (24)
Regulatory assets - long-term 170 75
Regulatory liabilities - long-term (70) (31)
Loss on early extinguishment of debt 24 --
Other assets (1) --
Other liabilities 25 41
Receivables and accrued unbilled revenue 14 46
Inventory, prepayments and other current assets (271) 36
Regulatory assets - short-term (294) (308)
Regulatory liabilities - short-term 352 195
Accrued interest and taxes 21 (112)
Accounts payable and other current liabilities (97) (80)
Distributions and dividends from unconsolidated entities 14 26
- ------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 318 312
- ------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued and issuance costs 640 1,617
Long-term debt repaid (1,208) (954)
Bonds remarketed - net -- 350
Redemption of preferred securities (4) (2)
Rate reduction notes repaid (62) (62)
Change in book overdrafts (38) (26)
Short-term debt financing - net 202 (203)
Shares purchased for stock-based compensation (31) (8)
Proceeds from stock option exercises 20 5
Dividends to minority shareholders (29) --
Dividends paid (81) (65)
- ------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities (591) 652
- ------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Capital expenditures (377) (330)
Acquisition costs related to nonutility generation plant -- (285)
Proceeds from sale of property and interests in projects -- 118
Proceeds from sale of discontinued operations 124 --
Contributions to and earnings from nuclear decommissioning trusts - net (24) (21)
Distributions from (investments in) partnerships and unconsolidated subsidiaries 27 10
Purchase of short-term investments - net 140 (40)
Sales of investments in other assets 58 40
- ------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (52) (508)
- ------------------------------------------------------------------------------------------------------------------
Effect of discontinued operations activities on cash 2 7
- ------------------------------------------------------------------------------------------------------------------
Effect of consolidation of variable interest entities on cash -- 79
- ------------------------------------------------------------------------------------------------------------------
Effect of deconsolidation of variable interest entities on cash -- (32)
- ------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (323) 510
Cash and equivalents, beginning of period 2,689 2,178
- ------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period 2,366 2,688
Cash and equivalents, discontinued operations (3) (195)
- ------------------------------------------------------------------------------------------------------------------
Cash and equivalents, continuing operations $ 2,363 $ 2,493
- ------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting principles generally
accepted in the United States for the periods covered by this report. The results of operations for the period ended March 31, 2005
are not necessarily indicative of the operating results for the full year.
This quarterly report should be read in conjunction with Edison International's Annual Report on Form 10-K for the year ended
December 31, 2004 filed with the Securities and Exchange Commission.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2004 Annual Report. Edison International follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the March 31, 2005 financial statement presentation. These
reclassifications include the reclassification of income from continuing operations to discontinued operations for Edison Mission
Energy's (EME) international operations, except the Doga project. See further discussion in Note 6. Except as indicated, amounts
presented in the Notes to the Consolidated Financial Statements relate to continuing operations.
Earnings Per Common Share (EPS)
In March 2004, the Financial Accounting Standards Board (FASB) issued new accounting guidance for the effect of participating
securities on EPS calculations and the use of the two-class method. The new guidance, which was effective in second quarter 2004,
requires the use of the two-class method of computing EPS for companies with participating securities. The two-class method is an
earnings allocations formula that determines EPS for each class of common stock and participating security. Edison International has
participating securities (vested stock options that earn dividend equivalents on an equal basis with common shares), but determined
that the effect on 2004, 2003 and 2002 EPS was immaterial.
Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding.
Net income available for common stock was $200 million and $97 million for the three months ended March 31, 2005, and 2004,
respectively. In arriving at net income, dividends on preferred securities and preferred stock have been deducted.
For the diluted EPS calculation, dilutive securities (stock-based compensation awards exercisable) are added to the weighted-average
shares. Dilutive securities are excluded from the diluted EPS calculation for items with a net loss due to their antidilutive effect.
New Accounting Principles
In March 2005, the FASB issued an interpretation related to accounting for conditional asset retirement obligations. This
Interpretation clarifies that an entity is required to recognize a liability for the fair
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
value of a conditional asset retirement obligation (ARO) if the fair value can be reasonably estimated even though uncertainty exists
about the timing and/or method of settlement. This Interpretation is effective December 31, 2005. Edison International is assessing
the impact of this Interpretation on its results of operations and financial condition.
A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison
International currently uses the intrinsic value accounting method for stock-based compensation. On April 14, 2005, the Securities
and Exchange Commission announced a delay in the effective date for the new standard to fiscal years beginning after June 15, 2005.
Edison International will implement the new standard effective January 1, 2006 by applying the modified prospective transition
method. The difference in expense between the two accounting methods is shown below under "Stock-Based Compensation."
In December 2004, the FASB issued guidance (Staff Position 109-1) on accounting for a tax deduction resulting from the American Jobs
Creation Act of 2004. The primary objective of this Position is to provide guidance on accounting for the provision within the
American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities. Under this Position,
recognition of the tax deduction on qualified production activities, which include the production of electricity, is reported in the
year it is earned. This FASB Staff Position had no material impact on Edison International's financial statements. Edison
International is evaluating the effect that the manufacturer's deduction will have in subsequent years.
In March 2004, the FASB issued new accounting guidance for the effect of participating securities on EPS calculations and the use of
the two-class method. The new guidance, which was effective in second quarter 2004, requires the use of the two-class method of
computing EPS for companies with participating securities (including vested stock options with dividend equivalents). See "Earnings
Per Common Share" above.
In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003), Consolidation of
Variable Interest Entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and
financial reporting for, VIEs, where control may be achieved through means other than voting rights. Under the Interpretation, the
enterprise that is expected to absorb or receive the majority of a VIE's expected losses or residual returns, or both, must
consolidate the VIE, unless specific exceptions apply. This Interpretation was effective for special purpose entities, as defined by
accounting principles generally accepted in the United States, as of December 31, 2003, and all other entities as of March 31, 2004.
Edison International implemented the Interpretation for its special purpose entities as of December 31, 2003.
On March 31, 2004, Southern California Edison (SCE) consolidated four power projects partially owned by EME, EME deconsolidated two
power projects, and Edison Capital consolidated two affordable housing partnerships and three wind projects. Edison International
recorded a cumulative effect adjustment that decreased net income by less than $1 million, net of tax, due to negative equity at one
of Edison Capital's newly consolidated entities.
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets included in the consolidated balance sheets are:
March 31, December 31,
In millions 2005 2004
- ------------------------------------------------------------------------------------------------------------
(Unaudited)
Current
Regulatory balancing accounts $ 675 $ 371
Direct access procurement charges 111 109
Purchased-power settlements 61 62
Other -- 11
- ------------------------------------------------------------------------------------------------------------
847 553
- ------------------------------------------------------------------------------------------------------------
Long-term
Flow-through taxes - net 1,107 1,018
Rate reduction notes - transition cost deferral 647 739
Unamortized nuclear investment - net 519 526
Nuclear-related ARO investment - net 269 272
Unamortized coal plant investment - net 80 78
Unamortized loss on reacquired debt 306 250
Direct access procurement charges 110 141
Environmental remediation 60 55
Purchased-power settlements 76 91
Other 83 115
- ------------------------------------------------------------------------------------------------------------
3,257 3,285
- ------------------------------------------------------------------------------------------------------------
Total Regulatory Assets $ 4,104 $ 3,838
- ------------------------------------------------------------------------------------------------------------
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory liabilities included in the consolidated balance sheets are:
March 31, December 31,
In millions 2005 2004
- ------------------------------------------------------------------------------------------------------------
(Unaudited)
Current
Regulatory balancing accounts $ 571 $ 357
Direct access procurement charges 111 109
Other 159 24
- ------------------------------------------------------------------------------------------------------------
841 490
- ------------------------------------------------------------------------------------------------------------
Long-term
ARO 734 819
Costs of removal 2,124 2,112
Direct access procurement charges 110 141
Employee benefits plans 212 200
Other 56 84
- ------------------------------------------------------------------------------------------------------------
3,236 3,356
- ------------------------------------------------------------------------------------------------------------
Total Regulatory Liabilities $ 4,077 $ 3,846
- ------------------------------------------------------------------------------------------------------------
Stock-Based Compensation
Edison International has three stock-based compensation plans, which are described more fully in Note 7 of "Notes to Consolidated
Financial Statements" included in its 2004 Annual Report. Edison International accounts for these plans using the intrinsic value
method. Upon grant, no stock-based compensation cost is reflected in net income, as all options granted under those plans had an
exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the
effect on net income and EPS if Edison International had used the fair-value accounting method.
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended
March 31,
- -------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2005 2004
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income, as reported $ 201 $ 97
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 11 4
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 13 3
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 199 $ 98
- -------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
As reported $ 0.61 $ 0.30
Pro forma $ 0.61 $ 0.30
Diluted earnings per common share:
As reported $ 0.61 $ 0.30
Pro forma $ 0.60 $ 0.30
- -------------------------------------------------------------------------------------------------------------------
Supplemental Accumulated Other Comprehensive Loss Information
Supplemental information regarding Edison International's accumulated other comprehensive loss, including discontinued operations, is:
March 31, December 31,
In millions 2005 2004
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Minimum pension liability - net $ (16) $ (15)
Unrealized gains (losses) on cash flow hedges - net (63) 11
- --------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive loss $ (79) $ (4)
- --------------------------------------------------------------------------------------------------------------
The minimum pension liability is discussed in Note 7, Compensation and Benefit Plans of "Notes to Consolidated Financial Statements"
included In Edison International's 2004 Annual Report.
Included in Edison International's accumulated other comprehensive loss at March 31, 2005, was a $57 million loss related to EME's
net unrealized losses on cash flow hedges and a $6 million loss related to SCE's interest rate swap (see discussion below).
Unrealized losses on cash flow hedges at March 31, 2005, include unrealized losses on commodity hedges primarily related to EME's
Homer City and Midwest Generation forward electricity contracts that did not meet the normal sales and purchases exception under the
derivative accounting standard. These losses arise because current forecasts of future electricity prices in these markets are
greater than contract prices. Partially offsetting these unrealized losses were unrealized gains on commodity hedges related to
EME's share of fuel contracts at its March Point cogeneration facility.
Unrealized losses on cash flow hedges also included those related to SCE's interest rate swap (the swap terminated on January 5,
2001, but the related debt matures in 2008). The unamortized loss of $6 million
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(as of March 31, 2005, net of tax) on the interest rate swap will be amortized over a period ending in 2008. Approximately
$2 million, after tax, of the unamortized loss on this swap will be reclassified into earnings during the next 12 months. Amortized
losses are recoverable through SCE's annual cost of capital proceeding.
As EME's hedged positions for continuing operations are realized, approximately $73 million (after tax) of the net unrealized losses
on cash flow hedges at March 31, 2005 are expected to be reclassified into earnings during the next 12 months. EME expects that
reclassification of net unrealized losses will offset energy revenue recognized at market prices. Actual amounts ultimately
reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market
conditions. The maximum period over which an EME cash flow hedge is designated is through December 31, 2006.
Supplemental Cash Flows Information
Three Months Ended
March 31,
- ----------------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- ----------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash payments for interest and taxes:
Interest - net of amounts capitalized $ 201 $ 271
Tax payments 28 --
Non-cash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed $ (49) --
Pollution-control bonds issued 204 --
- --------------------------------------------------------------------------------------------------------------------
Funds held in trust $ 155 --
- --------------------------------------------------------------------------------------------------------------------
Dividends declared but not paid $ 81 $ 65
Details of consolidation of variable interest entities:
Assets -- $ 625
Liabilities -- (704)
Details of deconsolidation of variable interest entities:
Assets -- $ (133)
Liabilities -- 165
Reoffering of pollution-control bonds -- $ 196
Details of pollution-control bond redemption:
Release of funds held in trust -- $ 20
Pollution-control bonds redeemed -- (20)
- --------------------------------------------------------------------------------------------------------------------
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Regulatory Matters
Further information on these regulatory matters is described in Note 2 of "Notes to Consolidated Financial Statements" included in
Edison International's 2004 Annual Report.
California Department of Water Resources (CDWR) Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in Note 2 of "Notes to Consolidated
Financial Statements" included in Edison International's 2004 Annual Report, in December 2004, the California Public Utilities
Commission (CPUC) issued its decision on how the CDWR's power charge revenue requirement for 2004 through 2013, when the last CDWR
contract expires, will be allocated among the investor-owned utilities. San Diego Gas & Electric (SDG&E) has filed a petition for
modification of the decision urging the CPUC to replace the adopted methodology with a methodology that would retain the
cost-follows-contract allocation of the avoidable costs, but would allocate the unavoidable costs associated with the contracts:
42.2% to Pacific Gas and Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. Such an allocation
would decrease the total costs allocated to SDG&E's customers and increase the total costs allocated to SCE's customers. The
assigned Administrative Law Judge has issued a draft decision denying the petition, but the draft is potentially subject to
revision. The CPUC is expected to act on the petition by the end of June 2005. Amounts billed to SCE's customers for electric power
purchased and sold by the CDWR are remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no
impact on SCE's earnings.
Energy Resource Recovery Account (ERRA) Proceedings
In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to track and recover SCE's: (1) fuel costs
related to its generating stations; (2) purchased-power costs related to cogeneration and renewable contracts; (3) purchased-power
costs related to existing interutility and bilateral contracts that were entered into before January 17, 2001; and (4) new
procurement-related costs incurred on or after January 1, 2003 (the date on which the CPUC transferred back to SCE the responsibility
for procuring energy resources for its customers). SCE recovers these costs on a cost-recovery basis, with no markup for return or
profit. SCE files annual forecasts of the above-described costs that it expects to incur during the following year. As these costs
are subsequently incurred, they will be tracked and recovered through the ERRA, but are subject to a reasonableness review in a
separate annual ERRA application. If the ERRA overcollection or undercollection exceeds 5% of SCE's prior year's generation revenue,
the CPUC has established a "trigger" mechanism, whereby SCE can request an emergency rate adjustment in addition to the annual
forecast and reasonableness ERRA applications.
ERRA Trigger Mechanism Filing
On March 25, 2005, SCE submitted a CPUC rate application under the ERRA trigger mechanism, as the recorded undercollection in its
ERRA balancing account as of February 28, 2005 had reached 9.7% of recorded 2004 generation revenue, well above the 5% threshold for
an emergency rate adjustment established by the CPUC. SCE's undercollection had been less than 4% of recorded 2004 generation
revenue at the end of January 2005. A combination of higher procurement costs, a delay in approval of the 2005 ERRA rate change and
other factors contributed to the large increase in the undercollection amount in February 2005. Nevertheless, SCE's trigger
application requested that the CPUC recognize and retain recently adopted rate levels rather than increasing rates. The application
cited the CPUC's
Page 12
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
recently approved ERRA rates in the 2005 ERRA forecast proceeding as compliant with the California Assembly Bill 57 requirements to
promptly amortize the undercollection. The application forecasted amortization of the ERRA undercollection to below the 5% threshold
by the end of July 2005, and amortization to zero by mid-September 2005. Therefore, the application requested a finding that no
further rate action is necessary at this time. A CPUC decision on this application is expected in May 2005.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA reasonableness review application requesting that the CPUC find its procurement-related
operations for calendar year 2004 to be reasonable. In addition, SCE requested recovery of approximately $13 million associated with
Nuclear Unit Incentive Procedure rewards for efficient operation of the Palo Verde Nuclear Generating Station and approximately
$7 million in administrative and general costs incurred to carry out the CPUC's directive to begin procuring energy supplies on
January 1, 2003 following the California energy crisis.
Generation Procurement Proceedings
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in a Southern California
region known as South of Path 15 (SP-15). To enable potential generators to secure financing to construct necessary generation
facilities, SCE has issued a Request for Offers (RFO) for New Generation Resources in SP-15. SCE is soliciting offers for
power-purchase agreements lasting up to 10 years from new generation facilities with delivery under the agreement beginning between
June 1, 2006 and August 1, 2008. SCE will file an application with the CPUC seeking approval of the RFO and the power-purchase
agreements executed under the RFO. SCE will also seek recovery of the costs of the contracts, through Federal Energy Regulatory
Commission (FERC)-jurisdictional rates, from all SP-15 customers. In addition, SCE will seek CPUC assurance of full cost recovery in
CPUC-approved rates, if the FERC denies any recovery. Any power-purchase agreement that SCE executes as a result of the RFO will be
contingent on CPUC approval of the contract and assurance of full cost recovery.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions authorizing utilities to form
holding companies and initiated an investigation into, among other things: (1) whether the holding companies violated CPUC
requirements to give first priority to the capital needs of their respective utility subsidiaries; (2) any additional suspected
violations of laws or CPUC rules and decisions; and (3) whether additional rules, conditions, or other changes to the holding company
decisions are necessary. For a discussion of item (1) above, see the "Holding Company Proceeding" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in Edison International's 2004 Annual Report.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed the proceeding without
addressing some of the issues the proceeding raised (such as the appropriateness of the large utilities' holding company structure
and dividend policies), the CPUC may rule on or investigate these issues in the future.
Page 13
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
California Independent System Operator (ISO) Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the cities of Anaheim, Azusa, Banning and
Riverside, California over the proper allocation and characterization of certain charges. The order reversed an arbitrator's award
that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those
charges to Scheduling Coordinators (SC) in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the
ISO to shift the costs from SCs in the affected zone to the responsible Participating Transmission Owner, SCE, and to do so within 60
days of the April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the Participating
Transmission Owner but also will be credited through the California Power Exchange, SCE's SC at the time. SCE obtained a stay of the
April 20, 2004 order pending resolution of its request for rehearing. On March 30, 2005, the FERC issued an Order Denying
Rehearing. SCE obtained an extension of the stay pending resolution of the appeal SCE has filed with the United States Court of
Appeals for the D.C. Circuit (D.C. Circuit Court). The potential net impact on SCE is estimated to be approximately $20 million to
$25 million, including interest. Should the April 20, 2004 order stand, SCE expects to receive recovery in rates of the amount
described above. SCE filed a request for clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the
disputed costs in SCE's reliability service rates.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report, the CPUC issued a final decision in December 2004 on SCE's
application regarding the post-2005 operation of Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant parties in an effort
to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been reached to date. Because resolution has not
been reached and because of the lead times required for installation of certain pollution-control equipment and other upgrades
necessary for post-2005 operation, it is probable that Mohave will shut down for at least several years, and perhaps permanently, at
the end of 2005. The outcome of the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. The outcome of this
matter is not expected to have a material impact on earnings.
