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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 800)
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
(626) 302-1212
(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 |_| No |X|
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest
practicable date:
Class Outstanding at August 5, 2005
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Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Financial Statements:
Consolidated Statements of Income - Three and Six Months
Ended June 30, 2005 and 2004 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2005 and 2004 1
Consolidated Balance Sheets - June 30, 2005
and December 31, 2004 2
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2005 and 2004 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk 43
Item 4. Controls and Procedures 43
Part II. Other Information:
Item 1. Legal Proceedings 44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 45
Item 4. Submission of Matters to a Vote of Security Holders 46
Item 6. Exhibits 47
Signature
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SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Operating revenue $ 2,203 $ 2,176 $ 4,110 $ 3,872
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Fuel 265 248 520 296
Purchased power 743 527 1,131 1,107
Provisions for regulatory adjustment clauses - net (41) (33) 24 (51)
Other operation and maintenance 570 580 1,169 1,159
Depreciation, decommissioning and amortization 231 222 454 439
Property and other taxes 47 46 97 91
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Total operating expenses 1,815 1,590 3,395 3,041
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Operating income 388 586 715 831
Interest and dividend income 10 4 20 9
Other nonoperating income 18 9 35 39
Interest expense - net of amounts capitalized (96) (101) (198) (204)
Other nonoperating deductions (11) (15) (18) (23)
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Income before tax and minority interest 309 483 554 652
Income tax 58 155 124 223
Minority interest 85 85 132 85
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Net income 166 243 298 344
Dividends on preferred and preference stock
not subject to mandatory redemption 5 1 6 3
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Net income available for common stock $ 161 $ 242 $ 292 $ 341
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Net income $ 166 $ 243 $ 298 $ 344
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 1 2 2
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Comprehensive income $ 167 $ 244 $ 300 $ 346
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions 2005 2004
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(Unaudited)
ASSETS
Cash and equivalents $ 176 $ 122
Restricted cash 55 61
Receivables, less allowances of $30 and $31
for uncollectible accounts at respective dates 691 618
Accrued unbilled revenue 519 320
Fuel inventory 8 8
Materials and supplies 197 188
Accumulated deferred income taxes - net 157 134
Regulatory assets 752 553
Prepayments and other current assets 138 72
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Total current assets 2,693 2,076
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Nonutility property - less accumulated provision
for depreciation of $547 and $554 at respective dates 1,017 960
Nuclear decommissioning trusts 2,793 2,757
Other investments 149 170
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Total investments and other assets 3,959 3,887
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Utility plant, at original cost:
Transmission and distribution 16,042 15,685
Generation 1,372 1,356
Accumulated provision for depreciation (4,629) (4,506)
Construction work in progress 871 789
Nuclear fuel, at amortized cost 141 151
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Total utility plant 13,797 13,475
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Regulatory assets 3,169 3,285
Other deferred charges 555 567
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Total deferred charges 3,724 3,852
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Total assets $ 24,173 $ 23,290
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions, except share amounts 2005 2004
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 148 $ 88
Long-term debt due within one year 597 246
Preferred stock to be redeemed within one year -- 9
Accounts payable 682 700
Accrued taxes 551 357
Accrued interest 113 115
Customer deposits 177 168
Book overdrafts 247 232
Regulatory liabilities 766 490
Other current liabilities 619 643
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Total current liabilities 3,900 3,048
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Long-term debt 4,797 5,225
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Accumulated deferred income taxes - net 2,789 2,865
Accumulated deferred investment tax credits 123 126
Customer advances and other deferred credits 618 510
Power-purchase contracts 88 130
Preferred stock subject to mandatory redemption -- 139
Accumulated provision for pensions and benefits 468 417
Asset retirement obligations 2,242 2,183
Regulatory liabilities 3,217 3,356
Other long-term liabilities 250 232
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Total deferred credits and other liabilities 9,795 9,958
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Total liabilities 18,492 18,231
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Commitments and contingencies (Notes 2, 4, and 6)
Minority interest 426 409
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 346 350
Accumulated other comprehensive loss (15) (17)
Retained earnings 2,227 2,020
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Total common shareholder's equity 4,726 4,521
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Preferred and preference stock
not subject to mandatory redemption 529 129
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Total shareholders' equity 5,255 4,650
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Total liabilities and shareholders' equity $ 24,173 $ 23,290
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
June 30,
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In millions 2005 2004
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(Unaudited)
Cash flows from operating activities:
Net income $ 298 $ 344
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization 454 439
Other amortization 47 46
Minority interest 132 85
Deferred income taxes and investment tax credits (133) 163
Regulatory assets - long-term 214 199
Regulatory liabilities - long-term (127) (50)
Other assets 41 (3)
Other liabilities 120 61
Receivables and accrued unbilled revenue (272) (152)
Inventory, prepayments and other current assets (68) (47)
Regulatory assets - short-term (199) (404)
Regulatory liabilities - short-term 276 299
Accrued interest and taxes 192 97
Accounts payable and other current liabilities (36) (131)
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Net cash provided by operating activities 939 946
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Cash flows from financing activities:
Long-term debt issued and issuance costs 983 1,598
Long-term debt repaid (1,041) (842)
Bonds remarketed - net -- 350
Issuance of preference stock 395 --
Redemption of preferred stock (148) (2)
Rate reduction notes repaid (116) (115)
Short-term debt financing - net 60 (200)
Change in book overdrafts 15 36
Shares purchased for stock-based compensation (63) (14)
Proceeds from stock option exercises 33 10
Minority interest (115) (49)
Dividends paid (74) (448)
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Net cash provided (used) by financing activities (71) 324
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Cash flows from investing activities:
Capital expenditures (774) (718)
Acquisition costs related to nonutility generation plant -- (285)
Contributions to and earnings from
nuclear decommissioning trusts - net (51) (42)
Sales of investments in other assets 11 2
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Net cash used by investing activities (814) (1,043)
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Effect of consolidation of variable interest entities -- 79
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Net increase in cash and equivalents 54 306
Cash and equivalents, beginning of period 122 95
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Cash and equivalents, end of period $ 176 $ 401
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary
for a fair presentation of the financial position, results of operations and cash flows in accordance with
accounting principles generally accepted in the United States for the periods covered by this report. The
results of operations for the period ended June 30, 2005 are not necessarily indicative of the operating results
for the full year.
The quarterly report should be read in conjunction with Southern California Edison Company's (SCE) 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
SCE's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2004 Annual Report. SCE follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the June 30, 2005 financial statement presentation.
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 (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. SCE 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. SCE 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. SCE 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 in Note 1 under "Stock-Based Compensation."
The American Jobs Creation Act of 2004 included a tax deduction on qualified production activities income
(including income from the sale of electricity). In December 2004, the FASB issued guidance that this deduction
should be accounted for as a special deduction, rather than a tax rate reduction. Accordingly, the special
deduction is recorded in the year it is earned. The tax deduction is not expected to materially affect SCE's
2005 financial statements. SCE is evaluating the potential effect for future years.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets included in the consolidated balance sheets are:
June 30, December 31,
In millions 2005 2004
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(Unaudited)
Current:
Regulatory balancing accounts $ 523 $ 371
Direct access procurement charges 111 109
Purchased-power settlements 60 62
Other 58 11
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752 553
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Long-term:
Flow-through taxes - net 1,048 1,018
Rate reduction notes - transition cost deferral 593 739
Unamortized nuclear investment - net 523 526
Nuclear-related ARO investment - net 265 272
Unamortized coal plant investment - net 81 78
Unamortized loss on reacquired debt 326 250
Direct access procurement charges 90 141
Environmental remediation 58 55
Purchased-power settlements 62 91
Other 123 115
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3,169 3,285
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Total regulatory assets $ 3,921 $ 3,838
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory liabilities included in the consolidated balance sheets are:
June 30, December 31,
In millions 2005 2004
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(Unaudited)
Current:
Regulatory balancing accounts $ 609 $ 357
Direct access procurement charges 111 109
Other 46 24
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766 490
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Long-term:
ARO 765 819
Costs of removal 2,137 2,112
Direct access procurement charges 90 141
Employee benefits plans 223 200
Other 2 84
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3,217 3,356
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Total regulatory liabilities $ 3,983 $ 3,846
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Income Taxes
SCE's income tax expense decreased $97 million and $99 million for the three- and six-month periods ended June
30, 2005, respectively, as compared to the same periods in 2004, primarily due to a decrease in pre-tax income as
well as changes in property-related flow-through items, reductions in accrued tax liabilities made in 2005 to
reflect progress in settlement negotiations relating to prior year tax liabilities, and adjustments to tax
balances made in 2005.
SCE's composite federal and state statutory rate was approximately 40% for the three- and six-month periods ended
June 30, 2005. The lower effective tax rate of 26% and 29% realized in the three- and six-month periods ended
June 30, 2005, respectively, was primarily due to property-related flow-through items, a reduction in accrued tax
liabilities, as well as adjustments to tax balances.
Stock-Based Compensation
SCE 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. SCE accounts for these plans using the intrinsic value
method. Upon grant of stock options, 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
value of the underlying common stock on the date of grant. The following table illustrates the effect on net
income if SCE had used the fair-value accounting method.
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Net income available for common stock, as reported $ 161 $ 242 $ 292 $ 341
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 8 2 14 4
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 9 2 15 4
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Pro forma net income available for common stock $ 160 $ 242 $ 291 $ 341
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Supplemental Cash Flows Information
Six Months Ended
June 30,
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In millions 2005 2004
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(Unaudited)
Cash payments for interest and taxes:
Interest - net of amounts capitalized $ 168 $ 151
Tax payments (receipts) 44 (25)
Non-cash investing and financing activities:
Details of debt exchange:
Pollution control bonds redeemed $ (204) --
Pollution control bonds issued 204 --
Details of consolidation of variable interest entities:
Assets -- $ 458
Liabilities -- (537)
Reoffering of pollution-control bonds -- $ 196
Details of pollution-control bond redemption:
Release of funds held in trust -- $ 20
Pollution-control bonds redeemed -- (20)
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Note 2. Regulatory Matters
Further information on these regulatory matters is described in Note 2 of "Notes to Consolidated Financial
Statements" included in SCE'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 SCE's 2004 Annual Report, in
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 2004, the California Public Utilities Commission (CPUC) issued its decision on how the CDWR's power
charge revenue requirement for 2004 through 2013 will be allocated among the investor-owned utilities. On June
30, 2005, the CPUC granted, in part, San Diego Gas & Electric's (SDG&E) petition for modification of the December
2004 decision. The June 30, 2005 decision adopted a methodology that retains the cost-follows-contract
allocation of the avoidable costs, and allocates the unavoidable costs associated with the contracts: 42.2% to
Pacific Gas and Electric's (PG&E) customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. This newly
adopted allocation methodology decreases the total costs allocated to SDG&E's customers and increases the total
costs allocated to SCE's and PG&E's customers, relative to the December 2004 decision. Amounts billed to SCE's
customers for electric power purchased and sold by the CDWR are remitted directly to the CDWR and are not
recognized as revenue by SCE and therefore have no impact on SCE's earnings.
Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms
Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain shareholder
incentives for its performance achievements in delivering demand-side management and energy efficiency programs.
On June 10, 2005, SCE and the Office of Ratepayer Advocates (ORA) executed a settlement agreement for SCE's
outstanding issues concerning SCE shareholder incentives and performance achievements resulting from the
demand-side management, energy efficiency, and low-income energy efficiency programs from program years
1994-2004. In addition, the settlement addresses shareholder incentives and performance achievements for program
years 1994-1998, anticipated but not yet claimed. The settlement agreement recommends, among other things, that
SCE be entitled to immediately recover 92% of the total of SCE's current claims and future claims related to
SCE's pre-1998 energy efficiency programs. SCE's total claim for program years 1994-2004 made in 2000 through
2008, including interest, franchise fees and uncollectibles, is approximately $46 million. The settling parties
agreed that it is reasonable for SCE to recover approximately $42 million of these claims in the near future as
full recovery of all of SCE's outstanding claims as well as future claims related to SCE's pre-1998 energy
efficiency programs. The settlement agreement requires CPUC approval. On June 13, 2005, SCE and the ORA filed a
joint motion requesting CPUC adoption of the settlement agreement. A decision is expected in the fourth quarter
of 2005, which if approved, would result in the recognition of a $42 million increase in earnings. SCE has
collected and deferred most of the expected claims in rates, and expects to recover the remaining portion of the
claims over a 12-month period beginning on January 1, 2006.