For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in Note 2 of "Notes to Consolidated Financial
Statements" included in Edison International's 2004 Annual Report, SCE is participating in several related proceedings seeking
recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including SCE, PG&E, the State of
California and various consumer class action representatives) settling various claims stated in proceedings at the FERC and in San
Diego County Superior Court that El Paso had manipulated interstate capacity and engaged in other anticompetitive behavior in the
natural
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
gas markets in order to unlawfully raise gas prices at the California border in 2000-2001. The United States District Court has
issued an order approving the stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC decision,
SCE will refund to customers amounts received under the terms of the El Paso settlement (net of legal and consulting costs) through
its ERRA mechanism. In June 2004, SCE received its first settlement payment of $76 million. Approximately $66 million of this
amount was credited to purchased-power expense, and will be refunded to SCE's ratepayers through the ERRA over the next 12 months,
and the remaining $10 million was used to offset SCE's incurred legal costs. El Paso has elected to prepay the additional settlement
payments over a 20-year period and as a result, made a payment to the escrow holder on April 15, 2005 of approximately $442 million.
The distribution of these funds to the settling parties will not occur until the superior court judge presiding over the settlement
has issued an order affirming an allocation of these funds to the various settling parties. That order will likely be issued by
mid-May 2005. It is estimated that SCE's share will be approximately $66 million. Amounts El Paso refunds to the CDWR will result
in reductions in the CDWR's revenue requirement allocated to SCE in proportion to SCE's share of the CDWR's power charge revenue
requirement.
On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant Corporation and a
number of its affiliates (collectively Mirant), all of whom are debtors in a Chapter 11 bankruptcy proceeding pending in Texas.
Among other things, the settlement terms provide for expected cash and equivalent refunds totaling $320 million, of which SCE's
allocated share is approximately $68 million. The settlement also provides for an allowed, unsecured claim totaling $175 million in
the bankruptcy of one of the Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual
value of the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant settlement
was approved by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. Under the settlement terms, distribution
of the cash portion of the settlement proceeds is to occur within 20 business days of April 15, 2005 and will be refunded to
ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum Account (ESMA) for
the purpose of recording the foregoing settlement proceeds from energy providers and allocating them in accordance with the terms of
the CPUC litigation settlement agreement. The resolution accordingly provides a mechanism whereby portions of the settlement
proceeds recorded in the ESMA will be allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings
described above and a 10% shareholder incentive pursuant to the CPUC litigation settlement agreement. Remaining amounts for each
settlement are to be refunded to ratepayers through the ERRA mechanism.
Note 3. Pension Plan and Postretirement Benefits Other Than Pensions
Pension Plan
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2004 Annual Report that it expects to contribute approximately $53 million to its pension plans in 2005. As of
March 31, 2005, $5 million in contributions have been made. Edison International anticipates that its original expectations will be
met by year-end 2005.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components are:
Three Months Ended
March 31,
- --------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 29 $ 26
Interest cost 43 43
Expected return on plan assets (56) (58)
Net amortization and deferral 7 6
- --------------------------------------------------------------------------------------------------------------
Expense under accounting standards 23 17
Regulatory adjustment - deferred (2) --
- --------------------------------------------------------------------------------------------------------------
Total expense recognized $ 21 $ 17
- --------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Edison International previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in Edison
International's 2004 Annual Report that it expects to contribute approximately $77 million to its postretirement benefits other than
pensions plans in 2005. As of March 31, 2005, $6 million in contributions have been made. Edison International anticipates that its
original expectation will be met by year-end 2005.
Expense components are:
Three Months Ended
March 31,
- --------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 12 $ 12
Interest cost 31 34
Expected return on plan assets (26) (28)
Amortization of unrecognized prior service costs (7) (8)
Amortization of unrecognized loss 12 15
- --------------------------------------------------------------------------------------------------------------
Total expense $ 22 $ 25
- --------------------------------------------------------------------------------------------------------------
Note 4. Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings
before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International
believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Aircraft Leases
Edison Capital has invested in three aircraft leased to American Airlines. American has reported very large operating and net losses
due to reduced pricing power, increases in capacity in excess of demand,
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
deeply discounted fare sales and significant increases in fuel prices. In the event American Airlines defaults in making its lease
payments, the lenders with a security interest in the aircraft or leases may exercise remedies that could lead to a loss of some or
all of Edison Capital's investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison Capital in
2005 is $45 million. A restructuring of the lease could also result in a loss of some or all of the investment. At March 31, 2005,
American Airlines was current in its lease payments to Edison Capital.
Environmental Remediation
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 31 identified sites at SCE (25 sites) and EME (6 sites
related to Midwest Generation) is $90 million, $88 million of which is related to SCE. Edison International's other subsidiaries
have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its
recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination;
the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected
to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed
its recorded liability by up to $130 million, all of which is related to SCE. The upper limit of this range of costs was estimated
using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its
identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 30 immaterial sites whose
total liability ranges from $4 million (the recorded minimum liability) to $9 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $34 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $60 million for its estimated minimum
environmental-cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is a lack of currently available information, including
the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing
to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next
several years are expected to range from $12 million to $25 million. Recorded costs for the twelve months ended March 31, 2005 were
$12 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental
remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
Edison International has reached a tentative settlement with the Internal Revenue Service (IRS) on tax issues and pending affirmative
claims relating to its 1991-1993 tax years. This settlement, which was signed by Edison International in March 2005 and is currently
awaiting approval by the United States Congress Joint Committee on Taxation, is expected to result in a net earnings benefit for
Edison International of approximately $70 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. Many of the asserted tax
deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would be
deductible on future tax returns of Edison International.
As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income
taxes in audits of the 1994-1996 and 1997-1999 tax years associated with Edison Capital's cross-border leases. The IRS is
challenging Edison Capital's foreign power plant and electric locomotive sale/leaseback transactions (termed a sale-in/lease-out or
SILO transaction). The estimated federal and state taxes deferred from these leases were $44 million in the 1994-1996 and 1997-1999
audit periods and $32 million in subsequent years through 2004.
The IRS is also challenging Edison Capital's foreign power plant and electric transmission system lease/leaseback transactions
(termed a lease-in, lease-out or LILO transaction). The estimated federal and state income taxes deferred from these leases were
$558 million in the 1997-1999 audit period and $565 million in subsequent years through 2004. The IRS has also proposed interest and
penalties in its challenge to each SILO and LILO transaction.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in
effect at the time the transactions were entered into. Written protests were filed to appeal the 1994-1996 audit adjustments
asserting that the IRS's position misstates material facts, misapplies the law and is incorrect. This matter is now being considered
by the Administrative Appeals branch of the IRS. Edison International also filed protests in March 2005 to appeal the issues raised
in the 1997-1999 audit. Edison International intends to contest these proposed deficiencies through administrative appeals and
litigation, if necessary.
Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (termed a
Service Contract). The IRS did not assert an adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge
this lease in subsequent audit cycles similar to positions asserted against the SILOs discussed above. The estimated federal and
state taxes deferred from this lease are $221 million through 2004.
If Edison International is not successful in its defense of the tax treatment for the SILOs, LILOs and the Service Contract, the
payment of taxes, exclusive of any interest or penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow. However, the FASB is currently considering changes to the accounting for
leases. If the proposed accounting changes are adopted and Edison International's tax treatment for the SILOs, LILOs and Service
Contract is significantly altered as a result of IRS challenges, there could be a material effect on reported earnings by requiring
Edison International to reverse earnings previously recognized as a current period adjustment and to report these earnings over the
remaining life of the leases. At this time, Edison International is unable to predict the impact of the ultimate resolution of these
matters.
The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE
subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability
company. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits
relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these
tax losses are sustained.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the
possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital
leveraged lease transactions and the SCE subsidiary contingent liability company transaction described above. Edison International
filed these amended returns under protest retaining its appeal rights.
Investigations Regarding Performance Incentives Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties for the period of
1997 through 2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and
illness reporting, and system reliability. Current CPUC ratemaking (through SCE's 2003 General Rate Case (GRC) decision) provides
for performance incentives or penalties for differences between actual results and GRC-determined standards of employee injury and
illness reporting, and system reliability.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE has been conducting investigations into its performance under these mechanisms and has reported to the CPUC certain findings of
misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own
proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer
satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose
additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of
refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE's
transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction
surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to
determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE
also anticipated that it could be eligible for customer satisfaction rewards of about $10 million for 2003.
SCE has been keeping the CPUC informed of the progress of SCE's internal investigation. On June 25, 2004, SCE submitted to the CPUC
a PBR customer satisfaction investigation report, which concluded that employees in the design organization of the transmission and
distribution business unit deliberately altered customer contact information in order to affect the results of customer satisfaction
surveys. At least 36 design organization personnel engaged in deliberate misconduct including alteration of customer information
before the data were transmitted to the independent survey company. Because of the apparent scope of the misconduct, SCE proposed to
refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending
that are both attributable to the design organization's portion of the customer satisfaction rewards for the entire PBR period
(1997-2003). In addition, during its investigation, SCE determined that it could not confirm the integrity of the method used for
obtaining customer satisfaction survey data for meter reading. Thus, SCE also proposed to refund all of the approximately $2 million
of customer satisfaction rewards associated with meter reading. As a result of these findings, SCE accrued a $9 million charge in
2004 for the potential refunds of rewards that have been received.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory
personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls
over data collection and processing. The PBR performance incentive mechanism for customer satisfaction expired after calendar year
2003 pursuant to the CPUC's decision in SCE's 2003 GRC.
The CPUC has not yet opened a formal investigative proceeding into this matter. However, the Consumer Protection and Safety Division
(CPSD) of the CPUC has submitted several data requests to SCE and requested an opportunity to interview a number of current and
former SCE employees in the design organization. SCE has responded to these requests and the CPSD has conducted interviews of
approximately 20 employees who were disciplined for misconduct.
Page 20
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE's
employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine
the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received
$20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, would have been entitled to an
additional $15 million for 2001 through 2003 ($5 million for each year).
On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE's performance
under the PBR incentive mechanism for injury and illness reporting. Under the PBR mechanism, rewards and/or penalties for the years
1997 through 2003 were based upon a total incident rate, which included two equally weighted measures: Occupational Safety and
Health Administration (OSHA) recordable incidents and first aid incidents. The major issue disclosed in the investigative findings
to the CPUC was that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid
incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these inaccuracies
did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the PBR mechanism for any year before
2004, and it return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in 2004 for
the potential refund of these rewards. SCE has also proposed to withdraw the pending requests for rewards for the 2001-2002 time
frames. SCE has not yet filed a request related to its performance for 2003 under the PBR mechanism. In SCE's 2003 GRC decision,
the CPUC adopted a modified employee injury and illness performance incentive beginning in 2004. However, SCE has requested that the
CPUC apply that mechanism beginning with recorded data for 2005 so that SCE can correct and validate its baseline data regarding OSHA
recordable injuries and illnesses and improve its OSHA recordkeeping process. If the CPUC were to apply the modified incentive
mechanism to SCE's recorded data for 2004, it would result in a reward of $50,000.
SCE is taking other remedial action to address the issues identified, including revising its organizational structure and overall
program for environmental, health and safety compliance. Additional actions, including disciplinary action against specific
employees identified as having committed wrongdoing, may result once the investigation is completed. SCE submitted a report on the
results of its investigation to the CPUC on December 3, 2004.
As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative proceeding into this matter. However,
the CPSD has recently submitted several data requests to SCE. SCE has responded to these requests.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE has conducted an investigation into the PBR system
reliability metric for the years 1997 through 2003. Since the inception of PBR payments in 1997, SCE has received $8 million in
rewards and has applied for an additional $5 million reward based on frequency of outage data for 2001. For 2002, SCE's data
indicates that it earned no reward and incurred no penalty. Based on the application of the PBR mechanism, SCE would be penalized
$5 million for 2003; however, as indicated above, SCE has not filed a request related to its performance under the PBR mechanism for
2003. In SCE's 2003 GRC, the CPUC adopted a modified
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reliability mechanism beginning in 2004. Based on that modified reliability mechanism, SCE would be penalized $2 million for its
performance in 2004. As a result of SCE's data and calculations, SCE accrued a $6 million charge in 2004 and an additional
$1 million charge in the first quarter of 2005 for these potential penalties.
On February 28, 2005, SCE provided its investigatory report on the PBR system reliability incentive mechanism to the CPUC concluding
that the reliability reporting system is working as intended. On March 30, 2005, SCE filed its advice letter reflecting the
$2 million penalty for 2004 in accordance with the modified reliability mechanism approved by the CPUC in SCE's 2003 GRC.
The CPUC is not expected to act on SCE's recent advice letter for 2004 or the pending PBR advice letters for 2001 and 2002 until the
CPSD has completed its investigation of these matters. SCE has agreed to file its PBR advice letter for 2003 after the CPSD has
completed its investigation.
Navajo Nation Litigation
In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District
Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power
District, and SCE arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,
violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual
relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion, as
well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined
Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C.
District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District's motion
for its separate dismissal from the lawsuit.
Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the
Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the
Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in
the Navajo Nation's lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there
was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for summary judgment in
the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003 motions to dismiss
or, in the alternative, for summary judgment. The D.C. District Court subsequently issued a scheduling order that imposed a
December 31, 2004 discovery cut-off. Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay of
the action to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave.
Negotiations are ongoing and the stay has been continued until further order of the court.
The D.C. Circuit Court, acting on a suggestion on remand filed by the Navajo Nation, held in an October 24, 2003 decision that the
Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations and therefore did not address the
question of whether a network of other
Page 22
statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in
question. The Government and the Navajo Nation both filed petitions for rehearing of the October 24, 2003 D.C. Circuit Court
decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the D.C. Circuit Court issued an order remanding the case
against the Government to the Court of Federal Claims, which conducted a status conference on May 18, 2004. As a result of the
status conference discussion, the Navajo Nation and the Government are in the process of briefing the remaining issues following
remand. As a result of the status conference discussion, the Court of Federal Claims has ordered the Navajo Nation and the
Government to brief the remaining issues following remand. The Navajo Nation's initial brief was filed in the remanded Court of
Federal Claims matter on August 26, 2004, and the Government filed its responsive brief on December 10, 2004. The Navajo Nation
subsequently obtained an extension of the due date for its reply brief while the Court of Federal Claims is considering a motion to
strike filed by the Government. Peabody's motion to intervene in the remanded Court of Federal Claims case as a party was denied.
On February 24, 2005, the Court of Federal Claims denied the motion to strike filed by the Government, but authorized the Government
to file a supplemental brief and appendix, which was filed by the Government on March 23, 2005. On April 25, 2005, the Navajo Nation
filed its reply brief and also filed a motion to strike the Government's supplemental brief and all of the exhibits attached to that
brief.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of the Supreme Court's
decision in the Navajo Nation's suit against the Government on this complaint, or the impact of the complaint on the operation of
Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre Nuclear
Generating Station and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear
incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant
site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San
Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $101 million
per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership
interests, SCE could be required to pay a maximum of $199 million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public
liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal
regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed
reactor operators. All licensed operating plants including San Onofre and Palo Verde are grandfathered under the applicable law.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde.
Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater
than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit
outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear
facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed
retrospective premium adjustments of up to $43 million per year. Insurance premiums are charged to operating expense.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Spent Nuclear Fuel
Under federal law, the United States Department of Energy (DOE) is responsible for the selection and construction of a facility for
the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin
acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear
fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives
and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at
San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to
0.1(cent)-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a
complaint against the DOE in the United States Court of Federal Claims seeking damages for DOE's failure to meet its obligation to
begin accepting spent nuclear fuel from San Onofre. The case is currently stayed pending development in other spent nuclear fuel
cases also before the United States Court of Federal Claims.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored
in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation. Movement of Unit 1
spent fuel from the Unit 2 spent fuel pool to the independent spent fuel storage installation is scheduled to be completed by summer
2005. This move will complete the transfer of all Unit 1 spent fuel on-site to the independent spent fuel storage installation.
Upon completion of this move, there will be sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through
mid-2007 and mid-2008, respectively. In order to maintain a full core off-load capability, SCE is planning to begin moving Unit 2
and 3 spent fuel into the independent spent fuel storage installation by late 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage
facility. Arizona Public Service, as operating agent, plans to continually load casks on a schedule to maintain full core off-load
capability for all three units.
Note 5. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), a nonutility power
generation segment (Mission Energy Holding Company (MEHC) - parent only and EME), and a financial services provider segment (Edison
Capital). Also, in accordance with an accounting standard related to the impairment and disposal of long-lived assets, prior periods
have been restated to reflect EME's international operations being reported as discontinued operations.
Page 24
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information for the three months ended March 31, 2005 and 2004 was:
Three Months Ended
March 31,
- --------------------------------------------------------------------------------------------------------------
In millions 2005 2004
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 1,908 $ 1,696
Nonutility power generation 511 389
Financial services 26 29
Corporate and other 1 2
- --------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,446 $ 2,116
- --------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 131 $ 100
Nonutility power generation(2) 32 6
Financial services(3) 52 11
Corporate and other (14) (20)
- --------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 201 $ 97
- --------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock.
(2) Includes earnings from discontinued operations of $7 million and $46 million, respectively, for the three months ended
March 31, 2005 and 2004.
(3) Includes a loss of $1 million from the cumulative effect of an accounting change for the three months ended March 31, 2004.
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.
Total segment assets as of March 31, 2005 were: electric utility, $24 billion; nonutility power generation, $6 billion; and,
financial services, $4 billion.
Note 6. Discontinued Operations
On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15,
2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately
$20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.
On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to Corporacion IMPSA S.A.,
pursuant to a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a
pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.
On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) to a consortium comprised of
International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, pursuant to a purchase agreement dated July 29,
2004. The purchase agreement was entered into
Page 25
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
following a competitive bidding process. The sale of MECIBV included the sale of EME's interests in ten electric power generating
projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV and related assets
was $2.0 billion.
On September 30, 2004, EME sold its 51% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a purchase
agreement dated July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for
the sale was NZ$1.6 billion (approximately $1.1 billion) which includes NZ$535 million of debt assumed by the purchaser.
EME previously owned and operated a 220-MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the
Lakeland project. The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power
generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU
UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland Power Ltd.
in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement.
Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is
distributed from this entity.
As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination
of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited (TXU Energy), entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy
proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received(pound)112 million (approximately $210 million) from
the TXU administrators, representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately $217 million).
No income related to this payment was recognized during the quarter ended March 31, 2005.