Energy Resource Recovery Account (ERRA) Proceedings
In an October 2002 decision, the CPUC established the Energy Resource Recovery Account (ERRA) as the rate-making
mechanism to track and recover SCE's: (1) fuel costs related to its generating stations; (2) purchased-power
costs related to cogeneration and renewable contracts; (3) purchased-power costs related to existing interutility
and bilateral contracts that were entered into before January 17, 2001; and (4) new procurement-related costs
incurred on or after January 1, 2003 (the date on which the CPUC transferred back to SCE the responsibility for
procuring energy resources for its customers). SCE recovers these costs on a cost-recovery basis, with no markup
for return or profit. SCE files annual forecasts of the above-described costs that it expects to incur during
the following year. As these costs are subsequently incurred, they will be tracked and recovered through the
ERRA, but are subject to a reasonableness review in a separate annual ERRA application. If the ERRA
overcollection or undercollection exceeds 5% of SCE's prior year's generation revenue, the CPUC has established a
"trigger" mechanism, whereby SCE can request an emergency rate adjustment in addition to the annual forecast and
reasonableness ERRA applications.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ERRA Trigger Mechanism Filing
On March 25, 2005, SCE submitted a CPUC rate application under the ERRA trigger mechanism, as the recorded
undercollection in its ERRA balancing account as of February 28, 2005 had reached 9.7% of recorded 2004
generation revenue, well above the 5% threshold for an emergency rate adjustment established by the CPUC. SCE's
undercollection had been less than 4% of recorded 2004 generation revenue at the end of January 2005. A
combination of higher procurement costs, a delay in approval of the 2005 ERRA rate change and other factors
contributed to the large increase in the undercollection amount in February 2005. SCE's trigger application
stated that if the CPUC retained recently authorized ERRA rate levels rather than increasing rates, the
undercollection would be recovered by mid-September 2005. On May 26, 2005, the CPUC issued a decision granting
SCE's application to maintain its previously authorized ERRA rate levels.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its procurement-related
costs for calendar year 2004 to be reasonable, and that its contract administration and economic dispatch
operations during 2004 complied with its CPUC-adopted procurement plan. In addition, SCE requested recovery of
approximately $13 million associated with Nuclear Unit Incentive Procedure rewards for efficient operation of the
Palo Verde Nuclear Generating Station (Palo Verde) and approximately $7 million in administrative and general
costs incurred to carry out the CPUC's directive to begin procuring energy supplies on January 1, 2003 following
the California energy crisis. The ORA is scheduled to issue its report on SCE's 2004 costs and operations in
mid-August 2005. Evidentiary hearings are scheduled to begin in September 2005 and a decision is expected in
late December 2005 or early January 2006.
Generation Procurement Proceedings
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan was filed on March 7, 2005. On July 21, 2005, the CPUC issued a decision
approving SCE's 2005 renewable procurement plan and deferred a ruling on SCE's renewable procurement plan for
2006 through 2014. This decision also approved the methodology advocated by SCE for determining the amount by
which reported renewable procurement should be adjusted to reflect line losses.
In addition, the decision states that SCE cannot count procurement from certain geothermal facilities towards its
1% annual renewable procurement requirement, unless such procurement is from production certified as
"incremental" by the California Energy Commission (CEC). A 2003 CPUC decision had held that SCE could count
procurement from these geothermal facilities toward its 1% annual renewable procurement requirement.
The geothermal facilities have applied to the CEC for certification of a portion of the facilities' production as
"incremental." A decision from the CEC is expected in late August or early September 2005. It is not clear
whether any of the facilities' production will be certified as "incremental" or how much, if any, of the
"incremental" production from the facilities will be allocated to SCE's procurement under its contract with the
facilities if the CEC certification is granted.
Depending upon the amount, if any, of CEC certified "incremental" production allocated to SCE's procurement under
its contract and the manner in which the CPUC implements its flexible rules for
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
compliance with renewable procurement obligations, SCE may not be in compliance with its statutory renewable
procurement obligations for 2003 through 2006 and could be subject to penalties for those years. The maximum
penalty is $25 million per year. To comply with renewable procurement mandates and avoid penalties for years
beyond 2006, SCE will either need to sign new contracts and/or extend existing renewable qualifying facility
contracts.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and
conducted negotiations with bidders regarding potential procurement contracts. On June 30, 2005, the CPUC issued
a resolution approving six renewable contracts resulting from the solicitation. The CPUC's July 21, 2005
decision referenced above also approved SCE's proposed new request for offers for additional renewable contracts,
which SCE contemplates initiating in the third quarter of 2005.
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in
southern California. SCE has issued a Request for Offers (RFO) for new generation resources. SCE has solicited
offers for power-purchase agreements lasting up to 10 years from new generation facilities with delivery under
the agreement beginning between June 1, 2006 and August 1, 2008. SCE has filed an application with the CPUC
seeking approval of the RFO and the power-purchase agreements executed under the RFO. SCE is seeking recovery of
the costs of the contracts, through the Federal Energy Regulatory Commission (FERC)-jurisdictional rates, from
all affected customers. In addition, SCE seeks CPUC assurance of full cost recovery in CPUC-approved rates, if
the FERC denies any recovery. Any power-purchase agreement that SCE executes as a result of the RFO will be
contingent on CPUC approval of the contract and assurance of full cost recovery.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary. For a
discussion of item (1) above, see the "Holding Company Proceeding" disclosure in Note 2 of "Notes to Consolidated
Financial Statements" included in SCE's 2004 Annual Report.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed
the proceeding without addressing some of the issues the proceeding raised (such as the appropriateness of the
large utilities' holding company structure and dividend policies), the CPUC may rule on or investigate these
issues in the future.
California Independent System Operator (ISO) Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim,
Azusa, Banning and Riverside, California over the proper allocation and characterization of certain charges. The
order reversed an arbitrator's award that had affirmed the ISO's characterization in May 2000 of the charges as
Intra-Zonal Congestion costs and allocation of those charges to Scheduling Coordinators (SCs) in the affected
zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from SCs in
the affected zone to the responsible Participating Transmission Owner, SCE, and to do so within 60 days of the
April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the Participating
Transmission Owner but also will
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. SCE filed a request for clarification with
the FERC asking the FERC to clarify that SCE can reflect and recover the disputed costs in SCE's reliability
services rates. On June 8, 2005, the FERC denied the clarification, noting that during the appeal, the FERC's
order is stayed, therefore SCE is not required to pay at this time. SCE may seek recovery in its reliability
service rates of the costs should SCE be required to pay these costs.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in SCE's 2004 Annual Report, the CPUC issued a final decision in
December 2004 on SCE's application regarding the post-2005 operation of Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant
parties in an effort to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been
reached to date. Because resolution has not been reached and because of the lead times required for installation
of certain pollution-control equipment and other upgrades necessary for post-2005 operation, it is probable that
Mohave will shut down for at least several years, and perhaps permanently, at the end of 2005. The outcome of
the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the presence or
absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. SCE's 2006
ERRA forecast application assumes Mohave is an unavailable resource for power for 2006. Because SCE expects to
recover Mohave shut-down costs in future rates, the outcome of this matter is not expected to have a material
impact on earnings.
For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.
Transmission Proceeding
In August and November 2002, the FERC issued opinions affirming a September 1999 administrative law judge
decision to disallow, among other things, recovery by SCE and the other California public utilities of costs
reflected in network transmission rates associated with ancillary services and losses incurred by the utilities
in administering existing wholesale transmission contracts after implementation of the restructured California
electric industry. SCE has incurred approximately $80 million of these unrecovered costs since 1998. In
addition, SCE has accrued interest on these unrecovered costs. The three California utilities appealed the
decisions to the D.C. Circuit Court. On July 12, 2005, the D.C. Circuit Court vacated the FERC's August and
November 2002 orders, and remanded the case to the FERC for further proceedings. SCE believes that the D.C.
Circuit Court's decision increases the likelihood that it will recover these costs.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in SCE's 2004 Annual Report, SCE is participating in several related
proceedings seeking recovery of refunds from sellers of electricity and natural gas who allegedly manipulated the
electric and natural gas markets.
Page 12
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including
SCE, PG&E, the State of California and various consumer class action representatives) settling various claims
stated in proceedings at the FERC and in San Diego County Superior Court that El Paso had manipulated interstate
capacity and engaged in other anticompetitive behavior in the natural gas markets in order to unlawfully raise
gas prices at the California border in 2000-2001. The United States District Court has issued an order approving
the stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC decision, SCE was
required to refund to customers amounts received under the terms of the El Paso settlement (net of legal and
consulting costs) through its ERRA mechanism. In June 2004, SCE received its first settlement payment of
$76 million. Approximately $66 million of this amount was credited to purchased-power expense, and was refunded
to SCE's ratepayers through the ERRA over the following twelve months, and the remaining $10 million was used to
offset SCE's incurred legal costs. El Paso has elected to prepay the additional settlement payments due over a
20-year period and, as a result, SCE received $66 million in May 2005. Amounts El Paso refunds to the CDWR will
result in reductions in the CDWR's revenue requirement allocated to SCE in proportion to SCE's share of the
CDWR's power charge revenue requirement.
On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant
Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in Chapter 11
bankruptcy proceedings pending in Texas. Among other things, the settlement terms provide for cash and
equivalent refunds totaling $320 million, of which SCE's allocated share is approximately $68 million. The
settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of one of the
Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual value of
the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant
settlement was approved by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. In April
and May 2005, SCE received its allocated $68 million in cash settlement proceeds. SCE continues to hold its
$33 million share of the allowed, unsecured bankruptcy claim. The Mirant settlement will be refunded to
ratepayers as described below.
On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Enron
Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11
bankruptcy proceedings pending in New York. Among other things, the settlement terms provide for cash and
equivalent payments from Enron totaling approximately $47 million and an allowed, unsecured claim in the
bankruptcy against one of the Enron entities in the amount of $875 million. SCE's allocable share of both the
cash and allowed claim portions of the settlement consideration has not yet been finally determined, and the
value of an allocable share of the allowed claim will be determined as part of the resolution of the Enron
parties' bankruptcies. The settlement remains subject to the approvals of the FERC, the CPUC and the Enron
bankruptcy court. The Enron settlement proceeds will be refunded to ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum
Account (ESMA) for the purpose of recording the foregoing settlement proceeds (excluding the El Paso settlement)
from energy providers and allocating them in accordance with the terms of the October 2001 settlement agreement
entered into by SCE and the CPUC which settled SCE's lawsuit against the CPUC. This lawsuit sought full recovery
of SCE's electricity procurement costs incurred during the energy crisis. The resolution provides a mechanism
whereby portions of the settlement proceeds recorded in the ESMA will be allocated to recovery of SCE's
litigation costs and expenses in the FERC refund proceedings described above and a 10% shareholder incentive
pursuant to the CPUC litigation settlement agreement. Remaining amounts for each settlement are to be refunded
to ratepayers through the ERRA mechanism. In the second quarter of 2005, SCE recorded a $7 million
Page 13
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
increase to other nonoperating income as a shareholder incentive related to the Mirant refund received during the
second quarter of 2005.
Note 3. Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
SCE previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in SCE's 2004 Annual
Report that it expects to contribute approximately $38 million to its pension plans in 2005. As of June 30,
2005, $5 million in contributions have been made. SCE anticipates that its original expectation will be met by
year-end 2005.
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 25 $ 22 $ 49 $ 44
Interest cost 40 41 80 82
Expected return on plan assets (54) (58) (108) (115)
Net amortization and deferral 6 6 12 11
-------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 17 11 33 22
Regulatory adjustment - deferred (2) -- (4) --
-------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 15 $ 11 $ 29 $ 22
-------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
SCE previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in SCE's 2004 Annual
Report that it expects to contribute approximately $76 million to its postretirement benefits other than pensions
plans in 2005. As of June 30, 2005, $12 million in contributions have been made. SCE anticipates that its
original expectation will be met by year-end 2005.
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 11 $ 11 $ 22 $ 22
Interest cost 30 32 60 65
Expected return on plan assets (26) (27) (51) (55)
Amortization of unrecognized prior service costs (7) (8) (14) (15)
Amortization of unrecognized loss 12 16 24 31
-------------------------------------------------------------------------------------------------------------------
Total expense $ 20 $ 24 $ 41 $ 48
-------------------------------------------------------------------------------------------------------------------
Page 14
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Contingencies
In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory
proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.
Environmental Remediation
SCE 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.
SCE 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. SCE 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, SCE records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 22 identified sites is $84 million. The ultimate
costs to clean up SCE'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. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $113 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In
addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE
also has 33 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to
$10 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $31 million of its
recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this
mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at
its remaining sites through customer rates. SCE has recorded a regulatory asset of $57 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer rates.
SCE'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 SCE 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.
Page 15
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
next several years are expected to range from $12 million to $25 million. Recorded costs for the twelve months
ended June 30, 2005 were $12 million.
Based on currently available information, SCE 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, SCE believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of new sites, will not require
material revisions to such estimates.
Federal Income Taxes
Edison International has reached a settlement with the IRS on tax issues and pending affirmative claims relating
to its 1991-1993 tax years. This settlement, which was signed by Edison International in March 2005 and approved
by the United States Congress Joint Committee on Taxation on July 27, 2005, will result in a third quarter 2005
net earnings benefit for Edison International of approximately $56 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting
deficiencies, including deficiencies asserted against SCE, 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 benefit
SCE as future tax deductions.
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 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.
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
Page 16
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reported events, the CPUC could institute its own proceedings to determine whether and in what amounts to order
refunds or disallowances of past and potential PBR rewards for customer satisfaction, injury and illness
reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional
penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential
amount of refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service
planning group of SCE's transmission and distribution business unit altered or omitted data in attempts to
influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The
results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or
penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate customer
satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in
income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of about
$10 million for 2003.