From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of
(pound)20 million (approximately $38 million) to EME on April 7, 2005 comprised of(pound)7 million (approximately $13 million) for a secured loan
which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd.,
and (pound)13 million (approximately $25 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power
Ltd. This amount will be recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay to
EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured
and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland
Power Ltd.'s liquidation.
EME estimates that the net proceeds after tax (including taxes due in the United States) resulting from the above payments will be
approximately $100 million and the increase in net income will be approximately $90 million (including the amounts discussed above
during the second quarter of 2005). These proceeds may be received throughout 2005, and possibly 2006, as Lakeland Power Ltd.'s
liquidation progresses. Because the amounts required to settle outstanding claims and UK taxes have not been finalized and cannot be
estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may vary
materially from the above estimate.
Page 26
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For both periods presented, the results of EME's international projects discussed above have been accounted for as discontinued
operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal
of long-lived assets.
For the three months ended March 31, 2005 and 2004, revenue from discontinued operations was zero and $394 million, respectively, and
pre-tax income was zero and $94 million, respectively.
The carrying value of assets and liabilities recorded as discontinued operations is:
March 31, December 31,
In millions 2005 2004
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
Assets
Cash and equivalents $ 2 $ 2
Other current assets 1 2
- --------------------------------------------------------------------------------------------------------------
Total current assets 3 4
- --------------------------------------------------------------------------------------------------------------
Investments in partnerships and
unconsolidated subsidiaries -- 107
Other deferred charges 10 11
- --------------------------------------------------------------------------------------------------------------
Total assets of discontinued operations $ 13 $ 122
- --------------------------------------------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities $ 2 $ 2
- --------------------------------------------------------------------------------------------------------------
Total current liabilities 2 2
- --------------------------------------------------------------------------------------------------------------
Customer advances and other deferred credits 4 4
Other long-term liabilities 9 9
- --------------------------------------------------------------------------------------------------------------
Total liabilities of discontinued operations $ 15 $ 15
- --------------------------------------------------------------------------------------------------------------
Note 7. Commitments
The following is an update to Edison International's commitments. See Note 9 of "Notes to Consolidated Financial Statements"
included in Edison International's 2004 Annual Report for a detailed discussion.
Leases
During the first quarter of 2005, SCE entered into new power contracts in which it takes virtually all of the power. In accordance
with an accounting standard, these power contracts are classified as operating leases. SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million for 2007 and $43 million for 2008.
Other Commitments
Midwest Generation has entered into additional fuel purchase commitments with various third-party suppliers during the first three
months of 2005. These additional commitments are currently estimated to
Page 27
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be $8 million for 2005, $8 million for 2006, $24 million for 2007, $25 million for 2008, and $53 million for 2009.
Midwest Generation has entered into additional coal transportation commitments during the first three months of 2005. Based on the
committed coal volumes in the fuel supply contracts mentioned above, these additional commitments are currently estimated to be
$16 million for 2005, $15 million for 2006, $38 million for 2007, $37 million for 2008, and $74 million for 2009.
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's purchased power capacity payment
commitments under these contracts are currently estimated to be $69 million for 2005, $95 million for 2006, $101 million for 2007 and
$84 million for 2008.
Guarantees and Indemnities
Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the
normal course of business. As discussed below, these contracts included performance guarantees, guarantees of debt and
indemnifications.
EME's Tax Indemnity Agreements
In connection with the sale-leaseback transactions that EME has entered into related to the Collins Station and the Powerton and
Joliet Stations in Illinois, and the Homer City facilities in Pennsylvania, EME or one of its subsidiaries entered into tax indemnity
agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions
for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including
specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be
significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be
triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the
termination of the Collins Station lease in April 2004, Midwest Generation will continue to have obligations under the tax indemnity
agreement with the former lease equity investor.
Indemnities Provided as Part of EME's Acquisition of the Illinois Plants
In connection with the acquisition of the Illinois plants, EME agreed to indemnify Commonwealth Edison with respect to specified
environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any
insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all
reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this
indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in
term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability
related to this indemnity.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003
to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities
set forth in the asset sale agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison
and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a
sharing arrangement for liabilities and expenses
Page 28
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest
Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth
Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The
supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate).
Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related
settlement, judgment, verdict, or expense. There were between 130 and 170 cases for which Midwest Generation was potentially liable
and that had not been settled and dismissed at March 31, 2005. Midwest Generation has recorded a $68 million liability at March 31,
2005 related to this matter.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Projecting
future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the
numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than
projected.
Indemnity Provided as Part of EME's Acquisition of the Homer City Facilities
In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify
the sellers with respect to specific environmental liabilities before and after the date of sale as specified in the Asset Purchase
Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this
indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. Payments would be
triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.
Indemnities Provided under EME's Asset Sale Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including
indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental
liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a
purported right of first refusal. Not all indemnities under the asset sale agreements have specific expiration dates. Payments
would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At March 31, 2005,
EME has recorded an $85 million liability related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes
imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items
specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the
nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities
under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims
from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.
Guarantee of Brooklyn Navy Yard Contractor Settlement Payments
On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which holds a 50% partnership
interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to
Page 29
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286-MW gas-fired cogeneration power plant in Brooklyn,
New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against
Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to
indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any
payments due under this settlement agreement, which are scheduled through 2006. At March 31, 2005, EME has recorded a $7 million
liability related to this indemnity.
EME's Capacity Indemnification Agreements
EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project
power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements
terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a
reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have
guaranteed the obligations of Kern River Cogeneration Company and Sycamore Cogeneration Company under their project power sales
agreements to repay capacity payments to the projects' power purchaser in the event that the projects unilaterally terminate their
performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the
indemnification agreements as of March 31, 2005, if payment were required, would be $144 million. EME has no reason to believe that
any of these projects will either cease operations or reduce its electric power producing capability during the term of its power
contract. EME has not recorded a liability related to this indemnity.
Indemnity Provided as Part of SCE's Acquisition of Mountainview
In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims
related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the
Mountainview acquisition. The generating station has not operated since early 2001, and SCE retained certain responsibilities with
respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the
purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities
expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.
Note 8. Subsequent Events
On April 20, 2005, SCE issued 4 million shares of Series A preference stock. The proceeds of this issuance are intended to be used
to redeem the outstanding shares of SCE's 7.23% Series preferred stock (approximately $81 million) and SCE's 6.05% Series preferred
stock (approximately $64 million).
On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment
and restatement of Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit
facility had provided for a $700 million first priority secured institutional term loan due in 2011 and a $200 million first priority
secured revolving credit, working capital facility due in 2009.
The refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million
revolving credit, working capital facility due in 2011. The previously existing
Page 30
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital
facility at closing and used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the
paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity date of the repriced term loan remains 2011. The
new working capital facility, together with the existing working capital facility, shares the first lien priority with the repriced
term loan. The new working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital
facility is 2011; however, the lenders can request to be fully repaid in 2010.
On April 19, 2005, EME contributed $300 million in equity to Midwest Generation, and Midwest Generation used the proceeds of this
equity contribution to repay the loans outstanding under the new working capital facility. Thus, after completion of the actions
discussed above, Midwest Generation has $343 million outstanding under its term loan and $500 million of working capital facilities
available for working capital requirements, including credit support for hedging activities. As of April 18, 2005, approximately
$5 million was outstanding under these working capital facilities.
Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as
defined in the credit agreement). In addition, Midwest Generation is permitted to distribute the remaining 25% of excess cash flow
until the amount so distributed totals the $300 million equity contribution (made on April 19, 2005). Furthermore, Midwest
Generation is required to make a concurrent offer to repay debt in an amount equal to one-third of any distribution over the portion
of such distribution allocated to the equity contribution.
Page 31
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
INTRODUCTION
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three-month period ended
March 31, 2005 discusses material changes in the financial condition, results of operations and other developments of Edison
International since December 31, 2004, and as compared to the three-month period ended March 31, 2004. This discussion presumes that
the reader has read or has access to Edison International's MD&A for the calendar year 2004 (the year-ended 2004 MD&A), which was
included in Edison International's 2004 annual report to shareholders and incorporated by reference into Edison International's
Annual Report on Form 10-K for the year ended December 31, 2004.
This MD&A contains forward-looking statements. These statements are based on Edison International's knowledge of present facts,
current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of
performance; they are subject to risks and uncertainties that could cause actual future outcomes and results of operations to be
materially different from those set forth in this discussion. Important factors that could cause actual results to differ are
discussed throughout this MD&A. The following discussion provides updated information about material developments since the issuance
of the year-ended 2004 MD&A and should be read in conjunction with the financial statements contained in this quarterly report and
Edison International's Annual Report on Form 10-K for the year ended December 31, 2004.
Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison
International's principal operating subsidiaries are Southern California Edison Company (SCE), Edison Mission Energy (EME) and Edison
Capital. Mission Energy Holding Company (MEHC) (parent), a subsidiary of Edison International, is the holding company for its wholly
owned subsidiary EME. Since the second quarter of 2004, MEHC (parent) and EME are presented as one business segment on a
consolidated basis due primarily to the elimination of EME's so-called "ring fencing" provisions in EME's certificate of
incorporation and bylaws discussed below under "MEHC: Liquidity--MEHC (parent)'s Liquidity." SCE comprises the largest portion of
the assets and revenue of Edison International. In this MD&A, except when stated to the contrary, references to each of Edison
International, SCE, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to
Edison International (parent) or parent company and MEHC (parent) mean Edison International or MEHC on a stand-alone basis, not
consolidated with its subsidiaries. References to SCE, EME or Edison Capital followed by "(stand alone)" mean each such company
alone, not consolidated with its subsidiaries.
This MD&A is presented in 10 major sections. The MD&A begins with a discussion of current developments. Following is a
company-by-company discussion of Edison International's principal business segments (SCE, MEHC, and Edison Capital) and Edison
International (parent). Each principal business segment's discussion includes discussions of liquidity, market risk exposures, and
other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a
consolidated basis, including results of operations and historical cash flow analysis, discontinued operations, new accounting
principles, commitments, guarantees and indemnities and other developments. These sections should be read in conjunction with the
continuing operations discussion of each principal business segment's section.
Page
----
Current Developments 34
Southern California Edison Company 36
Mission Energy Holding Company 46
Page 32
Edison Capital 64
Edison International (Parent) 65
Results of Operations and Historical Cash Flow Analysis 67
Discontinued Operations 74
New Accounting Principles 75
Commitments, Guarantees and Indemnities 76
Other Developments 77
Page 33
CURRENT DEVELOPMENTS
The following section provides a summary of current developments related to Edison International's principal business segments. This
section is intended to be a summary of those current developments that management believes are of most importance for first quarter
2005. This section is not intended to be an all-inclusive list of all current developments related to each principal business
segment. Further details of each current development discussed below can be found in the specific principal business segment's
section of this MD&A, along with discussions of liquidity, market risk exposures, and other matters as relevant to each principal
business segment.
SCE: CURRENT DEVELOPMENTS
2006 General Rate Case Proceeding
On December 21, 2004, SCE filed its application for a 2006 General Rate Case (GRC), requesting an increase of $370 million in SCE's
2006 base rate revenue, and also requested that the California Public Utilities Commission (CPUC) authorize continuation of SCE's
existing post-test year rate-making mechanism, which would result in base rate revenue increases of $159 million and $122 million in
2007 and 2008, respectively. On April 15, 2005, the Office of Ratepayer Advocates (ORA) submitted testimony recommending that SCE's
2006 base rate revenue requirement be decreased by $93 million, a difference of $463 million. In addition, the ORA is recommending
that an additional year, 2009, be added to SCE GRC cycle and that the CPUC use a Consumer Price Index method to determine base rate
revenue adjustments in the attrition years (2007 and 2008). The ORA's attrition recommendation would raise SCE's 2007 base rate
revenue by $2 million (as opposed to SCE's requested increase of $159 million) and would decrease SCE's 2008 base rate revenue by $10
million (as opposed to SCE's requested increase of $122 million). On May 6, 2005, intervenors submitted testimony on SCE's 2006
GRC. SCE is currently reviewing this testimony. See "SCE: Regulatory Matters--Transmission and Distribution--2006 General Rate Case
Proceeding" for further details.
MEHC: CURRENT DEVELOPMENTS
EME Restructuring Activities
During 2004, EME sold most of its international operations. EME's international operations, except for the Doga project, are
accounted for as discontinued operations in accordance with an accounting standard for the impairment or disposal of long-lived
assets, and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as
discontinued operations. In the first quarter of 2005, EME completed the sale of two international projects:
o EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to CBK Projects B.V., the purchasing entity
designated by its partner, for $104 million.
o EME sold its 25% equity interest in the Tri Energy project to a consortium comprised of International Power plc (70%) and
Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million.
While EME will continue to seek to sell its ownership interest in the Doga project, there is no assurance that such efforts will
result in a sale.
Page 34
In connection with the sale of its international operations in 2004, together with cash on hand, in January 2005, EME:
o made distributions to MEHC totaling $360 million, which were subsequently used primarily to repay the remaining $285 million
portion of the term loan.
o repaid its junior subordinated debentures and, consequently, repaid the monthly income preferred securities (MIPS) of
$150 million.
In April 2005, EME made an equity contribution of $300 million to Midwest Generation, which used the proceeds to repay indebtedness.
See "MEHC: Liquidity --Midwest Generation Financing" for a discussion of the Midwest Generation financing.
EME has also completed a review of its domestic organization to better align its resources with its domestic business requirements.
Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional
management structure. As part of the restructuring, EME expects to reduce annualized costs by $7 million (pre-tax) although this
decrease is expected to be offset by higher development costs in the future. As a result of these changes, EME recorded a charge of
$7 million (pre-tax) in the quarter ended March 31, 2005 for severance and related costs of the changes implemented by that date. EME
expects to record an additional charge of $4 million (pre-tax) during the quarter ended June 30, 2005 associated with completion of
the restructuring steps after March 31, 2005.
Expiration of the Exelon Power-Purchase Agreements and Wholesale Energy Prices
The five-year power-purchase agreements between Midwest Generation and Exelon Generation Company expired on December 31, 2004 and,
accordingly, beginning January 1, 2005, all of the output from the Illinois plants is considered merchant generation. In 2004,
approximately 53% of the energy and capacity sales from the Illinois plants were to Exelon Generation under the power-purchase
agreements.
The Exelon Generation power-purchase agreement for coal-fired units was structured to provide significant capacity payments and lower
energy payments which were primarily designed to reimburse the cost of production. The agreement also provided for substantial
capacity payments during the summer months. In the current wholesale energy market, energy prices are substantially higher than the
energy prices previously set forth in the Exelon Generation power-purchase agreement, but capacity payments are, and are expected to
remain, substantially lower. As a result, the composition of EME's revenue is expected to be significantly different in 2005 compared
to 2004. EME's merchant generation is subject to significant volatility as described further in "MEHC: Market Risk
Exposures--Commodity Price Risk."
Wholesale energy prices at the Northern Illinois Hub (related to the Illinois plants) have increased substantially in 2005 from the
comparable market prices in 2004 driven largely by increases in the market price of natural gas and oil. The average market price during
the first quarter of 2005 at the Northern Illinois Hub (related to the Illinois plants) increased to $39.68 per MWh compared to the
24-hour average market price at "Into ComEd" of $29.51 per MWh during the first quarter of 2004.
Page 35
SOUTHERN CALIFORNIA EDISON COMPANY
SCE: LIQUIDITY
SCE's liquidity is primarily affected by under- or over-collections of energy procurement-related costs, collateral and
mark-to-market requirements associated with power-purchase contracts, and access to capital markets or external financings. At March
31, 2005, SCE's credit and long-term senior secured issuer ratings from Standard & Poor's and Moody's Investors Service were BBB+ and
A3, respectively. At March 31, 2005, SCE's short-term (commercial paper) credit ratings from Standard & Poor's and Moody's Investors
Service were A2 and P2, respectively. As of March 31, 2005, SCE had $290 million in commercial paper outstanding.
As of March 31, 2005, SCE had cash and equivalents of $125 million ($88 million was held by SCE's consolidated Variable Interest
Entities (VIEs)). As of March 31, 2005, long-term debt, including current maturities of long-term debt, was $5.6 billion. As of
March 31, 2005, SCE posted approximately $23 million ($13 million in cash and $10 million in letters of credit) as collateral to
secure its obligations under power-purchase contracts and to transact through the California Independent System Operator (ISO) for
imbalance energy. SCE's collateral requirements can vary depending upon the level of unsecured credit extended by counterparties,
the ISO's credit requirements, changes in market prices relative to contractual commitments, and other factors. In February 2005,
SCE replaced its $700 million credit facility with a $1.25 billion senior secured 5-year revolving credit facility. As of March 31,
2005, SCE's credit facility supported $290 million of commercial paper outstanding and $10 million in letters of credit, leaving $950
million available under its credit facility.
SCE's estimated cash outflows, during the twelve-month period following March 31, 2005, consist of:
o Debt maturities and preferred equity redemptions of approximately $1.1 billion, including approximately $246 million of rate
reduction notes that are due at various times in 2005, but which have a separate cost recovery mechanism approved by state
legislation and CPUC decisions;
o Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct
and replace generation assets;
o Dividend payments to SCE's parent company. On April 28, 2005, SCE made a $71 million dividend payment to Edison
International;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections (if incurred), through
cash and equivalents on hand, operating cash flows and short-term borrowings, when necessary. Projected capital expenditures are
expected to be financed through operating cash flows and the issuance of long-term debt and preferred equity.
SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and
transmission infrastructure, and to construct and replace generation assets. In April 2005, the Finance Committee of SCE's Board of
Directors approved a $10.1 billion capital budget and forecast for the period 2005-2009, an increase of approximately $700 million
over the $9.4 billion amount adopted in October 2004. The increase is mainly due to acceleration of spending into 2005-2009 on
several transmission projects, as well as additional expenditures associated with the replacement of
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the steam generator and pressurizer at the San Onofre Nuclear Generating Station (San Onofre). Pursuant to the approved capital
budget and forecast, SCE expects its capital expenditures to be $1.8 billion, $1.9 billion, and $2.1 billion in 2005, 2006 and 2007,
respectively.
In April 2005, SCE issued 4,000,000 shares Series A Preference Stock (non-cumulative, $100 liquidation value) and received net
proceeds of approximately $394 million. SCE intends to use approximately $81 million of the net proceeds to redeem all of the
outstanding shares of $100 cumulative preferred stock, 7.23% Series; approximately $64 million of the net proceeds to redeem all of
the outstanding shares of $100 cumulative preferred stock, 6.05% Series; and the remainder of the net proceeds for general corporate
purposes.
SCE has debt covenants that require certain interest coverage, interest and preferred dividend coverage, and debt to total
capitalization ratios to be met. At March 31, 2005, SCE was in compliance with these debt covenants.
SCE's liquidity may be affected by, among other things, matters described in "SCE: Regulatory Matters."
SCE: MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, commodity prices and volume, and counterparty credit.
Fluctuations in interest rates can affect earnings and cash flows. However, fluctuations in commodity prices and volumes and
counterparty credit losses temporarily affect cash flows, but should not affect earnings due to recovery through regulatory
mechanisms. SCE uses derivative financial instruments to manage its market risks, but prohibits the use of these instruments for
speculative purposes. See "SCE: Market Risk Exposures" in the year-ended 2004 MD&A for a complete discussion of SCE's market risk
exposures.
SCE: REGULATORY MATTERS
This section of the MD&A describes SCE's regulatory matters in three main subsections:
o generation and power procurement;
o transmission and distribution; and
o other regulatory matters.
Generation and Power Procurement
Energy Resource Recovery Account Proceedings
In an October 2002 decision, the CPUC established the Energy Resource Recovery Account (ERRA) as the rate-making mechanism to track
and recover SCE's: (1) fuel costs related to its generating stations; (2) purchased-power costs related to cogeneration and
renewable contracts; (3) purchased-power costs related to existing interutility and bilateral contracts that were entered into before
January 17, 2001; and (4) new procurement-related costs incurred on or after January 1, 2003 (the date on which the CPUC transferred
back to SCE the responsibility for procuring energy resources for its customers). SCE recovers these costs on a cost-recovery basis,
with no markup for return or profit. SCE files annual forecasts of the above-described costs that it expects to incur during the
following year. As these costs are subsequently incurred, they will be tracked and recovered through the ERRA, but are subject to a
reasonableness review in a separate annual ERRA application. If the ERRA overcollection or
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undercollection exceeds 5% of SCE's prior year's generation revenue, the CPUC has established a "trigger" mechanism, whereby SCE can
request an emergency rate adjustment in addition to the annual forecast and reasonableness ERRA applications.
ERRA Trigger Mechanism Filing
On March 25, 2005, SCE submitted a CPUC rate application under the ERRA trigger mechanism, as the recorded undercollection in its
ERRA balancing account as of February 28, 2005 had reached 9.7% of recorded 2004 generation revenue, well above the 5% threshold for
an emergency rate adjustment established by the CPUC. SCE's undercollection had been less than 4% of recorded 2004 generation
revenue at the end of January 2005. A combination of higher procurement costs, a delay in approval of the 2005 ERRA rate change and
other factors contributed to the large increase in the undercollection amount in February 2005. Nevertheless, SCE's trigger
application requested that the CPUC recognize and retain recently adopted rate levels rather than increasing rates. The application
cited the CPUC's recently approved ERRA rates in the 2005 ERRA forecast proceeding (see below) as compliant with the California
Assembly Bill 57 requirements to promptly amortize the undercollection. The application forecasted amortization of the ERRA
undercollection to below the 5% threshold by the end of July 2005, and amortization to zero by mid-September 2005. Therefore, the
application requested a finding that no further rate action is necessary at this time. A CPUC decision on this application is
expected in May 2005.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA reasonableness review application requesting that the CPUC find its procurement-related
operations for calendar year 2004 to be reasonable. In addition, SCE requested recovery of approximately $13 million associated with
Nuclear Unit Incentive Procedure (NUIP) rewards for efficient operation of the Palo Verde Nuclear Generating Station (Palo Verde) and
approximately $7 million in administrative and general costs incurred to carry out the CPUC's directive to begin procuring energy
supplies on January 1, 2003 following the California energy crisis.
2005 ERRA Forecast
On March 17, 2005, the CPUC issued a final decision adopting SCE's requested ERRA revenue requirement of $3.3 billion for the 2005
calendar year, an increase of $1 billion over the 2004 revenue requirement. The increase was primarily attributable to increasing
procurement costs, in part because SCE must procure additional energy and capacity in 2005 to replace energy and capacity currently
provided by a major California Department of Water Resources (CDWR) contract that terminated in December 2004. In addition, the
increase was attributable to additional capacity and associated energy costs resulting from increasing SCE's reserve margin to
fulfill the CPUC's requirement of a 15% to 17% planning reserve and a substantially higher forecasted ERRA undercollected balance as
of December 31, 2004 than the balance included in current rate levels.
CDWR Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2004 MD&A, in December
2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement for 2004 through 2013, when the last CDWR
contract expires, will be allocated among the investor-owned utilities. San Diego Gas & Electric (SDG&E) has filed a petition for
modification of the decision urging the CPUC to replace the adopted methodology with a methodology that would retain the
cost-follows-contract allocation of the avoidable costs, but would allocate the unavoidable costs associated with the contracts:
42.2% to Pacific Gas and Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. Such an allocation
would decrease the
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total costs allocated to SDG&E's customers and increase the total costs allocated to SCE's customers. The assigned administrative
law judge has issued a draft decision denying the petition, but the draft is potentially subject to revision. The CPUC is expected
to act on the petition by the end of June 2005. Amounts billed to SCE's customers for electric power purchased and sold by the CDWR
are remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no impact on SCE's earnings.
Generation Procurement Proceedings
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in a Southern California
region known as South of Path 15 (SP-15). To enable potential generators to secure financing to construct necessary generation
facilities, SCE has issued a Request for Offers (RFO) for New Generation Resources in SP-15. SCE is soliciting offers for
power-purchase agreements lasting up to 10 years from new generation facilities with delivery under the agreement beginning between
June 1, 2006 and August 1, 2008. SCE will file an application with the CPUC seeking approval of the RFO and the power-purchase
agreements executed under the RFO. SCE will also seek recovery of the costs of the contracts, through the Federal Energy Regulatory
Commission (FERC)-jurisdictional rates, from all SP-15 customers. In addition, SCE will seek CPUC assurance of full cost recovery in
CPUC-approved rates, if the FERC denies any recovery. Any power-purchase agreement that SCE executes as a result of the RFO will be
contingent on CPUC approval of the contract and assurance of full cost recovery.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2004 MD&A, the CPUC issued a
final decision in December 2004 on SCE's application regarding the post-2005 operation of Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant parties in an effort
to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been reached to date. Because resolution has not
been reached and because of the lead times required for installation of certain pollution-control equipment and other upgrades
necessary for post-2005 operation, it is probable that Mohave will shut down for at least several years, and perhaps permanently, at
the end of 2005. The outcome of the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the
presence or absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. The outcome of this
matter is not expected to have a material impact on earnings.
San Onofre Nuclear Generating Station
As discussed in the "San Onofre Nuclear Generating Station" disclosure in the year-ended 2004 MD&A, there are several issues related
to the operation and maintenance of San Onofre Units 2 and 3. The following are new developments with respect to San Onofre.
2005 Outage Schedule, O&M and Capital Budget Disputes
On April 20, 2005, the San Onofre Units 2 and 3 Board of Review (BOR) held a special meeting to consider the 5-year outage schedule,
revisions to the 2005 operation and maintenance (O&M) budget, and the 2005 capital budget. These matters require unanimous approval
of the BOR. The representatives of all owners except SDG&E voted to approve these matters. The representative of SDG&E withheld
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approval of all three matters. SCE and SDG&E agreed to consolidate the disputes over the 2005 O&M and 2005 capital budgets and to
treat the dispute over the 5-year outage schedule as a separate dispute. The parties will proceed with the dispute resolution
procedures in the Second Amended San Onofre Operating Agreement, which culminate in binding arbitration.
Transmission and Distribution
2006 General Rate Case Proceeding
On December 21, 2004, SCE filed its application for a 2006 GRC, requesting an increase of $370 million in SCE's 2006 base rate
revenue, primarily for capital-related expenditures to accommodate infrastructure replacement, customer and load growth. This
increase is also necessary to fund substantially higher operation and maintenance expenses, particularly in SCE's transmission and
distribution business unit. SCE also requested that the CPUC authorize continuation of SCE's existing post-test year rate-making
mechanism, which would result in base rate revenue increases of $159 million and $122 million in 2007 and 2008, respectively. If the
CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the total
increase over current base rates is estimated to be 10%.
On April 15, 2005, the ORA submitted testimony recommending that SCE's 2006 base rate revenue be decreased by $93 million, a
difference of $463 million from SCE's request. In addition, the ORA is recommending that an additional year, 2009, be added to SCE's
GRC cycle and that the CPUC use a Consumer Price Indexed (CPI) method, applied to the test year revenue requirement, to determine
base rate revenue adjustments in the attrition years (2007 and 2008). SCE had used a budget-based approach to projected capital
additions in the attrition years in its filing. This approach was previously authorized in the 2003 GRC decision. The ORA's CPI
methodology would raise SCE's 2007 base rate revenue by $2 million (as opposed to SCE's requested increase of $159 million) and would
decrease SCE's 2008 base rate revenue by $10 million (as opposed to SCE's requested increase of $122 million). Portions of the ORA's
proposed adjustments reflect an updated rate of return, authorized by the CPUC subsequent to the filing of SCE's GRC application. On
May 6, 2005, intervenors submitted testimony on SCE's 2006 GRC. SCE is currently reviewing this testimony. Evidentiary hearings are
scheduled to begin in June 2005. A decision on SCE's 2006 GRC is expected in December 2005 or January 2006.
2006 Cost of Capital
SCE expects to file an application in May 2005 requesting the CPUC to authorize a return on common equity and overall rate of return
for SCE's CPUC-jurisdictional assets for 2006.
ISO Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning and
Riverside, California over the proper allocation and characterization of certain charges. The order reversed an arbitrator's award
that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those
charges to Scheduling Coordinators (SC) in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the
ISO to shift the costs from SCs in the affected zone to the responsible Participating Transmission Owner, SCE, and to do so within
60 days of the April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the Participating
Transmission Owner but also will be credited through the California Power Exchange, SCE's SC at the time. SCE obtained a stay of the
April 20, 2004 order pending resolution of its request for rehearing. On March 30, 2005, the FERC issued an Order Denying
Rehearing. SCE obtained an extension of the stay pending resolution of the appeal SCE has filed with the United States Court of
Appeals for the D.C. Circuit (D.C. Circuit Court).
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The potential net impact on SCE is estimated to be approximately $20 million to $25 million, including interest. Should the April
20, 2004 order stand, SCE expects to receive recovery in rates of the amount described above. SCE filed a request for clarification
with the FERC asking the FERC to clarify that SCE can reflect and recover the disputed costs in SCE's reliability services rates.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in the year-ended 2004 MD&A, SCE is participating in
several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and
natural gas markets.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including SCE, PG&E, the State of
California and various consumer class action representatives) settling various claims stated in proceedings at the FERC and in San
Diego County Superior Court that El Paso had manipulated interstate capacity and engaged in other anticompetitive behavior in the
natural gas markets in order to unlawfully raise gas prices at the California border in 2000-2001. The United States District Court
has issued an order approving the stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC
decision, SCE will refund to customers amounts received under the terms of the El Paso settlement (net of legal and consulting costs)
through its ERRA mechanism. In June 2004, SCE received its first settlement payment of $76 million. Approximately $66 million of
this amount was credited to purchased-power expense, and will be refunded to SCE's ratepayers through the ERRA over the next
12 months, and the remaining $10 million was used to offset SCE's incurred legal costs. El Paso has elected to prepay the additional
settlement payments due over a 20-year period and, as a result, made a payment to the escrow holder on April 15, 2005 of
approximately $442 million. The distribution of these funds to the settling parties will not occur until the superior court judge
presiding over the settlement has issued an order affirming an allocation of these funds to the various settling parties. That order
will likely be issued by mid-May 2005. It is estimated that SCE's share will be approximately $66 million. Amounts El Paso refunds
to the CDWR will result in reductions in the CDWR's revenue requirement allocated to SCE in proportion to SCE's share of the CDWR's
power charge revenue requirement.
On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant Corporation and a
number of its affiliates (collectively Mirant), all of whom are debtors in a Chapter 11 bankruptcy proceeding pending in Texas.
Among other things, the settlement terms provide for expected cash and equivalent refunds totaling $320 million, of which SCE's
allocated share is approximately $68 million. The settlement also provides for an allowed, unsecured claim totaling $175 million in
the bankruptcy of one of the Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual
value of the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant settlement
was approved by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. Under the settlement terms, distribution
of the cash portion of the settlement proceeds is to occur within 20 business days of April 15, 2005 and will be refunded to
ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum Account (ESMA) for
the purpose of recording the foregoing settlement proceeds from energy providers and allocating them in accordance with the terms of
the CPUC litigation settlement agreement. The resolution accordingly provides a mechanism whereby portions of the settlement
proceeds recorded in the ESMA will be allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings
described above and a 10% shareholder incentive pursuant to the CPUC litigation settlement agreement. Remaining amounts for each
settlement are to be refunded to ratepayers through the ERRA mechanism.
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Other Regulatory Matters
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions authorizing utilities to form
holding companies and initiated an investigation into, among other things: (1) whether the holding companies violated CPUC
requirements to give first priority to the capital needs of their respective utility subsidiaries; (2) any additional suspected
violations of laws or CPUC rules and decisions; and (3) whether additional rules, conditions, or other changes to the holding company
decisions are necessary. For a discussion of item (1) above, see the "Holding Company Proceeding" disclosure in the year-ended 2004
MD&A.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed the proceeding without
addressing some of the issues the proceeding raised (such as the appropriateness of the large utilities' holding company structure
and dividend policies), the CPUC may rule on or investigate these issues in the future.
Investigations Regarding Performance Incentive Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties for the period of
1997 through 2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and
illness reporting, and system reliability. Current CPUC ratemaking (through SCE's 2003 GRC decision) provides for performance
incentives or penalties for differences between actual results and GRC-determined standards of employee injury and illness reporting,
and system reliability.
SCE has been conducting investigations into its performance under these mechanisms and has reported to the CPUC certain findings of
misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own
proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer
satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose
additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of
refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE's
transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction
surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to
determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded
aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE
also anticipated that it could be eligible for customer satisfaction rewards of about $10 million for 2003.
SCE has been keeping the CPUC informed of the progress of SCE's internal investigation. On June 25, 2004, SCE submitted to the CPUC
a PBR customer satisfaction investigation report, which concluded that employees in the design organization of the transmission and
distribution business unit deliberately altered customer contact information in order to affect the results of customer satisfaction
surveys. At least 36 design organization personnel engaged in deliberate misconduct including alteration of customer information
before the data were transmitted to the independent survey company. Because of the
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apparent scope of the misconduct, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an
additional $5 million of the PBR rewards pending that are both attributable to the design organization's portion of the customer
satisfaction rewards for the entire PBR period (1997-2003). In addition, during its investigation, SCE determined that it could not
confirm the integrity of the method used for obtaining customer satisfaction survey data for meter reading. Thus, SCE also proposed
to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading. As a result of these
findings, SCE accrued a $9 million charge in 2004 for the potential refunds of rewards that have been received.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory
personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls
over data collection and processing. The PBR performance incentive mechanism for customer satisfaction expired after calendar year
2003 pursuant to the CPUC's decision in SCE's 2003 GRC.
The CPUC has not yet opened a formal investigative proceeding into this matter. However, the Consumer Protection and Safety Division
(CPSD) of the CPUC has submitted several data requests to SCE and requested an opportunity to interview a number of current and
former SCE employees in the design organization. SCE has responded to these requests and the CPSD has conducted interviews of
approximately 20 employees who were disciplined for misconduct.
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE's
employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine
the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received
$20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, would have been entitled to an
additional $15 million for 2001 through 2003 ($5 million for each year).
On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE's performance
under the PBR incentive mechanism for injury and illness reporting. Under the PBR mechanism, rewards and/or penalties for the years
1997 through 2003 were based upon a total incident rate, which included two equally weighted measures: Occupational Safety and
Health Administration (OSHA) recordable incidents and first aid incidents. The major issue disclosed in the investigative findings
to the CPUC was that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid
incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these inaccuracies
did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the PBR mechanism for any year before
2004, and it return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in 2004 for
the potential refund of these rewards. SCE has also proposed to withdraw the pending requests for rewards for the 2001-2002 time
frames. SCE has not yet filed a request related to its performance for 2003 under the PBR mechanism. In SCE's 2003 GRC decision,
the CPUC adopted a modified employee injury and illness performance incentive beginning in 2004. However, SCE has requested that the
CPUC apply that mechanism beginning with recorded data for 2005 so that SCE can correct and validate its baseline data regarding OSHA
recordable injuries and illnesses and improve its OSHA recordkeeping process. If the CPUC were to apply the modified incentive
mechanism to SCE's recorded data for 2004, it would result in a reward of $50,000.
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SCE is taking other remedial action to address the issues identified, including revising its organizational structure and overall
program for environmental, health and safety compliance. Additional actions, including disciplinary action against specific
employees identified as having committed wrongdoing, may result once the investigation is completed. SCE submitted a report on the
results of its investigation to the CPUC on December 3, 2004.
As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative proceeding into this matter. However,
the CPSD has recently submitted several data requests to SCE. SCE has responded to these requests.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE has conducted an investigation into the PBR system
reliability metric for the years 1997 through 2003. Since the inception of PBR payments in 1997, SCE has received $8 million in
rewards and has applied for an additional $5 million reward based on frequency of outage data for 2001. For 2002, SCE's data
indicates that it earned no reward and incurred no penalty. Based on the application of the PBR mechanism, SCE would be penalized
$5 million for 2003; however, as indicated above, SCE has not filed a request related to its performance under the PBR mechanism for
2003. In SCE's 2003 GRC, the CPUC adopted a modified reliability mechanism beginning in 2004. Based on that modified reliability
mechanism, SCE would be penalized $2 million for its performance in 2004. As a result of SCE's data and calculations, SCE accrued a
$6 million charge in 2004 and an additional $1 million charge in the first quarter of 2005 for these potential penalties.
On February 28, 2005, SCE provided its investigatory report on the PBR system reliability incentive mechanism to the CPUC concluding
that the reliability reporting system is working as intended. On March 30, 2005, SCE filed its advice letter reflecting the $2
million penalty for 2004 in accordance with the modified reliability mechanism approved by the CPUC in SCE's 2003 GRC.