SCE has been keeping the CPUC informed of the progress of SCE's internal investigation. On June 25, 2004, SCE
submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees in the
design organization of the transmission and distribution business unit deliberately altered customer contact
information in order to affect the results of customer satisfaction surveys. At least 36 design organization
personnel engaged in deliberate misconduct including alteration of customer information before the data were
transmitted to the independent survey company. Because of the apparent scope of the misconduct, SCE proposed to
refund to ratepayers $7 million of the PBR rewards previously received and forego an additional $5 million of the
PBR rewards pending that are both attributable to the design organization's portion of the customer satisfaction
rewards for the entire PBR period (1997-2003). In addition, during its investigation, SCE determined that it
could not confirm the integrity of the method used for obtaining customer satisfaction survey data for meter
reading. Thus, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards
associated with meter reading. As a result of these findings, SCE accrued a $9 million charge in 2004 for the
potential refunds of rewards that have been received.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of
several supervisory personnel, updating system process and related documentation for survey reporting, and
implementing additional supervisory controls over data collection and processing. The PBR performance incentive
mechanism for customer satisfaction expired after calendar year 2003 pursuant to the CPUC's decision in SCE's
2003 GRC.
The CPUC has not yet opened a formal investigative proceeding into this matter. However, the Consumer Protection
and Safety Division (CPSD) of the CPUC has submitted several data requests to SCE and has requested an
opportunity to interview a number of current and former SCE employees in the design organization. SCE has
responded to these requests and the CPSD has conducted interviews of approximately 20 employees who were
disciplined for misconduct.
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into
the accuracy of SCE's employee injury and illness reporting. The yearly results of employee injury and illness
reporting to the CPUC are used to determine the amount of the incentive
Page 17
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received
$20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, would have been
entitled to an additional $15 million for 2001 through 2003 ($5 million for each year).
On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings
concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. Under the PBR
mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident rate, which
included two equally weighted measures: Occupational Safety and Health Administration (OSHA) recordable
incidents and first aid incidents. The major issue disclosed in the investigative findings to the CPUC was that
SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid
incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact
of these inaccuracies did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the PBR mechanism
for any year before 2004, and it return to ratepayers the $20 million it has already received. Therefore, SCE
accrued a $20 million charge in 2004 for the potential refund of these rewards. SCE has also proposed to
withdraw the pending requests for rewards for the 2001-2002 time frames. SCE has not yet filed a request related
to its performance for 2003 under the PBR mechanism.
SCE is taking other remedial action to address the issues identified, including revising its organizational
structure and overall program for environmental, health and safety compliance. SCE also took disciplinary action
against twenty-four individuals in several SCE business areas in early June 2005. SCE submitted a report on the
results of its investigation to the CPUC on December 3, 2004.
As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative proceeding into this
matter. However, the CPSD did submit several data requests to SCE to which SCE has responded.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE has conducted an investigation
into the PBR system reliability metric for the years 1997 through 2003. Since the inception of PBR payments in
1997, SCE has received $8 million in rewards and has applied for an additional $5 million reward based on
frequency of outage data for 2001. For 2002, SCE's data indicates that it earned no reward and incurred no
penalty. Based on the application of the PBR mechanism, SCE would be penalized $5 million for 2003; however, as
indicated above, SCE has not filed a request related to its performance under the PBR mechanism for 2003.
On February 28, 2005, SCE provided its investigatory report on the PBR system reliability incentive mechanism to
the CPUC concluding that the reliability reporting system is working as intended.
The CPUC is not expected to act on SCE's recent advice letter for 2004 or the pending PBR advice letters for 2001
and 2002 until the CPSD has completed its investigation of these matters. SCE has agreed to file its PBR advice
letter for 2003 after the CPSD has completed its investigation.
Navajo Nation Litigation
In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of
Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates,
Page 18
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Salt River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement
for Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced
and Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal
supplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, and
punitive damages of not less than $1 billion, as well as a declaration that Peabody's lease and contract rights
to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody's motion to strike the Navajo
Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District Court
denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District's
motion for its separate dismissal from the lawsuit.
Certain issues related to this case were addressed by the United States Supreme Court in a separate legal
proceeding filed by the Navajo Nation in the United States Court of Federal Claims against the United States
Department of Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary
duty concerning negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and
Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach of a
fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for
summary judgment in the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and
Peabody's April 2003 motions to dismiss or, in the alternative, for summary judgment. The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off. Pursuant to a joint
request of the parties, the D.C. District Court granted a 120-day stay of the action to allow the parties to
attempt to resolve, through facilitated negotiations, all issues associated with Mohave. Negotiations are
ongoing and the stay has been continued until further order of the court.
The D.C. Circuit Court, acting on a suggestion on remand filed by the Navajo Nation, held in an October 24, 2003
decision that the Supreme Court's March 4, 2003 decision was focused on three specific statutes or regulations
and therefore did not address the question of whether a network of other statutes, treaties and regulations
imposed judicially enforceable fiduciary duties on the United States during the time period in question. The
Government and the Navajo Nation both filed petitions for rehearing of the October 24, 2003 D.C. Circuit Court
decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the D.C. Circuit Court issued an
order remanding the case against the Government to the Court of Federal Claims, which conducted a status
conference on May 18, 2004. As a result of the status conference discussion, the Navajo Nation and the
Government are in the process of briefing the remaining issues following remand. As a result of the status
conference discussion, the Court of Federal Claims has ordered the Navajo Nation and the Government to brief the
remaining issues following remand. The Navajo Nation's initial brief was filed in the remanded Court of Federal
Claims matter on August 26, 2004, and the Government filed its responsive brief on December 10, 2004. The Navajo
Nation subsequently obtained an extension of the due date for its reply brief while the Court of Federal Claims
is considering a motion to strike filed by the Government. Peabody's motion to intervene in the remanded Court
of Federal Claims case as a party was denied. On February 24, 2005, the Court of Federal Claims denied the
motion to strike filed by the Government, but authorized the Government to file a supplemental brief and
appendix, which was filed by the Government on March 23, 2005. On April 25, 2005, the Navajo Nation filed its
reply brief and also filed a motion to strike the Government's supplemental brief and all of the exhibits
attached to that brief. Oral argument on the motion to strike is scheduled for September 28, 2005.
Page 19
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Spent Nuclear Fuel
Under federal law, the United States Department of Energy (DOE) is responsible for the selection and construction
of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not
meet its obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain
when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended
delays by the DOE have led to the construction of costly alternatives and associated siting and environmental
issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through
April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to
0.1(cent)-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating
agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for DOE's
failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The case is currently
stayed pending development in other spent nuclear fuel cases also before the United States Court of Federal
Claims.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent
nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel
storage installation. Movement of Unit 1 spent fuel from the Unit 2 spent fuel pool to the independent spent
fuel storage installation is complete. There is now sufficient space in the
Page 20
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
SCE's reportable business segments include the rate-regulated electric utility segment and the variable interest
entity (VIE) segment. The VIEs were consolidated as of March 31, 2004. Additional details on the VIE segment
are in Note 1 of "Notes to Consolidated Financial Statements" included in SCE's 2004 Annual Report. The VIEs are
gas-fired power plants that sell both electricity and steam. The VIE segment consists of non-rate-regulated
entities (all in California). SCE's management has no control over the resources allocated to the VIE segment
and does not make decisions about its performance.