The CPUC is not expected to act on SCE's recent advice letter for 2004 or the pending PBR advice letters for 2001 and 2002 until the
CPSD has completed its investigation of these matters. SCE has agreed to file its PBR advice letter for 2003 after the CPSD has
completed its investigation.
SCE: OTHER DEVELOPMENTS
Navajo Nation Litigation
In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District
Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power
District, and SCE arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,
violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual
relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion, as
well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined
Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C.
District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District's motion
for its separate dismissal from the lawsuit.
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Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the
Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the
Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in
the Navajo Nation's lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there
was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for summary judgment in
the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and Peabody's April 2003 motions to dismiss
or, in the alternative, for summary judgment. The D.C. District Court subsequently issued a scheduling order that imposed a
December 31, 2004 discovery cut-off. Pursuant to a joint request of the parties, the D.C. District Court granted a 120-day stay of
the action to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave.
Negotiations are ongoing and the stay has been continued until further order of the court.
The D.C. Circuit Court, acting on a suggestion on remand filed by the Navajo Nation, held in an October 24, 2003 decision that the
Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations and therefore did not address the
question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the
United States during the time period in question. The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the D.C. Circuit
Court issued an order remanding the case against the Government to the Court of Federal Claims, which conducted a status conference
on May 18, 2004. As a result of the status conference discussion, the Navajo Nation and the Government are in the process of
briefing the remaining issues following remand. As a result of the status conference discussion, the Court of Federal Claims has
ordered the Navajo Nation and the Government to brief the remaining issues following remand. The Navajo Nation's initial brief was
filed in the remanded Court of Federal Claims matter on August 26, 2004, and the Government filed its responsive brief on December
10, 2004. The Navajo Nation subsequently obtained an extension of the due date for its reply brief while the Court of Federal Claims
is considering a motion to strike filed by the Government. Peabody's motion to intervene in the remanded Court of Federal Claims
case as a party was denied. On February 24, 2005, the Court of Federal Claims denied the motion to strike filed by the Government,
but authorized the Government to file a supplemental brief and appendix, which was filed by the Government on March 23, 2005. On
April 25, 2005, the Navajo Nation filed its reply brief and also filed a motion to strike the Government's supplemental brief and all
of the exhibits attached to that brief. The Government has not yet responded to the motion to strike.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of the Supreme Court's
decision in the Navajo Nation's suit against the Government on this complaint, or the impact of the complaint on the operation of
Mohave beyond 2005.
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MISSION ENERGY HOLDING COMPANY
MEHC: LIQUIDITY
Introduction
MEHC's liquidity discussion is organized in the following sections:
o MEHC (parent)'s Liquidity
o EME's Liquidity
o Midwest Generation Financing
o Capital Expenditures
o EME's Credit Ratings
o EME's Liquidity as a Holding Company
o Dividend Restrictions in Major Financings
o MEHC's Interest Coverage Ratio
MEHC (parent)'s Liquidity
At March 31, 2005, MEHC (parent) had cash and cash equivalents of $2 million (excluding amounts held by EME and its subsidiaries).
MEHC (parent)'s ability to honor its obligations under the senior secured notes and to pay overhead is substantially dependent upon
the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and ultimately
Edison International. See "MEHC: Liquidity--EME's Liquidity as a Holding Company--Intercompany Tax-Allocation Agreement." Dividends
from EME are limited based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility,
business and tax considerations and restrictions imposed by applicable law.
Dividends to MEHC (parent)
In January 2005, EME made total dividend payments of $360 million to MEHC (parent). A portion of these payments was used to repay the
remaining $285 million of the term loan plus interest on January 3, 2005.
EME's Liquidity
At March 31, 2005, EME and its subsidiaries had cash and cash equivalents of $2.0 billion and EME had available the full amount of
borrowing capacity under a $98 million corporate credit facility. EME's consolidated debt at March 31, 2005 was $3.5 billion. In
addition, EME's subsidiaries had $5.0 billion of long-term lease obligations that are due over periods ranging up to 30 years.
Midwest Generation Financing
On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and
restatement of Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility
had provided for a $700 million first priority secured institutional term loan due in 2011 and a $200 million first priority secured
revolving credit, working capital facility due in 2009.
The refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million
revolving credit, working capital facility due in 2011. The previously existing
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$200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital
facility at closing and used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the
paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity date of the repriced term loan remains 2011. The new
working capital facility, together with the existing working capital facility, shares first lien priority with the repriced term
loan. The new working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital
facility is 2011; however, the lenders can request to be fully repaid in 2010.
On the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and
Midwest Generation used the proceeds of this equity contribution to repay the loans outstanding under the new working capital
facility. Thus, after completion of the actions outlined herein, Midwest Generation has $343 million outstanding under its term loan
and $500 million of working capital facilities available for working capital requirements, including credit support for hedging
activities. As of April 18, 2005, approximately $5 million was outstanding under these working capital facilities.
Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as
defined in the credit agreement). In addition, Midwest Generation is permitted to distribute the remaining 25% of excess cash flow
until the amount so distributed totals the $300 million equity contribution (made on April 19, 2005). Furthermore, Midwest
Generation is required to make a concurrent offer to repay debt in an amount equal to one-third of any distribution over the portion
of such distribution allocated to the equity contribution.
Capital Expenditures
The estimated capital and construction expenditures of EME's subsidiaries are $65 million for the final three quarters of 2005 and
$20 million and $24 million for 2006 and 2007, respectively. Non-environmental expenditures relate to upgrades to dust
collection/mitigation systems and the coal handling system, ash removal improvements and component replacement projects. These
expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from their
operations. Included in the estimated expenditures are environmental expenditures of $18 million for 2005 and $1 million for 2006. In
late 2004, Midwest Generation returned Will County Units 1 and 2 to service. As part of returning these units to service, Midwest
Generation expects to install environmental improvements of approximately $5 million in 2005. In addition, Homer City plans to spend
approximately $13 million in 2005 related to environmental selective catalytic reduction system improvements on all three units.
EME's Credit Ratings
Overview
Credit ratings for EME and its subsidiaries, Midwest Generation, LLC and Edison Mission Marketing & Trading, are as follows:
Moody's Rating S&P Rating
- ---------------------------------------------------------------------------------
EME B1 B+
Midwest Generation, LLC:
First priority senior secured rating Ba3 BB-
Second priority senior secured rating B1 B
Edison Mission Marketing & Trading Not Rated B+
- ---------------------------------------------------------------------------------
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On March 17, 2005, Standard & Poor's raised the credit ratings of EME and Edison Mission Marketing & Trading to B+ from B. Standard
& Poor's also raised Midwest Generation's first priority senior secured rating to BB- from B+ and its second priority senior secured
rating to B from B-. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will
remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit
ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EME does not have any "rating triggers" contained in subsidiary financings that would result in EME being required to make equity
contributions or provide additional financial support to its subsidiaries.
The credit ratings of EME are below investment grade and, accordingly, EME has historically provided collateral in the form of cash
and letters of credit for the benefit of counterparties for its price risk management and trading activities related to accounts
payable and unrealized losses. Midwest Generation provides credit support for forward contracts entered into by Edison Mission
Marketing & Trading related to the Illinois plants.
Edison Mission Marketing & Trading has provided credit for the benefit of counterparties in the form of cash and letters of credit
($199 million as of March 31, 2005) for EME's price risk management and domestic trading activities (including Midwest Generation and
Homer City) related to accounts payable and unrealized losses.
EME expects to have higher merchant generation in 2005 than in previous years, as a result of the expiration in 2004 of the
power-purchase agreements between Midwest Generation and Exelon Generation. The increased merchant generation will increase the
potential for margin and collateral requirements. Changes in forward market prices and the strategies adopted for merchant generation
could further increase the need for credit support for price risk management activities related to EME's projects. Using common
industry analytics, EME estimates that total margin and collateral requirements to support price risk management could increase to
approximately $400 million in 2005 if 50% of merchant generation from the Illinois plants and Homer City facilities is sold forward
for one year and power prices subsequently increased. Midwest Generation is expected to have cash on hand and $500 million of working
capital facilities that can be used to provide credit support for forward contracts entered into on behalf of the Illinois plants. As
of April 18, 2005, approximately $5 million was outstanding under these facilities. In addition, EME is expected to have cash on hand
and a $98 million working capital facility that can be used to provide credit support for its subsidiaries. See "MEHC:
Liquidity--EME's Liquidity" for further discussion.
Credit Rating of Edison Mission Marketing & Trading
The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer City's) ability to enter into trading
activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City
facilities if Edison Mission Marketing & Trading does not have an investment grade credit rating from Standard & Poor's or Moody's
or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures.
These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an
unaffiliated third party, be investment grade. EME currently sells all 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
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obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified
conditions, through December 31, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the
consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that
it intends to revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent
would not affect trades between Edison Mission Marketing & Trading and EME Homer City that had been entered into while the consent
was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "MEHC:
Market Risk Exposures--Commodity Price Risk--Energy Price Risk Affecting Sales from the Homer City Facilities."
EME's Liquidity as a Holding Company
Overview
At March 31, 2005, EME had corporate cash and cash equivalents of $1.6 billion to meet liquidity needs. See "MEHC: Liquidity--EME's
Liquidity." EME had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at March 31,
2005. Cash distributions from EME's subsidiaries and partnership investments, and unused capacity under its corporate credit facility
represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's
subsidiaries may be affected by many factors beyond its control. See "MEHC: Liquidity--Dividend Restrictions in Major Financings."
EME's secured corporate credit facility provides credit available in the form of cash advances or letters of credit. In addition to
the interest payments, EME pays a commitment fee of 0.50% on the unutilized portion of the facility. EME has agreed to maintain a
minimum interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the credit
agreement). At March 31, 2005, EME met both these ratio tests.
As security for its obligations under its new corporate credit facility, EME pledged its ownership interests in the holding companies
through which it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project.
EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be
deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.
At March 31, 2005, EME also had available $70 million under Midwest Generation EME, LLC's $100 million letter of credit facility with
Citibank, N.A., as Issuing Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation
EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be outstanding under
the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings,
which in turn owns 100% of Midwest Generation, LLC.
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Historical Domestic Distributions Received By EME
The following table is presented as an aid in understanding the cash flow of EME's domestic operations and its various subsidiary
holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and debt
service costs of recourse debt.
In millions Three Months Ended March 31, 2005 2004
- -----------------------------------------------------------------------------------------------------------------
Distributions from Consolidated Operating Projects:
Edison Mission Midwest Holdings (Illinois plants)(1) $ 62 $ --
EME Homer City Generation L.P. (Homer City facilities) 24 41
Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects)(2) 29 21
Holding companies for Westside projects 3 3
Holding companies of other unconsolidated operating projects 3 1
- -----------------------------------------------------------------------------------------------------------------
Total Distributions $ 121 $ 66
- -----------------------------------------------------------------------------------------------------------------
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(1) On April 26, 2005, EME received a $109 million distribution from Midwest Generation.
(2) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and
Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy
Funding Corp.
Intercompany Tax-Allocation Agreement
MEHC (parent) and EME are included in the consolidated federal and combined state income tax returns of Edison International and are
eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic
tax losses are incurred. The right of MEHC (parent) and EME to receive and the amount and timing of tax-allocation payments is
dependent on the inclusion of MEHC (parent) and EME, respectively, in the consolidated income tax returns of Edison International and
its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the
amount of net operating losses and other tax items of MEHC (parent), EME, its subsidiaries, and other subsidiaries of Edison
International and specific procedures regarding allocation of state taxes. MEHC (parent) and EME receive tax-allocation payments for
tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be
able to utilize MEHC (parent)'s tax losses or the tax losses of EME in the consolidated income tax returns for Edison International
and its subsidiaries. Based on the application of the factors cited above, MEHC (parent) and EME are obligated during periods they
generate taxable income to make payments under the tax-allocation agreements.
Dividend Restrictions in Major Financings
General
Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries.
Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries.
However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of
financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to
its subsidiary holding companies.
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Key Ratios of EME's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EME's principal subsidiaries for the twelve months ended March 31, 2005:
Subsidiary Financial Ratio Covenant Actual
- --------------------------------------------------------------------------------------------------------------
Midwest Generation, LLC Interest Coverage Greater than or 3.15 to 1(1)
(Illinois plants) Ratio equal to 1.25 to 1
Midwest Generation, LLC Secured Leverage Less than or 4.24 to 1
(Illinois plants) Ratio equal to 8.75 to 1
EME Homer City Senior Rent Service Greater than 1.7 to 1 2.56 to 1
Generation L.P. Coverage Ratio
(Homer City facilities)
Edison Mission Energy Debt Service Greater than or 2.91 to 1
Funding Corp. Coverage Ratio equal to 1.25 to 1
(Big 4 Projects)
- ---------------------------------------------------------------------------------------------------------------
--------------
(1) Interest coverage ratio was computed on a pro forma basis assuming the credit facility had been
in existence for a 12-month period.
For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities
to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "MEHC: Liquidity:
Dividend Restrictions in Major Financings" in the year-ended 2004 MD&A.
MEHC's Interest Coverage Ratio
The following details with respect to MEHC's interest coverage ratio are provided as an aid to understanding the computations set
forth in the indenture governing MEHC's senior secured notes. This information is not intended to measure the financial performance
of MEHC and, accordingly, should not be read in lieu of the financial information set forth in MEHC's consolidated financial
statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture and are
not the same as would be determined in accordance with generally accepted accounting principles.
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MEHC's interest coverage ratio equals Funds Flow from Operations divided by Interest Expense and is comprised of interest income and
expense related to its holding company activities and the consolidated financial information of EME. The following table sets forth
MEHC's interest coverage ratio for the twelve months ended March 31, 2005 and the year ended December 31, 2004:
March 31, December 31,
In millions 2005 2004
--------------------------------------------------------------------- --------------------- --------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating
Projects(2):
Illinois plants $ 296 $ 214
Homer City 119 95
First Hydro 25 48
Other consolidated operating projects 82 128
Price risk management and energy trading 25 1
Distributions from unconsolidated Big 4 projects 116 108
Distributions from other unconsolidated operating
projects 126 131
Interest income 18 8
Operating expenses (157) (167)
--------------------------------------------------------------------- --------------------- --------------------
Total EME funds flow from operations $ 650 $ 566
Operating cash flow from unrestricted subsidiaries -- 1
Funds flow from operations of projects sold (132) (195)
MEHC (parent) (2) (2)
--------------------------------------------------------------------- --------------------- --------------------
Total funds flow from operations $ 516 $ 370
Interest Expense:
EME $ 263 $ 265
EME - affiliate debt 2 1
MEHC (parent) interest expense 146 158
Interest savings on projects sold (100) (110)
--------------------------------------------------------------------- --------------------- --------------------
Total interest expense $ 311 $ 314
--------------------------------------------------------------------- --------------------- --------------------
Interest Coverage Ratio 1.66 1.18
--------------------------------------------------------------------- --------------------- --------------------
--------------
(1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid and project debt service. Operating
cash flow does not include capital expenditures or the difference between cash payments under EME's long-term leases and
lease expenses recorded in EME's income statement. EME expects its cash payments under its long-term power plant leases to
be higher than its lease expense through 2014.
(2) Consolidated operating projects are entities of which EME owns more than a 50% interest and, thus, include the operating
results and cash flows in its consolidated financial statements. Unconsolidated operating projects are entities of which
EME owns 50% or less and which EME accounts for on the equity method or EME is not the primary beneficiary under a new
accounting interpretation for variable interest entities.
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's
senior secured notes. The interest coverage ratio prohibits MEHC, EME and its subsidiaries from incurring additional indebtedness,
except as specified in the indenture and the financing documents, unless MEHC's interest coverage ratio exceeds 2.0 to 1 for the
immediately preceding four fiscal quarters.
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MEHC: MARKET RISK EXPOSURES
Introduction
EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted
generating plants. These market risks arise from fluctuations in electricity and fuel prices, emission allowances, transmission
rights, interest rates and foreign currency exchange rates. EME manages these risks in part by using derivative financial instruments
in accordance with established policies and procedures. See "MEHC: Liquidity--EME's Credit Ratings" for a discussion of market
developments and their impact on EME's credit and the credit of its counterparties.
This section discusses these market risk exposures under the following headings:
o Commodity Price Risk
o Credit Risk
o Interest Rate Risk
o Fair Value of Financial Instruments
Commodity Price Risk
General Overview
EME's revenue and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy,
ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market
areas where EME's merchant plants are located. Among the factors that influence the price of power in these markets are:
o prevailing market prices for coal, natural gas and fuel oil, and associated transportation costs;
o the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market
entrants, including the development of new generation facilities;
o transmission congestion in and to each market area;
o the market structure rules to be established for each market area and regulatory developments affecting the market areas;
o the cost and availability of emission credits or allowances;
o the availability, reliability and operation of nuclear generating plants, where applicable, and the extended operation of
nuclear generating plants beyond their presently expected dates of decommissioning;
o weather conditions prevailing in surrounding areas from time to time; and
o the rate of electricity usage as a result of factors such as regional economic conditions and the implementation of
conservation programs.
A discussion of commodity price risk for the Illinois plants and Homer City facilities is set forth below.
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Energy Price Risk - Introduction
Electric power generated at EME's merchant plants is generally sold under bilateral arrangements with utilities and power marketers
under short-term transactions with terms of two years or less or to the PJM Interconnection, LLC (PJM) and/or the New York
Independent System Operator (NYISO) markets. As discussed further below, beginning in 2003, EME has been selling a significant
portion of the power generated from its Illinois plants into wholesale power markets, including PJM since May 1, 2004.
EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in
the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure
compliance with EME's risk management policies. Policies are in place which define risk tolerance, and procedures exist which allow
for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be
no assurance that all risks have been accurately identified, measured and/or mitigated.
In addition to the prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the
cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and,
accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary from unit
to unit.
EME performs a "value at risk" analysis in its daily business to identify, measure, monitor and control its overall market risk
exposure in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk allows
management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk
measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the
inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of
stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure
limits.
Hedging Strategy
EME intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. To the extent that EME does
not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. The
extent to which EME will hedge its market price risk through forward over-the-counter sales depends on several factors. First, EME
will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared
to assuming the risk associated with spot market sales. Second, EME's ability to enter into hedging transactions will depend upon
its, Midwest Generation's and Edison Mission Marketing & Trading's credit capacity and upon the over-the-counter forward sales
markets having sufficient liquidity to enable EME to identify counterparties who are able and willing to enter into hedging
transactions. In the case of forward sales of generation and capacity from the Illinois plants, Midwest Generation is permitted to
use its new working capital facility and cash on hand to provide credit support for forward contracts entered into by Edison Mission
Marketing & Trading for capacity and energy generation of the Illinois plants under an energy services agreement between the Midwest
Generation and Edison Mission Marketing & Trading. Utilization of this credit facility in support of such forward contracts is
expected to provide additional liquidity support for implementation of EME's contracting strategy for the Illinois plants. In the
case of forward sales of generation and capacity from the Homer City facilities, credit support is provided by EME pursuant to
intercompany arrangements between it and Edison Mission Marketing & Trading. See "--Credit Risk," below.
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Energy Price Risk Affecting Sales from the Illinois Plants
Pre-2005 Merchant Sales
Energy generated at the Illinois plants was historically sold under three power-purchase agreements between Midwest Generation and
Exelon Generation Company, under which Exelon Generation was obligated to make capacity payments for the plants under contract and
energy payments for the energy produced by these plants and taken by Exelon Generation. The power-purchase agreements began on
December 15, 1999. The capacity payments provided the units under contract with revenue for fixed charges, and the energy payments
compensated those units for all, or a portion of, variable costs of production. The three power-purchase agreements with Exelon
Generation had all been terminated by December 31, 2004.
To the extent that energy and capacity from the Illinois plants was not sold under the power-purchase agreements with Exelon
Generation, it was sold on a wholesale basis through a combination of bilateral agreements, forward energy sales and spot market
sales. Approximately 60% of the energy and capacity sales from the Illinois plants in the first quarter of 2004 were made on a
wholesale basis outside of the power-purchase agreements.
Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants
were direct "wholesale customers" and broker arranged "over-the-counter customers." During this period, the most liquid
over-the-counter markets in the Midwest region were for sales into the control area of Cinergy (which, as of April 1, 2005, became a
locational marginal pricing location in the Midwest Independent Transmission System Operator, or MISO) and, to a lesser extent, for
sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP,"
respectively. "Into ComEd" and "Into AEP" were bilateral markets for the sale or purchase of electrical energy for future delivery.
Due to geographic proximity, "Into ComEd" was the primary market for Midwest Generation.
Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois
control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, which linked eastern PJM and the
Northern Illinois control areas of the PJM system and improved access from the Illinois plants into the broader PJM market. Under the
PJM tariff, Midwest Generation is no longer required to arrange and pay separately for transmission when making sales to wholesale
buyers located within the PJM system.
Following the expansion of the PJM system described above, sales of electricity from the Illinois plants have been made on the basis
of bilateral and spot sales into PJM, with spot sales being based on locational marginal pricing. These sales into the expanded PJM,
the primary market currently available to the Illinois plants, replaced sales previously made as bilateral sales and spot sales "Into
ComEd" and "Into AEP." See "MEHC: Other Development--Regulatory Matters" in the year-ended 2004 MD&A.
2005 Merchant Sales
Beginning on January 1, 2005, electric power generated at the Illinois plants is sold under bilateral arrangements with domestic
utilities and power marketers pursuant to transactions which generally have terms of two years or less, or to the PJM market. The PJM
pool has a short-term market, which establishes an hourly clearing price. The Illinois plants are situated in the new expanded
western PJM control area and are physically connected to high-voltage transmission lines serving this market.
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The following table depicts the average historical market prices for energy per megawatt-hour as quoted for sales into the Northern
Illinois Hub for the first three months of 2005.
24-Hour
Historical Energy Prices* Northern Illinois Hub
----------------------------------------------------------
January $ 38.36
February 34.92
March 45.75
----------------------------------------------------------
Quarterly Average $ 39.68
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--------------
* Energy prices calculated at the Northern Illinois Hub delivery point using
hourly real-time prices as published by PJM. There is no comparison for the
same months in 2004.
For comparison with 2004, the following table depicts the average historical market prices for energy per megawatt-hour "Into ComEd"
for the first three months of 2004. See discussion under "--Pre-2005 Merchant Sales" above for further discussion regarding the
replacement of sales "Into ComEd" with sales into the expanded PJM.
Into ComEd*
----------------------------------------
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr
------------------------------------------------------------------------
January $ 43.30 $ 15.18 $ 27.88
February 43.05 18.85 29.98
March 40.38 21.15 30.66
------------------------------------------------------------------------
Quarterly Average $ 42.25 $ 18.39 $ 29.51
------------------------------------------------------------------------
--------------
(1) On-peak refers to the hours of the day between 6:00 a.m. and 10:00 p.m. Monday through Friday,
excluding North American Electric Reliability Council (NERC) holidays. All other hours of the week
are referred to as off-peak.
* Source: Energy prices were determined by obtaining broker quotes and other price information from
public sources, for "Into ComEd" delivery points.
Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices,
transmission congestion, changes in market rules, electricity demand which is affected by weather and economic growth, plant outages
in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the
Illinois plants into these markets may vary materially from the forward market prices set forth in the table below.
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The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois
Hub at March 31, 2005:
24-Hour
Northern Illinois Hub
2005 Forward Energy Prices*
- -----------------------------------------------------------------------------
April $ 38.72
May 37.89
June 40.68
July 49.00
August 50.20
September 38.38
October 35.36
November 36.78
December 39.27
2006 Calendar "strip"(1) $ 41.49
- -----------------------------------------------------------------------------
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(1) Market price for energy purchases for the entire calendar year, as quoted for sales into the
Northern Illinois Hub.
* Energy prices were determined by obtaining broker quotes and other price information from public
sources for the Northern Illinois Hub delivery point.
The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at
March 31, 2005:
2005 2006
---------------------------------------------------------------------------------------
Megawatt hours 12,550,055 1,641,654
Average price/MWh(1) $ 38.58 $ 35.84
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(1) The above hedge positions include forward contracts for the sale of power during different periods of the
year and the day. Market prices tend to be higher during on-peak periods during the day and during summer
months, although there is significant variability of power prices during different periods of time.
Accordingly, the above hedge position at March 31, 2005 is not directly comparable to the 24-hour Northern
Illinois Hub prices set forth above.
Energy Price Risk Affecting Sales from the Homer City Facilities
Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power
marketers pursuant to transactions with terms of two years or less, or to the PJM or the NYISO markets. These pools have short-term
markets, which establish an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically
connected to high-voltage transmission lines serving both the PJM and NYISO markets.
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The following table depicts the average historical market prices for energy per megawatt-hour in PJM during the first three months of
2005 and 2004:
24-Hour PJM
Historical Energy Prices*
-----------------------------
2005 2004
- -----------------------------------------------------------------------
January $ 45.82 $ 51.12
February 39.40 47.19
March 47.42 39.54
- -----------------------------------------------------------------------
Quarterly Average $ 44.21 $ 45.95
- -----------------------------------------------------------------------
--------------
* Energy prices were calculated at the Homer City busbar (delivery point) using historical hourly real-time prices
provided on the PJM-ISO web-site.
Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission
congestion, changes in market rules, electricity demand which is affected by weather and economic growth, plant outages in the
region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Homer
City facilities into these markets may vary materially from the forward market prices set forth in the table below.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at
March 31, 2005:
24-Hour PJM West Hub
2005 Forward Energy Prices*
- -----------------------------------------------------------------------------
April $ 46.24
May 48.00
June 51.14
July 61.30
August 63.26
September 50.14
October 48.98
November 49.30
December 48.98
2006 Calendar "strip"(1) $ 53.07
- -----------------------------------------------------------------------------
--------------
(1) Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM
West Hub.
* Energy prices were determined by obtaining broker quotes and other public sources for the PJM West
Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer
City busbar.
Page 58
The following table summarizes Homer City's hedge position at March 31, 2005:
2005
-----------------------------------------------------------
Megawatt hours 6,797,125
Average price/MWh(1) $ 45.21
-----------------------------------------------------------
--------------
(1) The above hedge positions include forward contracts for the sale of power during different periods
of the year and the day. Market prices tend to be higher during on-peak periods during the day and
during summer months, although there is significant variability of power prices during different
periods of time. Accordingly, the above hedge position at March 31, 2005 is not directly comparable
to the 24-hour PJM West Hub prices set forth above.
The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy prices at the PJM West Hub have averaged 5%
higher than energy prices at the Homer City busbar during the past twelve months. See "--Basis Risk" below for a discussion of the
difference.
Basis Risk
Sales made from the Illinois plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices
at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the
individual plant busbars, EME may enter into forward contracts with counterparties for energy to be delivered in future periods.
Currently, there is not a liquid market for entering into forward contracts at the individual plant busbars. A liquid market does
exist for a delivery point known as the PJM West Hub in the case of Homer City and for a delivery point known as the Northern
Illinois Hub in the case of the Illinois plants. EME's price risk management activities use these delivery points to enter into
forward contracts. EME's revenue with respect to such forward contracts include:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot prices at the busbar
of the plant involved; plus,
o sales to third parties under such forward contracts at designated delivery points (generally the PJM West Hub for Homer City
and the Northern Illinois Hub for the Illinois plants) less the cost of purchasing power at spot prices at the same designated
delivery points to fulfill obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific
locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can
cause the price of a specific delivery point to be raised or lowered relative to other locations depending on how the point is
impacted by transmission constraints. During the past 12 months, transmission congestion in PJM has resulted in prices at the PJM
West Hub (the primary trading hub in PJM for the Homer City facilities) being higher than those at the Homer City busbar by an
average of 5%. By contrast, during the past 12 months, transmission congestion in PJM has not resulted in prices at the Northern
Illinois Hub being significantly different from those at the individual busbars of the Illinois plants.
By entering into forward contracts using the PJM West Hub and the Northern Illinois Hub as the delivery points, EME is exposed to
"basis risk," which occurs when forward contracts are executed on a different basis (PJM West Hub for Homer City and the Northern
Illinois Hub for the Illinois plants) than the actual point of delivery (the individual plant busbars). In order to mitigate basis
risk resulting from forward contracts using the PJM West Hub as the delivery point, EME has participated in purchasing financial
transmission rights in PJM, and may continue to do so in the future. A financial transmission right is a
Page 59
financial instrument that entitles the holder thereof to receive actual spot prices at one point of delivery and pay prices at
another point of delivery that are pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's
price risk management activities include using financial transmission rights alone or in combination with forward contracts to manage
the risks associated with changes in prices within the PJM market.
Coal Price Risk
The Illinois plants use approximately 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of
Wyoming. In addition, the Homer City facilities use approximately 5 million tons of coal annually, obtained from mines located near
the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements typically ranging from one year to six
years in length. The following table summarizes the percent of expected coal requirements by year that are under contract at
March 31, 2005.
2005 2006 2007 2008 2009 2010
---------------------------------------------------------------------------------------------------
Percent of coal requirements under contract 95% 67% 50% 26% 26% 23%
---------------------------------------------------------------------------------------------------
EME is subject to price risk for purchases of coal that are not under contract. Prices of Northeast coal have risen considerably in
2004. The price of Northern Appalachian coal with 13,000 British thermal units (Btu) content and 3.0 SO2 MMBtu content for delivery
in the remaining three quarters of 2005 has fluctuated between $37.33 per ton and $57.55 per ton in the twelve-month period ended
March 31, 2005 with a price of $53.67 per ton at March 31, 2005. This increase in price has been largely attributed to greater demand
from domestic power producers and increased international shipments partly driven by a decline in the value of the United States
dollar. The price of the Powder River Basin coal at the mine with 8,800 Btu content and 0.8 SO2 MMBtu content for delivery in the
remaining three quarters of 2005 has fluctuated between $6.37 per ton and $7.99 per ton in the twelve-month period ended March 31,
2005, with a price of $7.26 per ton at March 31, 2005. See "Commitments, Guarantees and Indemnities--Fuel Supply Contracts" for more
information regarding fuel supply interruptions and the dispute with two suppliers.
Emission Allowances Price Risk
Under the federal Acid Rain Program (which requires electric generating stations to hold sulfur dioxide allowances) and Illinois and
Pennsylvania regulations implementing the federal NOx SIP Call requirement, EME purchases (or sells) emission allowances based on the
amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. As part of the
acquisition of the Illinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been
or are allocated to these plants.
The price of emission allowances, particularly SO2 allowances issued through the US EPA Acid Rain Program, also increased
substantially during the past eighteen months. The average price of purchased SO2 allowances increased to $692 per ton during the
first quarter of 2005 from $253 per ton during the first quarter of 2004. During the first quarter of 2005, EME Homer City purchased
13,089 tons of SO2 allowances at an EPA auction for an average price of $692 per ton. These developments have been attributed to
reduced numbers of both allowance sellers and prior vintage allowances.
Credit Risk
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies,
financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default
on its trade obligation, EME would be exposed
Page 60
to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if
the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the
risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.
To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would
be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and
mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used whenever possible
and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or
lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME
manages the credit risk on the portfolio based on credit ratings using published ratings of counterparties and other publicly
disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. A risk management committee regularly
reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly
successful in mitigating credit risk or that collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities as either: (i) the sum of 60 days of accounts
receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts
receivable and the current fair value of open positions. EME's subsidiaries enter into master agreements and other arrangements in
conducting price risk management and trading activities which typically provide for a right of setoff in the event of bankruptcy or
default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these
agreements. At March 31, 2005, the amount of exposure, broken down by the credit ratings of EME's counterparties was as follows:
March 31,
In millions 2005
- -----------------------------------------------------------------
S&P Credit Rating
A or higher $ 5
A- 47
BBB+ 48
BBB 15
BBB- 1
Below investment grade --
- -----------------------------------------------------------------
Total $ 116
- -----------------------------------------------------------------
EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power-purchase agreements.
Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power-purchase
agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such
power plant.
For the three months ended March 31, 2005, one customer accounted for 11% of nonutility power generation revenue. For the three
months ended March 31, 2004, one customer accounted for 14% and a second customer, Exelon Generation, accounted for 29% of nonutility
power generation revenue. For more information on Exelon Generation see "MEHC: Market Risk Exposures--Commodity Price Risk--Energy
Price Risk Affecting Sales from the Illinois Plants--Pre-2005 Merchant Sales."
Page 61
Interest Rate Risk
Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or
other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations
are subject to interest rate risk. The fair market value of MEHC's total long-term obligations (including current portion) was
$4.9 billion at March 31, 2005, compared to the carrying value of $4.3 billion. The fair market value of MEHC's parent only total
long-term obligations was $985 million at March 31, 2005, compared to the carrying value of $790 million.
Fair Value of Financial Instruments
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used in EME's continuing operations
for purposes other than trading by risk category and instrument type:
March 31, December 31,
In millions 2005 2004
- --------------------------------------------------------------------------
Commodity price:
Electricity $ (150) $ 10
- --------------------------------------------------------------------------
In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions
based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts
takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The
following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management
assets and liabilities as of March 31, 2005:
Total Maturity Maturity Maturity Maturity
Fair Less than 1 to 3 4 to 5 Greater than
In millions Value 1 year years years 5 years
-------------------------------------------------------------------------------------------------
Prices actively quoted $ (150) $ (146) $ (4) $ -- $ --
-------------------------------------------------------------------------------------------------
Energy Trading Derivative Financial Instruments
EME's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading. As a result of a
number of industry and credit-related factors, Edison Mission Marketing & Trading has minimized its price risk management and trading
activities not related to EME's power plants or investments in energy projects. To the extent Edison Mission Marketing & Trading
engages in trading activities, Edison Mission Marketing & Trading seeks to manage price risk and to create stability of future income
by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and
fuels by buying and selling these commodities in wholesale markets. EME generally balances forward sales and purchase contracts and
manages its exposure through a value at risk analysis as described under "--Commodity Price Risk."
Page 62
The fair value of the commodity financial instruments related to energy trading activities as of March 31, 2005 and December 31,
2004, are set forth below:
March 31, 2005 December 31, 2004
----------------------------- --------------------------------
In millions Assets Liabilities Assets Liabilities
- ----------------------------------------------------------------------------------------------
Electricity $ 107 $ 12 $ 125 $ 36
- ----------------------------------------------------------------------------------------------
The change in the fair value of trading contracts for the quarter ended March 31, 2005, was as follows:
In millions
------------------------------------------------------------------------
Fair value of trading contracts at January 1, 2005 $ 89
Net gains from energy trading activities 23
Amount realized from energy trading activities (17)
------------------------------------------------------------------------
Fair value of trading contracts at March 31, 2005 $ 95
------------------------------------------------------------------------
Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except
for the power sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term
power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair value based upon a
discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the
non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the
valuation method and the related fair value of energy trading assets and liabilities, as of March 31, 2005:
Maturity
Total Maturity Maturity Maturity Greater
Fair Less than 1 to 3 4 to 5 than
In millions Value 1 year years years 5 years
-----------------------------------------------------------------------------------------------------------
Prices actively quoted $ 5 $ 5 $ -- $ -- $ --
Prices based on models and other
valuation methods 90 (2) 7 13 72
-----------------------------------------------------------------------------------------------------------
Total $ 95 $ 3 $ 7 $ 13 $ 72
-----------------------------------------------------------------------------------------------------------
MEHC: OTHER DEVELOPMENT
Regulatory Matters
The Midwest Independent Transmission System Operator (the MISO) commenced operation of its day-ahead, locational marginal pricing
market on April 1, 2005, as scheduled, and has been functioning since that time. At that time, "Into Cinergy" became a locational
marginal pricing location in MISO. It is anticipated that the opening of the MISO market will provide increased liquidity in the
Midwest electricity markets. See "MEHC: Other Development--Regulatory Matters" in the year-ended 2004 MD&A for further discussion.
Page 63
EDISON CAPITAL
EDISON CAPITAL: CURRENT DEVELOPMENTS
Edison Capital has investments in three regionally focused global infrastructure funds; Europe, Asia and Latin America. All three
funds follow fair value accounting, in which changes in the fair value of investments are recorded directly in earnings. Edison
Capital records its share of the Fund's earnings as equity in income from partnerships and unconsolidated affiliates. Edison
Capital's share of earnings from its investment in the Emerging Europe Infrastructure Fund totaled $43 million, after tax, in the
first quarter of 2005. These earnings were significantly above expectations and mainly resulted from gains on investments in several
telecommunications companies in Eastern Europe. Furthermore, Vodafone has recently announced the acquisition of a company in which
the Emerging Europe Infrastructure Fund has a significant interest. As a result of this acquisition, Edison Capital expects to
record an additional $17 million, after tax, in the second quarter as its share of the fund's earnings.
EDISON CAPITAL: LIQUIDITY
Edison Capital's main sources of liquidity are tax-allocation payments from Edison International, lease rents and distributions from
its global infrastructure fund investments.