SCE's business segment information including all line items with VIE activities is:
Electric
In millions Utility VIEs Eliminations SCE
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Balance Sheet Items as of June 30, 2005:
Cash $ 88 $ 88 $ -- $ 176
Accounts receivable-net 646 170 (125) 691
Materials and supplies 181 16 -- 197
Prepayments and other current assets 136 2 -- 138
Nonutility property-net of depreciation 663 354 -- 1,017
Other deferred charges 545 10 -- 555
Total assets 23,658 640 (125) 24,173
Accounts payable 660 147 (125) 682
Other current liabilities 618 1 -- 619
Long-term debt 4,743 54 -- 4,797
Asset retirement obligations 2,230 12 -- 2,242
Minority interest -- 426 -- 426
Total liabilities and shareholder's equity 23,658 640 (125) 24,173
Balance Sheet Items as of December 31, 2004:
Cash and equivalents $ 32 $ 90 $ -- $ 122
Accounts receivable-net 569 153 (104) 618
Materials and supplies 173 15 -- 188
Prepayments and other current assets 69 3 -- 72
Nonutility property-net of depreciation 583 377 -- 960
Other deferred charges 562 5 -- 567
Total assets 22,751 643 (104) 23,290
Accounts payable 638 166 (104) 700
Other current liabilities 641 2 -- 643
Long-term debt 5,171 54 -- 5,225
Customer advances and other deferred credits 498 12 -- 510
Minority interest -- 409 -- 409
Total liabilities and shareholder's equity 22,751 643 (104) 23,290
-------------------------------------------------------------------------------------------------------------------
Page 21
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Electric
In millions Utility VIEs Eliminations* SCE
-------------------------------------------------------------------------------------------------------------------
Income Statement Items for the (Unaudited)
Three Months Ended June 30, 2005:
Operating revenue $ 2,101 $ 323 $ (221) $ 2,203
Fuel 60 205 -- 265
Purchased power 964 -- (221) 743
Other operation and maintenance 546 24 -- 570
Depreciation, decommissioning and amortization 222 9 -- 231
Total operating expenses 1,798 238 (221) 1,815
Operating income 303 85 -- 388
Minority interest -- 85 -- 85
Net income 166 -- -- 166
Income Statement Items for the
Six Months Ended June 30, 2005:
Operating revenue $ 3,907 $ 597 $ (394) $ 4,110
Fuel 122 398 -- 520
Purchased power 1,525 -- (394) 1,131
Other operation and maintenance 1,121 48 -- 1,169
Depreciation, decommissioning and amortization 435 19 -- 454
Total operating expenses 3,324 465 (394) 3,395
Operating income 583 132 -- 715
Minority interest -- 132 -- 132
Net income 298 -- -- 298
Income Statement Items for the
Three Months Ended June 30, 2004:
Operating revenue $ 2,082 $ 302 $ (208) $ 2,176
Fuel 61 187 -- 248
Purchased power 735 -- (208) 527
Other operation and maintenance 559 21 -- 580
Depreciation, decommissioning and amortization 213 9 -- 222
Total operating expenses 1,581 217 (208) 1,590
Operating income 501 85 -- 586
Minority interest -- 85 -- 85
Net income 243 -- -- 243
Income Statement Items for the
Six Months Ended June 30, 2004:
Operating revenue $ 3,778 $ 302 $ (208) $ 3,872
Fuel 109 187 -- 296
Purchased power 1,315 -- (208) 1,107
Other operation and maintenance 1,138 21 -- 1,159
Depreciation, decommissioning and amortization 430 9 -- 439
Total operating expenses 3,032 217 (208) 3,041
Operating income 746 85 -- 831
Minority interest -- 85 -- 85
Net income 344 -- -- 344
-------------------------------------------------------------------------------------------------------------------
* VIE segment revenue includes sales to the electric utility segment, which is eliminated in revenue and
purchased power in the consolidated statements of income.
Page 22
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Commitments
The following is an update to SCE's commitments. See Note 9 of "Notes to Consolidated Financial Statements"
included in SCE's 2004 Annual Report for a detailed discussion.
Power-Purchase Contracts
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's revised
purchased-power capacity payment commitments under these contracts are currently estimated to be $32 million for
2005, $95 million for 2006, $101 million for 2007, and $84 million for 2008.
Leases
During the first quarter of 2005, SCE entered into new power contracts, in which SCE takes virtually all of the
power. In accordance with an accounting standard, these power contracts are classified as operating leases.
SCE's commitments under these operating leases are currently estimated to be $39 million for 2005, $55 million for
2006, $50 million for 2007, and $43 million for 2008.
Indemnity Provided as Part of the 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 7. Preferred Stock Subject to Mandatory Redemption
SCE redeemed 807,000 shares of 7.23% $100 cumulative preferred stock at par value on April 30, 2005 and 637,500
shares of 6.05% $100 cumulative preferred stock at par value on May 20, 2005.
Note 8. Preferred and Preference Stock Not Subject to Mandatory Redemption
SCE's authorized shares are: $25 cumulative preferred - 24 million and preference - 50 million. SCE issued 4
million shares of 5.349% Series A $100 stated value non-cumulative preference stock on April 20, 2005. The
preference stock ranks junior to all of the preferred stock and senior to all common stock. The preference
shares may not be redeemed prior to April 30, 2010. After that date, SCE may, at its option, redeem the shares
in whole or in part and the dividend rate may be adjusted. The preference stock is not convertible into shares
of any other class or series of SCE's capital stock or any other security. Shares of SCE's preferred stock have
liquidation and dividend preferences over shares of SCE's preference stock and common stock.
Page 23
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
INTRODUCTION
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three-
and six-month periods ended June 30, 2005 discusses material changes in the financial condition, results of
operations and other developments of Southern California Edison Company (SCE) since December 31, 2004, and as
compared to the three- and six-month periods ended June 30, 2004. This discussion presumes that the reader has
read or has access to SCE's MD&A for the calendar year 2004 (the year-ended 2004 MD&A), which was included in
SCE's 2004 annual report to shareholders and incorporated by reference into SCE's Annual Report on Form 10-K for
the year ended December 31, 2004, filed with the Securities and Exchange Commission.