Edison Capital's 2005 cash requirements primarily consist of:
o Funding new investments in renewable energy;
o Scheduled debt principal and interest; and
o General and administrative expenses.
As of March 31, 2005, Edison Capital had unrestricted cash and cash equivalents of $222 million and long-term debt, including current
maturities of $321 million. Additionally, as of March 31, 2005, Edison Capital had unfunded commitments of $11 million, and had
signed binding term sheets, subject to closing, for $76 million of additional renewable energy. Edison Capital's pursuit of new
renewable energy investments depends upon economic and regulatory conditions and continuation of government policies supporting
renewable energy.
Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation payments from the parent company and
expected cash flow from operating activities.
At March 31, 2005, Edison Capital's long-term debt had credit ratings of Ba1 and BB+ from Moody's Investors Service and Standard &
Poor's, respectively.
EDISON CAPITAL: MARKET RISK EXPOSURES
Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance risk that could
adversely affect its results of operations or financial position. See "Edison Capital: Market Risk Exposures" in the year-ended
2004 MD&A for a complete discussion of Edison Capital's market risk exposures.
EDISON CAPITAL: OTHER DEVELOPMENT
Federal Income Taxes
Edison International received Revenue Agent Reports from the Internal Revenue Service (IRS) in August 2002 and in January 2005
asserting deficiencies in federal corporate income taxes with respect to audits of its to 1994-1996 and 1997-1999 tax years,
respectively. Among the issues raised were items related to Edison Capital. See "Other Developments--Federal Income Taxes" for
further discussion of these matters.
Page 64
EDISON INTERNATIONAL (PARENT)
EDISON INTERNATIONAL (PARENT): LIQUIDITY
The parent company's liquidity and its ability to pay interest, debt principal, operating expenses and dividends to common
shareholders are affected by dividends from subsidiaries, tax-allocation payments under its tax-allocation agreements with its
subsidiaries, and access to capital markets or external financings. Edison International was focused on reducing its parent company
debt in 2004, and as of March 31, 2005, had no debt outstanding.
Edison International (parent)'s 2005 cash requirements primarily consist of:
o Dividends to common shareholders. On February 17, 2005, the Board of Directors of Edison International declared a $0.25 per
share common stock dividend. The $81 million dividend was paid on May 3, 2005; and
o General and administrative expenses.
Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, short-term
borrowings, when necessary, and dividends from its subsidiaries. At March 31, 2005, Edison International (parent) had approximately
$39 million of cash and cash equivalents on hand. In February 2005, Edison International (parent) entered into a $750 million senior
unsecured 5-year revolving credit facility and as of March 31, 2005, had the entire amount available under its credit facility. The
ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described below.
The CPUC regulates SCE's capital structure by requiring that SCE maintain prescribed percentages of common equity, preferred equity
and long-term debt in the utility's capital structure. SCE may not make any distributions to Edison International that would reduce
the common equity component of SCE's capital structure below the prescribed level. The CPUC also requires that SCE establish its
dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the
utility as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of
dividend payments by SCE to Edison International include, among other things, SCE's cash requirements, SCE's access to capital
markets, dividends on SCE's preferred and preference stock, and actions by the CPUC. SCE paid a cash dividend of $71 million on
April 28, 2005.
MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At March 31, 2005, its interest coverage
ratio was 1.66 to 1. See "MEHC: Liquidity--MEHC's Interest Coverage Ratio." In addition, MEHC's certificate of incorporation and
senior secured note indenture, contain restrictions on MEHC's ability to declare or pay dividends or distributions (other than
dividends payable solely in MEHC's common stock). These restrictions require the unanimous approval of MEHC's Board of Directors,
including its independent director, before it can declare or pay dividends or distributions, as long as any indebtedness is
outstanding under the indenture. MEHC did not declare or pay a dividend in 2004 to Edison International. MEHC's ability to pay
dividends is dependent on EME's ability to pay dividends to MEHC (parent). EME and its subsidiaries have certain dividend
restrictions as discussed in the "MEHC: Liquidity--Dividend Restrictions in Major Financings" section. MEHC has not declared or made
dividend payments to Edison International in 2005.
Edison Capital's ability to make dividend payments is currently restricted by covenants in its financial instruments, which require
Edison Capital, through a wholly owned subsidiary, to maintain a specified
Page 65
minimum net worth of $200 million. Edison Capital met this minimum net worth as of March 31, 2005. Edison Capital has not declared
or made dividend payments to Edison International in 2005.
EDISON INTERNATIONAL (PARENT): MARKET RISK EXPOSURES
Although Edison International (parent) had no debt outstanding as of March 31, 2005, the parent company may be exposed to changes in
interest rates which may result from future borrowing and investing activities, the proceeds of which may be used for general
corporate purposes, including investments in nonutility businesses. The nature and amount of the parent company's long-term and
short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors.
EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS
Holding Company Proceeding
Edison International was a party to a CPUC holding company proceeding. See "SCE: Regulatory Matters--Other Regulatory
Matters--Holding Company Proceeding" for a discussion of this matter.
Federal Income Taxes
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. See "Other
Developments--Federal Income Taxes" for further discussion of these matters.
Page 66
EDISON INTERNATIONAL (CONSOLIDATED)
The following sections of the MD&A are on a consolidated basis. The section begins with a discussion of Edison International's
consolidated results of operations and historical cash flow analysis. This is followed by discussions of discontinued operations,
new accounting principles, commitments, guarantees and indemnities and other developments.
RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS
The following subsections of "Results of Operations and Historical Cash Flow Analysis" provide a discussion on the changes in various
line items presented on the Consolidated Statements of Income as well as a discussion of the changes on the Consolidated Statements
of Cash Flows.
Results of Operations
First Quarter 2004 vs. First Quarter 2005
Edison International recorded consolidated earnings of $201 million, or 61(cent)per common share, in first quarter 2005, compared to $97
million, or 30(cent)per common share, in first quarter 2004. The increased earnings primarily reflect: improved operating results from
MEHC's independent power business; gains from Edison Capital's investment in the Emerging Europe Infrastructure Fund; and higher
revenue at SCE associated with a GRC decision reached in July 2004. The July 2004 decision provided higher authorized revenue for
all of 2004; therefore, the 2005 full-year comparison is not expected to reflect a year-over-year increase in earnings related to the
GRC decision.
The table below presents Edison International's earnings and earnings per share for the three-month periods ended March 31, 2005 and
2004, and the relative contributions by its subsidiaries.
In millions, except per share amounts Earnings (Loss) Earnings (Loss) per Share
- ----------------------------------------------------------------------------------------------------------------------
Three-Month Period Ended March 31, 2005 2004 2005 2004
- ----------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 131 $ 100 $ 0.40 $ 0.31
MEHC 25 (39) 0.08 (0.12)
Edison Capital 52 11 0.16 0.03
Edison International (parent) and other (14) (20) (0.05) (0.06)
- ----------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings
from Continuing Operations 194 52 0.59 0.16
- ----------------------------------------------------------------------------------------------------------------------
Earnings from Discontinued Operations 7 46 0.02 0.14
- ----------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change -- (1) -- --
- ----------------------------------------------------------------------------------------------------------------------
Edison International Consolidated $ 201 $ 97 $ 0.61 $ 0.30
- ----------------------------------------------------------------------------------------------------------------------
Earnings from Continuing Operations
Edison International's first quarter 2005 earnings from continuing operations were $194 million, or 59(cent)per common share, compared
with earnings of $52 million, or 16(cent)per common share, in first quarter 2004.
SCE's first quarter 2005 earnings from continuing operations were $131 million, $31 million above the same period last year.
Virtually all of this increase is due to higher authorized revenue in 2005 from the implementation of the 2003 GRC decision. SCE
received the decision in July 2004, therefore 2004 first quarter earnings do not include the effects from this decision.
Page 67
MEHC's first quarter 2005 earnings from continuing operations were $25 million, compared to a loss of $39 million in the same period
last year. MEHC's first quarter 2005 earnings from continuing operations include a $15 million after-tax charge related to the early
extinguishment of debt while the first quarter 2004 loss includes a $27 million after-tax net gain from the sale of EME's interests
in Four Star Oil & Gas and the Brooklyn Navy Yard projects. The improved earnings are largely due to stronger operating performance
at the Illinois and the Homer City Plants, driven by higher merchant generation and wholesale energy prices. Also contributing to
the increase in earnings was higher income from MEHC's marketing and trading subsidiary, stronger operating results from the Big Four
projects in California and lower net corporate interest costs.
Edison Capital's earnings from continuing operations for first quarter 2005 were $52 million, up $41 million over the same period
last year. This increase is primarily due to Edison Capital's share of income from its investment in the Emerging Europe
Infrastructure Fund. The Fund accounts for most of its investments at fair value, with changes in the fair value recorded quarterly
through net income. Edison Capital's share of the Fund's income was $43 million during first quarter 2005, which primarily resulted
from gains on several telecommunication investments in Eastern Europe.
The first quarter 2005 loss from Edison International (parent) and other was $14 million, $6 million lower than the same period last
year. The improvement was primarily due to lower interest expense, partially offset by higher taxes.
Operating Revenue
SCE's retail sales represented approximately 80% and 87% of electric utility revenue in the first quarter of 2005 and 2004,
respectively. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is
generally significantly higher than other quarters.
The following table sets forth the major changes in electric utility revenue:
In millions Three-Month Period Ended March 31, 2005 vs. 2004
------------------------------------------------------------------------------------
Electric utility revenue
Rate changes $ (67)
Sales volume changes 111
Sales for resale 59
SCE's variable interest entities 101
Other (including intercompany transactions) 8
------------------------------------------------------------------------------------
Total $ 212
------------------------------------------------------------------------------------
Total electric utility revenue increased by $212 million in 2005 (as shown in the table above). The reduction in electric utility
revenue resulting from rate changes was mainly due to higher deferrals of revenue related to balancing account overcollections in
2005, as compared to 2004. The rate changes variance also reflects the implementation of the 2003 GRC, effective in August 2004. As
a result, generation rates decreased by approximately $115 million and distribution rates increased by approximately $150 million.
The increase in electric utility revenue resulting from sales volume changes was mainly due to an increase in kWh sold and SCE
providing a greater amount of energy to its customers from its own sources in 2005, compared to 2004, in which the CDWR provided a
greater amount of energy to SCE's customers. Sales for resale increased due to a greater amount of excess energy in 2005, as
compared to 2004. As a result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times,
which then is resold in the energy markets. SCE's variable interest entities revenue represents the recognition of revenue resulting
from the consolidation of SCE's variable interest entities on March 31, 2004.
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Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers (beginning
January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003) are
remitted to the CDWR and are not recognized as revenue by SCE. These amounts were $510 million and $630 million for the three-month
periods ended March 31, 2005 and 2004, respectively.
Nonutility power generation revenue increased $122 million in 2005 mainly due to higher energy revenue of approximately $119 million
and $45 million at EME's Illinois plants and Homer City, respectively. The increases resulted from higher average realized energy
prices and increased generation. During the first quarter of 2004, an unplanned outage at EME's Homer City contributed to lower
generation. The 2005 increase was partially offset by lower capacity revenue of approximately $19 million at EME's Illinois plants
from the expiration of the power-purchase agreements with Exelon Generation, as well as a decrease of $29 million due to the
deconsolidation of EME's Doga project at March 31, 2004, in accordance with accounting standards.
Nonutility power generation revenue is generally higher in the third quarter than revenue related to other quarters of the year. Due
to higher electric demand resulting from warmer weather during the summer months, nonutility power generation revenue generated from
EME's Homer City facilities and the Illinois plants are generally higher during the third quarter of each year.
Operating Expenses
Fuel Expense
In millions Three-Month Period Ended March 31, 2005 2004
-----------------------------------------------------------------------------------------
SCE $ 255 $ 48
MEHC 164 179
-----------------------------------------------------------------------------------------
Edison International Consolidated $ 419 $ 227
-----------------------------------------------------------------------------------------
SCE's fuel expense increased in 2005 primarily due to the consolidation of SCE's variable interest entities resulting in the
recognition of fuel expense of $193 million.
MEHC's fuel expense decreased in 2005 primarily due to the deconsolidation of EME's Doga project, resulting in a decrease of $17
million, and lower fuel costs of $30 million primarily attributable to the cessation of operations at EME's Collins Station. The
decrease was partially offset by higher fuel costs of $12 million at EME's Illinois plants attributable to increased generation and
higher coal prices and $20 million at EME's Homer City facilities attributable to higher fuel consumption, higher coal prices and
higher priced SO2 emission allowances.
Purchased-Power Expense
Purchased-power expense decreased $192 million in 2005. The 2005 decrease was mainly due to the consolidation of SCE's variable
interest entities which resulted in a $173 million reduction in purchased-power expense, as well as higher unrealized gains of
approximately $150 million related to hedging transactions resulting from increased hedging activities in 2005, as compared to 2004.
The 2005 decrease was partially offset by higher expenses of approximately $70 million resulting from an increase in the number of
bilateral contracts in 2005, as compared to 2004, an increase of approximately $40 million mainly due to an increase in the volume
and a true-up of exchanged energy, and higher expenses of approximately $20 million related to ISO and qualifying facilities (QF)
purchases.
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.
Page 69
Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)-per-kWh. Average spot natural
gas prices were slightly higher during 2005 as compared to 2004. The higher expenses related to power purchased from QFs were mainly
due to higher average spot natural gas prices, partially offset by lower kWh purchases.
Provisions for Regulatory Adjustment Clauses - Net
Provisions for regulatory adjustment clauses - net increased $84 million in 2005. The increase was mainly due to $150 million of
unrealized gains related to hedging transactions (mentioned above in purchased-power expense) that, if realized, would be refunded to
ratepayers, partially offset by net undercollections of purchased power, fuel and operating and maintenance costs of approximately
$65 million which were deferred in balancing accounts for future recovery.
Other Operation and Maintenance Expense
In millions Three-Month Period Ended March 31, 2005 2004
----------------------------------------------------------------------------------------
SCE $ 601 $ 580
MEHC 188 188
Other 26 19
----------------------------------------------------------------------------------------
Edison International Consolidated $ 815 $ 787
----------------------------------------------------------------------------------------
SCE's other operating and maintenance expense increased in 2005 mainly due to the recognition of approximately $24 million in
operating and maintenance expenses as a result of the consolidation of SCE's variable interest entities, and an increase of $40
million in reliability costs due to an increase in must run units to improve the reliability of the California ISO systems operations
(which are recovered through regulatory mechanisms approved by the FERC). The 2005 increase was partially offset by a decrease of
$40 million in generation-related expenses primarily related to lower outage and refueling costs in 2005, as compared to 2004. In
2004, there was a scheduled major overhaul at SCE's Four Corners coal facility, as well as a refueling outage at SCE's San Onofre
Unit 2.
Other Income and Deductions
Equity in Income from Partnerships and Unconsolidated Subsidiaries - Net
Equity in income from partnerships and unconsolidated subsidiaries - net increased $65 million in 2005, mainly due to increased
earnings of approximately $70 million from Edison Capital's global infrastructure funds (see "Edison Capital: Current
Developments"), partially offset by the effects of accounting for variable interest entities consolidated upon adoption of a new
accounting pronouncement in second quarter 2004, resulting in a decrease of approximately $10 million. As a result, SCE now
consolidates projects previously treated under the equity method by EME.
Equity in income from partnerships and unconsolidated subsidiaries - net from EME's energy projects is materially higher than equity
in income from partnerships and unconsolidated subsidiaries - net related to other quarters of the year due to warmer weather during
the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for
higher payments during the summer months.
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Other Nonoperating Income
In millions Three-Month Period Ended March 31, 2005 2004
-----------------------------------------------------------------------------------------------
SCE $ 18 $ 33
MEHC -- 48
-----------------------------------------------------------------------------------------------
Edison International Consolidated $ 18 $ 81
-----------------------------------------------------------------------------------------------
SCE's other nonoperating income in 2005 includes a $10 million reward for the efficient operation of Palo Verde during 2003, which
was approved by the CPUC in 2005. SCE's other nonoperating income in 2004 includes $19 million in rewards for the efficient
operation of Palo Verde during 2001 and 2002, which were approved by the CPUC in 2004.
MEHC's other nonoperating income in 2004 primarily related to a pre-tax gain of $47 million on the sale of EME's interest in Four
Star Oil & Gas on January 7, 2004.
Interest Expense - Net of Amounts Capitalized
In millions Three-Month Period Ended March 31, 2005 2004
-----------------------------------------------------------------------------------------------
SCE $ (103) $ (105)
MEHC (104) (99)
Other (7) (35)
-----------------------------------------------------------------------------------------------
Edison International Consolidated $ (214) $ (239)
-----------------------------------------------------------------------------------------------
MEHC's interest expense - net of amounts capitalized increased in 2005 mainly due to higher interest expense of approximately $20
million at EME's Illinois plants attributable to higher interest rates on the debt issued in April 2004, partially offset by a
decrease of $12 million at MEHC (parent) attributable to the repayment of MEHC (parent)'s $385 million term loan ($100 million of the
term loan was repaid in July 2004 and the remaining $285 million of the term loan was repaid in January 2005).
The decrease in interest expense - net of amounts capitalized related to Other was mainly due to the elimination of Edison
International (parent) debt. Edison International (parent) has had no debt outstanding since the fourth quarter of 2004.
Loss on Early Extinguishment of Debt
The loss on early extinguishment of debt in 2005 includes a $20 million loss related to the early repayment of MEHC (parent)'s $385
million term loan and a $4 million loss related to the early repayment of EME's junior subordinated debentures.
Income Taxes
In millions Three-Month Period Ended March 31, 2005 2004
-----------------------------------------------------------------------------------------------
SCE $ 65 $ 69
MEHC 16 (10)
Edison Capital 18 (3)
Edison International (parent) and other 5 (13)
-----------------------------------------------------------------------------------------------
Edison International Consolidated $ 104 $ 43
-----------------------------------------------------------------------------------------------
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Income tax expense increased $61 million in the 2005 primarily due to an increase in pre-tax income as well as non-deductible
compensation paid by Edison International. The increase was partially offset by changes in SCE's property-related flow-through items
between the periods, reductions in accrued tax liabilities made by SCE in the first quarter of 2005 to reflect progress in settlement
negotiations relating to prior-year tax liabilities at SCE, and adjustments made to deferred tax balances at Edison Capital and EME
as well as adjustments made at EME which increased tax expense in 2004.
Edison International's composite federal and state statutory rate was approximately 40% for both periods presented. The lower
effective tax rate of 34.9% realized in 2005 was primarily due to reductions in tax liabilities at SCE and the benefits received from
low income housing and production tax credits at Edison Capital. The decrease was partially offset by non-deductible compensation
paid by Edison International. The higher effective tax rate of 45.1% realized in 2004 was primarily due to adjustments made to
deferred tax balances at Edison Capital, property-related flow-through items at SCE and other adjustments at EME, partially offset by
the benefits received from low-income housing and production tax credits at Edison Capital.
Minority Interest
Minority interest represents the effects of the adoption of a new accounting pronouncement in second quarter 2004 related to SCE's
variable interest entities.
Income from Discontinued Operations
Edison International's earnings from discontinued operations were $7 million in first quarter 2005, reflecting the operating results
and sales impacts from MEHC's Tri-Energy and CBK international projects, both of which were sold during first quarter 2005. The
earnings from discontinued operations in first quarter 2004 of $46 million represent the operating results from MEHC's international
projects that were held for sale.
Cumulative Effect of Accounting Change - Net of Tax
Edison International's results for 2004 include a charge for the cumulative effect of a change in accounting principle reflecting the
impact of Edison Capital's implementation of an accounting standard that requires the consolidation of certain variable interest
entities.
Historical Cash Flow Analysis
The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating, financing and investing
activities.
Cash Flows from Operating Activities
Net cash provided by operating activities:
In millions Three-Month Period Ended March 31, 2005 2004
-------------------------------------------------------------------------------------------
Continuing operations $ 318 $ 312
-------------------------------------------------------------------------------------------
The 2005 change in cash provided by operating activities from continuing operations was mainly due to the timing of cash receipts and
disbursements related to working capital items.
Pge 72
Cash Flows from Financing Activities
Net cash (used) provided by financing activities:
In millions Three-Month Period Ended March 31, 2005 2004
----------------------------------------------------------------------------------------------
Continuing operations $ (591) $ 652
----------------------------------------------------------------------------------------------
Cash (used) provided by financing activities from continuing operations mainly consisted of long-term and short-term debt payments at
SCE and EME.
Financing activities in the first quarter of 2005 were mainly due to activities at SCE. SCE's first quarter financing activity
included the issuance of $650 million of first and refunding mortgage bonds. The issuance included $400 million of 5% bonds due in
2016 and $250 million of 5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of 8% first and refunding
mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding mortgage bonds due
February 2007 (Series 2003B). In addition, SCE issued $202 million of commercial paper, net of repayments. MEHC's first quarter
financing activity included the repayment of the remaining $285 million of the term loan and the repayment of the junior subordinated
debentures of $150 million. Financing activities in 2005 also include dividend payments of $81 million paid by Edison International
to its shareholders.
Financing activities in the first quarter of 2004 were mainly due to activities at SCE. During the first quarter of 2004, SCE issued
$300 million of 5% bonds due in 2014, $525 million of 6% bonds due in 2034 and $150 million of floating rate bonds due in 2006. The
proceeds from these issuances were used to call at par $300 million of 7.25% first and refunding mortgage bonds due March 2026,
$225 million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding mortgage bonds due
October 2018, and $100 million of junior subordinated deferrable interest debentures due June 2044. In addition, during the first
quarter of 2004, SCE paid the $200 million outstanding balance of its credit facility, as well as remarketed approximately
$550 million of pollution-control bonds with varying maturity dates ranging from 2008 to 2040. Approximately $354 million of these
pollution-control bonds had been held by SCE since 2001 and the remaining $196 million were purchased and reoffered in 2004. In
March 2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds due in 2015 and $350 million of 5.75% first and
refunding mortgage bonds due in 2035. A portion of the proceeds from the March 2004 first and refunding mortgage bond issuances were
used to fund the acquisition and construction of the Mountainview project. Financing activities in 2004 also included a dividend
payment of $65 million paid by Edison International to its shareholders.
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Three-Month Period Ended March 31, 2005 2004
-----------------------------------------------------------------------------------------------
Continuing operations $ (52) $ (508)
-----------------------------------------------------------------------------------------------
Cash flows from investing activities are affected by capital expenditures, EME's sales of assets and SCE's funding of nuclear
decommissioning trusts.
Investing activities in the first quarter of 2005 reflect $364 million in capital expenditures at SCE, primarily for transmission and
distribution assets, including approximately $14 million for nuclear fuel acquisitions, and $14 million in capital expenditures at
EME. In addition, investing activities include $140 million in net sales of auction rate securities at EME and $124 million in
proceeds received from
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the sale of EME's 25% investment in the Tri Energy project and EME's 50% investment in the CBK project.
Investing activities in the first quarter of 2004 reflect $316 million in capital expenditures at SCE, primarily for transmission and
distribution assets, including approximately $12 million for nuclear fuel acquisitions, and $14 million in capital expenditures at
EME, primarily for new plant and equipment related to EME's Illinois plants and its Homer City facilities. In addition, investing
activities include $285 million of acquisition costs related to the Mountainview project as SCE, and $118 million in proceeds
received from the sale of 100% of EME's stock of Edison Mission Energy Oil & Gas.
DISCONTINUED OPERATIONS
On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15,
2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately
$20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.
On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to Corporacion IMPSA S.A.,
pursuant to a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a
pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.
EME previously owned and operated a 220-MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the
Lakeland project. The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power
generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU
UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland Power Ltd.
in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement.
Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is
distributed from this entity.
As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination
of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading
Limited (TXU Energy), entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy
proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received(pound)112 million (approximately $210 million) from
the TXU administrators, representing an interim payment of 97% of its accepted claim of(pound)116 million (approximately $217 million).
No income related to this payment was recognized during the quarter ended March 31, 2005.
From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of
(pound)20 million (approximately $38 million) to EME on April 7, 2005 comprised of(pound)7 million (approximately $13 million) for a secured loan
which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd.,
and (pound)13 million (approximately $25 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power
Ltd. This amount will be recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay to
EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured
and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland
Power Ltd.'s liquidation.
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EME estimates that the net proceeds after tax (including taxes due in the United States) resulting from the above payments will be
approximately $100 million and the increase in net income will be approximately $90 million (including the amounts discussed above
during the second quarter of 2005). These proceeds may be received throughout 2005, and possibly 2006, as Lakeland Power Ltd.'s
liquidation progresses. Because the amounts required to settle outstanding claims and UK taxes have not been finalized and cannot be
estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may vary
materially from the above estimate.
For both periods presented, the results of EME's international projects discussed above have been accounted for as discontinued
operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal
of long-lived assets.
For the three months ended March 31, 2005 and 2004, revenue from discontinued operations was zero and $394 million, respectively, and
pre-tax income was zero and $94 million, respectively.
NEW ACCOUNTING PRINCIPLES
In March 2005, the Financial Accounting Standards Board (FASB) issued an interpretation related to accounting for conditional asset
retirement obligations. This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a
conditional asset retirement obligation if the fair value can be reasonably estimated even though uncertainty exists about the timing
and/or method of settlement. This Interpretation is effective December 31, 2005. Edison International is assessing the impact of
this Interpretation on its results of operations and financial condition.
A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison
International currently uses the intrinsic value accounting method for stock-based compensation. On April 14, 2005, the Securities
and Exchange Commission announced a delay in the effective date for the new standard to fiscal years beginning after June 15, 2005.
Edison International will implement the new standard effective January 1, 2006 by applying the modified prospective transition
method. The difference in expense, net of tax, between the two accounting methods is an increase of $2 million.
In December 2004, the FASB issued guidance (Staff Position 109-1) on accounting for a tax deduction resulting from the American Jobs
Creation Act of 2004. The primary objective of this Position is to provide guidance on accounting for the provision within the
American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities. Under this Position,
recognition of the tax deduction on qualified production activities, which include the production of electricity, is reported in the
year it is earned. This FASB Staff Position had no material impact on Edison International's financial statements. Edison
International is evaluating the effect that the manufacturer's deduction will have in subsequent years.
In March 2004, the FASB issued new accounting guidance for the effect of participating securities on earnings per common share (EPS)
calculations and the use of the two-class method. The new guidance, which was effective in second quarter 2004, requires the use of
the two-class method of computing EPS for companies with participating securities. The two-class method is an earnings allocations
formula that determines EPS for each class of common stock and participating security. Edison International has participating
securities (vested stock options that earn dividend equivalents on an equal basis with common shares), but determined that the effect
on 2004, 2003 and 2002 EPS was immaterial.
Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding.
Net income available for common stock was $200 million and $97 million for the three months ended March 31, 2005 and 2004,
respectively. In arriving at net income, dividends on preferred securities and preferred stock have been deducted.
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In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003), Consolidation of
VIEs. The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for,
VIEs, where control may be achieved through means other than voting rights. Under the Interpretation, the enterprise that is
expected to absorb or receive the majority of a VIE's expected losses or residual returns, or both, must consolidate the VIE, unless
specific exceptions apply. This Interpretation was effective for special purpose entities, as defined by accounting principles
generally accepted in the United States, as of December 31, 2003, and all other entities as of March 31, 2004. Edison International
implemented the Interpretation for its special purpose entities as of December 31, 2003.
On March 31, 2004, SCE consolidated four power projects partially owned by EME, EME deconsolidated two power projects, and Edison
Capital consolidated two affordable housing partnerships and three wind projects. Edison International recorded a cumulative effect
adjustment that decreased net income by less than $1 million, net of tax, due to negative equity at one of Edison Capital's newly
consolidated entities.
COMMITMENTS, GUARANTEES AND INDEMNITIES
The following is an update to Edison International's commitments, guarantees and indemnities. See the "Commitments, Guarantees and
Indemnities" section of the year-ended 2004 MD&A for a detailed discussion.
Fuel Supply Contracts
Midwest Generation has entered into additional fuel purchase commitments with various third-party suppliers during the first three
months of 2005. These additional commitments are currently estimated to be $8 million for 2005, $8 million for 2006, $24 million for
2007, $25 million for 2008, and $53 million for 2009.
Beginning in 2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis,
Inc. Unionvale and Genesis claimed that alleged geologic conditions at the Genesis No. 17 Mine in Pennsylvania, which is one source
of coal under these multi-source coal contracts, constituted force majeure and excused full contract performance. These
two agreements together provide for the delivery to EME Homer City of 1,290,000 tons of coal, which represents 20% of EME Homer City's
clean coal requirements in 2005 and 2006, and approximately 10% in 2007.
On December 21, 2004, Unionvale and Genesis gave notice of termination of one of the agreements, which was scheduled to run through
December 2007, under a provision that they claim allows either party to the agreement to terminate if an event of force majeure lasts
30 days or more. Unionvale and Genesis allege that the geologic problems encountered at the one mine have continued beyond a 30-day
period and excuse their obligation to deliver coal under the agreement. The parties' second agreement with a term through December
2006 does not contain the same termination provision, and the suppliers have sought contract modifications to the term, quantity,
quality and price provisions of this agreement. On April 26, 2005, Unionvale and Genesis informed EME Homer City that Genesis No. 17
Mine has been shut down and that no delivery of coal from that mine will be made under either agreement.
EME Homer City disputes the force majeure claim and the suppliers' reliance upon this claim to excuse their performance under the
multi-source coal agreements. EME Homer City has filed suit against Unionvale and Genesis in Pennsylvania state court seeking, among
other things, equitable relief by way of an order requiring the defendants to fulfill their contractual obligations and other
monetary relief. The parties are currently engaged in mediation in an effort to resolve the contractual dispute. Contracts have
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been awarded and inventory strategies adjusted to reflect and offset the delivery shortfall for 2005. As of March 31, 2005, EME
Homer City had not contracted for the resultant potential shortfalls in 2006 and 2007.
Gas and Coal Transportation
Midwest Generation has additional coal transportation commitments during the first three months of 2005. Based on the committed coal
volumes in the fuel supply contracts mentioned above, these commitments are currently estimated to be $16 million for 2005,
$15 million for 2006, $38 million for 2007, $37 million for 2008, and $74 million for 2009.
Power-Purchase Contracts
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's purchased power capacity payment
commitments under these contracts are currently estimated to be $69 million for 2005, $95 million for 2006, $101 million for 2007,
and $84 million for 2008.
Leases
During the first quarter of 2005, SCE entered into new power contracts, in which SCE takes virtually all of the power. In accordance
with an accounting standard, these power contracts are classified as operating leases. SCE's commitments under these operating
leases are currently estimated to be $39 million for 2005, $55 million for 2006, $50 million for 2007, and $43 million for 2008.
OTHER DEVELOPMENTS
Environmental Matters
Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the
environment.
Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible
future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the
manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that
additional costs would be recovered from customers or that Edison International's financial position and results of operations would
not be materially affected.
Environmental Remediation
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and
a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International
records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
Edison International's recorded estimated minimum liability to remediate its 31 identified sites at SCE (25 sites) and EME (6 sites
related to Midwest Generation) is $90 million, $88 million of which is related to SCE. Edison International's other subsidiaries
have no identified remediation sites. The ultimate
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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 $130 million, all of
which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison
International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of
the range of costs is at least $1 million), SCE also has 30 immaterial sites whose total liability ranges from $4 million (the
recorded minimum liability) to $9 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $34 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 $60 million for its
estimated minimum environmental-cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is a lack of currently available information, including
the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing
to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next
several years are expected to range from $12 million to $25 million. Recorded costs for the twelve months ended March 31, 2005 were
$12 million.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental
remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such estimates.
Federal Income Taxes
Edison International has reached a tentative settlement with the IRS on tax issues and pending affirmative claims relating to its
1991-1993 tax years. This settlement, which was signed by Edison International in March 2005 and is currently awaiting approval by
the United States Congress Joint Committee on Taxation, is expected to result in a net earnings benefit for Edison International of
approximately $70 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal
corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. Many of the asserted tax
deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would be
deductible on future tax returns of Edison International.
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As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income
taxes in audits of the 1994-1996 and 1997-1999 tax years associated with Edison Capital's cross-border leases. The IRS is
challenging Edison Capital's foreign power plant and electric locomotive sale/leaseback transactions (termed a sale-in/lease-out or
SILO transaction). The estimated federal and state taxes deferred from these leases were $44 million in the 1994-1996 and 1997-1999
audit periods and $32 million in subsequent years through 2004.
The IRS is also challenging Edison Capital's foreign power plant and electric transmission system lease/leaseback transactions
(termed a lease-in, lease-out or LILO transaction). The estimated federal and state income taxes deferred from these leases were
$558 million in the 1997-1999 audit period and $565 million in subsequent years through 2004. The IRS has also proposed interest and
penalties in its challenge to each SILO and LILO transaction.
Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in
effect at the time the transactions were entered into. Written protests were filed to appeal the 1994-1996 audit adjustments
asserting that the IRS's position misstates material facts, misapplies the law and is incorrect. This matter is now being considered
by the Administrative Appeals branch of the IRS. Edison International also filed protests in March 2005 to appeal the issues raised
in the 1997-1999 audit. Edison International intends to contest these proposed deficiencies through administrative appeals and
litigation, if necessary.
Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (termed a
Service Contract). The IRS did not assert an adjustment for this lease in the 1997-1999 audit cycle but is expected to challenge
this lease in subsequent audit cycles similar to positions asserted against the SILOs discussed above. The estimated federal and
state taxes deferred from this lease are $221 million through 2004.
If Edison International is not successful in its defense of the tax treatment for the SILOs, LILOs and the Service Contract, the
payment of taxes, exclusive of any interest or penalties, would not affect results of operations under current accounting standards,
although it could have a significant impact on cash flow. However, the FASB is currently considering changes to the accounting for
leases. If the proposed accounting changes are adopted and Edison International's tax treatment for the SILOs, LILOs and Service
Contract is significantly altered as a result of IRS challenges, there could be a material effect on reported earnings by requiring
Edison International to reverse earnings previously recognized as a current period adjustment and to report these earnings over the
remaining life of the leases. At this time, Edison International is unable to predict the impact of the ultimate resolution of these
matters.
The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE
subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability
company. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits
relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these
tax losses are sustained.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the
possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to
listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital
leveraged lease transactions and the SCE subsidiary contingent liability company transaction described above. Edison International
filed these amended returns under protest retaining its appeal rights.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition
and Results of Operations," under the headings "SCE: Market Risk Exposures," "MEHC: Market Risk Exposures," "Edison Capital:
Market Risk Exposures," and "Edison International (Parent): Market Risk Exposures" and is incorporated herein by this reference.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and
Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term
is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of
the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded
that, as of the end of the period, Edison International's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting
There were no changes in Edison International's internal control over financial reporting (as that term is defined in Rules 13a-15(f)
or 15d-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably
likely to materially affect, Edison International's internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The following is a description of litigation of subsidiaries of Edison International that may be material to Edison International.
Southern California Edison Company
Navajo Nation Litigation
Information about the Navajo Nation Litigation appears in Part I, Item 2, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" under the heading "SCE: Other Developments--Navajo Nation Litigation" and is incorporated herein
by this reference. Information about the Navajo Nation Litigation was previously reported in Part I, Item 3 of Edison
International's Annual Report on Form 10-K for the year ended December 31, 2004.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser
(as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International's equity
securities that is registered pursuant to Section 12 of the Exchange Act.
(c) Total (d) Maximum
Number of Shares Number (or
(or Units) Approximate
Purchased Dollar Value)
as Part of of Shares
(a) Total Publicly (or Units) that May
Number of Shares (b) Average Announced Yet Be Purchased
(or Units) Price Paid per Plans or Under the Plans or
Period Purchased 1 Share (or Unit)1 Programs Programs
- --------------------------------------------------------------------------------------------------------------
January 1, 2005 to 738,156 $31.50 -- --
January 31, 2005
February 1 to 1,973,326 $32.27 -- --
February 28, 2005
March 1, 2005 to 2,890,569 $33.87 -- --
March 31, 2005
- --------------------------------------------------------------------------------------------------------------
Total 5,602,051 $32.99 -- --
- --------------------------------------------------------------------------------------------------------------
- -------------------
1 The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill
requirements in connection with Edison International's (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Stock Purchase
Plan, and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan
terms or participant elections. Edison International did not control the quantity of shares purchased, the timing of the
purchases or the price of the shares purchased in these transactions. The shares were never registered in Edison International's
name and none of the shares purchased were retired as a result of the transactions.
Page 82
Item 6. Exhibits
Edison International
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. Section 1350
Page 83
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By /s/ THOMAS M. NOONAN
---------------------------------
THOMAS M. NOONAN
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Dated: May 9, 2005