This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform
Act of 1995. Forward-looking statements reflect SCE's current expectations and projections about future events
based on SCE's knowledge of present facts and circumstances and assumptions about future events and include any
statement that does not directly relate to a historical or current fact. Other information distributed by SCE
that is incorporated in this report, or that refers to or incorporates this report, may also contain
forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates,"
"estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations
of such words and similar expressions, or discussions of strategy or of plans, are intended to identify
forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual
results to differ materially from those anticipated. Some of the risks, uncertainties and other important
factors that could cause results to differ, or that otherwise could impact SCE, include, but are not limited to:
o the ability of SCE to recover its costs in a timely manner from its customers through regulated rates;
o decisions and other actions by the California Public Utilities Commission (CPUC) and other regulatory
authorities and delays in regulatory actions;
o market risks affecting SCE's energy procurement activities;
o access to capital markets and the cost of capital;
o changes in interest rates and rates of inflation;
o governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity
industry, including environmental regulations that could require additional expenditures or otherwise affect
the cost and manner of doing business;
o risks associated with operating nuclear and other power generating facilities, including operating
risks, equipment failure, availability, heat rate and output;
o the ability to obtain sufficient insurance;
o effects of legal proceedings, changes in tax laws, rates or policies, and changes in accounting
standards;
o weather conditions, natural disasters and other unforeseen events; and
o changes in the fair value of investments accounted for using fair value accounting.
Additional information about risks and uncertainties, including more detail about the factors described above, is
contained throughout this MD&A. Readers are urged to read this entire report, including the information
incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect SCE's
business. The information contained in this report is subject to change without notice. Forward-looking
statements speak only as of the date they are made and SCE is not obligated to publicly update or revise
forward-looking statements. Readers should review future reports filed by SCE with the Securities and Exchange
Commission. The following discussion provides updated information about material developments since the issuance
of the year-ended 2004 MD&A and should be read in
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conjunction with the financial statements contained in this quarterly report and SCE's Annual Report on Form 10-K
for the year ended December 31, 2004.
This MD&A includes information about SCE, an investor-owned utility company providing electricity to retail
customers in central, coastal, and southern California. SCE is regulated by the CPUC and the Federal Energy
Regulatory Commission (FERC).
This MD&A is presented in eight major sections. The MD&A begins with a discussion of current developments. The
remaining sections of the MD&A include: liquidity; market risk exposures; regulatory matters; other
developments; results of operations and historical cash flow analysis; new and proposed accounting principles;
and commitments and guarantees.
CURRENT DEVELOPMENTS
2006 General Rate Case Proceeding
In December 2004, SCE filed an application with the CPUC for its 2006 General Rate Case (GRC). During the course
of the GRC proceeding, SCE agreed to certain revisions to its original request, updated the revenue requirement
for the 2005 cost of capital, and incorporated a second refueling O&M expense forecast for San Onofre Nuclear
Generating Station (San Onofre) in 2006, which reduced SCE's test year request by $29 million. In a joint
comparison exhibit filed by all parties on August 2, 2005, SCE requested an increase of $341 million in 2006 base
rate revenue, followed by a requested increase of $106 million in 2007 and $111 million in 2008. In this
exhibit, the ORA revised its previously requested decrease in 2006 revenue to $47 million, a difference of $388
million from SCE's request. The revised ORA request, when combined with proposed reductions from several other
intervenors, would result in a reduction of $273 million in revenue, a difference of $614 million from SCE's
request. A decision in this matter is expected in January 2006. On August 2, 2005 SCE filed a motion requesting
the establishment of a GRC Memo Account which would make the GRC decision retroactive to January 9, 2006, or the
first CPUC meeting in January 2006, whichever is earlier. See "Regulatory Matters--Transmission and
Distribution--2006 General Rate Case Proceeding" for further discussion.
In SCE's 2006 Energy Resource Recovery Account (ERRA) forecast proceeding, SCE is proposing to consolidate the
rate changes arising from the 2006 GRC proceeding with other changes in rates beginning on January 1, 2006 (see
"Regulatory Matters--Generation and Power Procurement--Generation Procurement Proceedings--Energy Resource Recovery
Account Proceedings--2006 ERRA Forecast").
Passage of Comprehensive Energy Legislation by Congress
A comprehensive energy bill was passed by the House and Senate in the last week of July 2005 and is expected to
be signed by the President on August 8, 2005. This comprehensive legislation includes provisions for the repeal
of the Public Utility Holding Company Act, for amendments of the Public Utility Regulatory Policies Act of 1978,
for the introduction of new regulations regarding "Transmission Operation Improvements," for Transmission Rate
Reform, for incentives for various generation technologies and for the extension through December 31, 2007 of
production tax credits for wind and other specified types of generation. A number of these provisions will
require implementing regulations by the FERC. SCE is currently assessing the potential impact of this
legislation and the likely regulations.
LIQUIDITY
SCE's liquidity is primarily affected by under- or over-collections of energy procurement-related costs,
collateral requirements associated with power-purchase contracts, and access to capital markets or external
financings. At June 30, 2005, SCE's credit and long-term senior secured issuer ratings from Standard & Poor's
and Moody's Investors Service were BBB+ and A3, respectively. At June 30, 2005,
Page 25
SCE's short-term (commercial paper) credit ratings from Standard & Poor's and Moody's Investors Service were A2
and P2, respectively. As of June 30, 2005, SCE had $148 million in commercial paper outstanding.
As of June 30, 2005, SCE had cash and equivalents of $176 million ($88 million of which was held by SCE's
consolidated Variable Interest Entities (VIEs)). As of June 30, 2005, long-term debt, including current
maturities of long-term debt, was $5.4 billion. As of June 30, 2005, SCE posted approximately $44 million
(comprised of $37 million in cash and $7 million in letters of credit) as collateral to secure its obligations
under power-purchase contracts and to enter into transactions for imbalance energy through the California
Independent System Operator (ISO). SCE's collateral requirements can vary depending upon the level of unsecured
credit extended by counterparties, the ISO's credit requirements, changes in market prices relative to
contractual commitments, and other factors. In February 2005, SCE replaced its $700 million credit facility with
a $1.25 billion senior secured 5-year revolving credit facility. The security pledged (first and refunding
mortgage bonds) for the new facility can be removed at SCE's discretion. If SCE chooses to remove the security,
the credit facility's rating and pricing will change to an unsecured basis per the term of the credit facility
agreement. As of June 30, 2005, SCE's credit facility supported $148 million of commercial paper outstanding
and $7 million in letters of credit, leaving $1.1 billion available under the credit facility.
SCE's estimated cash outflows, during the twelve-month period following June 30, 2005, consist of:
o Debt maturities of approximately $597 million, including approximately $246 million of rate reduction
notes that are due at various times in 2005 and 2006, but which have a separate cost recovery mechanism
approved by state legislation and CPUC decisions;
o Projected capital expenditures primarily to replace and expand distribution and transmission
infrastructure and construct and replace generation assets, as discussed below;
o Dividend payments to SCE's parent company. SCE made a $71 million dividend payment to Edison
International on both April 28, 2005 and July 28, 2005;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections
(as incurred), through cash and equivalents on hand, operating cash flows and short-term borrowings, when
necessary. Projected capital expenditures are expected to be financed through operating cash flows and the
issuance of long-term debt and preferred equity.
SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its
distribution and transmission infrastructure, and to construct and replace generation assets. In April 2005, the
Finance Committee of SCE's Board of Directors approved a $10.1 billion capital budget and forecast for the period
2005-2009, an increase of approximately $700 million over the $9.4 billion amount adopted in October 2004. The
increase is mainly due to acceleration of spending in 2005-2009 on several transmission projects, as well as
additional expenditures associated with the replacement of the steam generator and pressurizer at San Onofre.
All amounts exceeding the October 2004 forecast are included in either the 2006 GRC or separate regulatory
filings for major generation and transmission projects. Pursuant to the approved capital budget and forecast,
SCE expects its capital expenditures to be $1.8 billion, $1.9 billion, and $2.1 billion in 2005, 2006 and 2007,
respectively.
On July 18, 2005, SCE gave notice of its election to prepay $29 million of its 6.90% Pollution Control Revenue
Bonds (1991 Series), $30 million of its 6% Pollution Control Revenue Bonds (1992A Series)
Page 26
and $190 million of its 6.4% Pollution Control Revenue Bonds (1992B Series) on September 8, 2005. The notice is
revocable and SCE may, at its option, choose not to prepay such bonds.
SCE has debt covenants that require certain interest coverage, interest and preferred dividend coverage, and debt
to total capitalization ratios to be met. At June 30, 2005, SCE was in compliance with these debt covenants.
SCE's liquidity may be affected by, among other things, matters described in "Regulatory Matters."
MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, commodity prices and volume, and counterparty
credit. Fluctuations in interest rates can affect earnings and cash flows. However, fluctuations in commodity
prices and volumes, and counterparty credit losses temporarily affect cash flows, but generally should not affect
earnings due to recovery through regulatory mechanisms. SCE uses derivative financial instruments to manage its
market risks, but does not use these instruments for speculative purposes. See "Market Risk Exposures" in the
year-ended 2004 MD&A for a complete discussion of SCE's market risk exposures.
REGULATORY MATTERS
This section of the MD&A describes SCE's regulatory matters in three main subsections:
o generation and power procurement;
o transmission and distribution; and
o other regulatory matters.
Generation and Power Procurement
Energy Resource Recovery Account Proceedings
In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to track and recover
SCE's: (1) fuel costs related to its generating stations; (2) purchased-power costs related to cogeneration and
renewable contracts; (3) purchased-power costs related to existing interutility and bilateral contracts that were
entered into before January 17, 2001; and (4) new procurement-related costs incurred on or after January 1, 2003
(the date on which the CPUC transferred back to SCE the responsibility for procuring energy resources for its
customers). SCE recovers these costs on a cost-recovery basis, with no markup for return or profit. SCE files
annual forecasts of the above-described costs that it expects to incur during the following year. As these costs
are subsequently incurred, they 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
Page 27
revenue at the end of January 2005. A combination of higher procurement costs, a delay in approval of the 2005
ERRA rate change and other factors contributed to the large increase in the undercollection amount in February
2005. SCE's trigger application stated that if the CPUC retained recently authorized ERRA rate levels rather
than increasing rates, the undercollection would be recovered by mid-September 2005. On May 26, 2005, the CPUC
issued a decision granting SCE's application to maintain its previously authorized ERRA rate levels.
ERRA Reasonableness Review for the Period January 1, 2004 through December 31, 2004
On April 1, 2005, SCE submitted an ERRA review application requesting that the CPUC find its procurement-related
costs for calendar year 2004 to be reasonable, and that its contract administration and economic dispatch
operations during 2004 complied with its CPUC-adopted procurement plan. In addition, SCE requested recovery of
approximately $13 million associated with Nuclear Unit Incentive Procedure rewards for efficient operation of the
Palo Verde Nuclear Generating Station (Palo Verde) and approximately $7 million in administrative and general
costs incurred to carry out the CPUC's directive to begin procuring energy supplies on January 1, 2003 following
the California energy crisis. The ORA is scheduled to issue its report on SCE's 2004 costs and operations in
mid-August 2005. Evidentiary hearings are scheduled to begin in September 2005 and a decision is expected in
late December 2005 or early January 2006.
2005 ERRA Forecast
On March 17, 2005, the CPUC issued a final decision adopting SCE's requested ERRA revenue requirement of $3.3
billion for the 2005 calendar year, an increase of $1 billion over the 2004 revenue requirement. The increase
was primarily attributable to increasing procurement costs, in part because SCE must procure additional energy
and capacity in 2005 to replace energy and capacity that had been provided by a major California Department of
Water Resources (CDWR) contract that terminated in December 2004. In addition, the increase was attributable to
additional capacity and associated energy costs resulting from increasing SCE's reserve margin to fulfill the
CPUC's requirement of a 15% to 17% planning reserve and a substantially higher forecasted ERRA undercollected
balance as of December 31, 2004 than the balance included in 2004 rate levels.
2006 ERRA Forecast
SCE submitted an ERRA forecast application on August 1, 2005, in which it forecasts a procurement-related revenue
requirement for the 2006 calendar year of $3.8 billion. The 2006 ERRA proceeding revenue requirement is an
increase of $509 million over SCE's adopted 2005 ERRA proceeding revenue requirement. The increase is mainly
attributable to load growth and resource adequacy requirements (see the discussion under "--Generation Procurement
Proceedings--Resource Adequacy Requirements" included in the year-ended 2004 MD&A), and the unavailability of
SCE's Mohave coal-fired generating station (Mohave) after December 31, 2005, and its replacement with higher-cost
natural gas generation (see "--Mohave Generating Station and Related Proceedings").
In addition, the 2006 ERRA forecast application requests the CPUC to consolidate all CPUC-authorized revenue
requirements, including the revenue requirements from the 2006 ERRA forecast application, the 2006 GRC (see
"--Transmission and Distribution--2006 General Rate Case Proceeding") and CDWR-related proceedings (see
"--CDWR-Related Matters--CDWR Power Purchases and Revenue Requirement Proceeding"), for recovery through rates
beginning January 1, 2006. SCE's current system average rate for bundled service customers is
12.6(cent)-per-kilowatt-hour (kWh). SCE expects the 2006 system average rate for bundled service customers to range
between 13.9(cent)-per-kWh to 14.4(cent)-per-kWh.
Page 28
CDWR-Related Matters
CDWR Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2004
MD&A, in December 2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement for 2004
through 2013 will be allocated among the investor-owned utilities. On June 30, 2005, the CPUC granted, in part,
San Diego Gas & Electric's (SDG&E) petition for modification of the December 2004 decision. The June 30, 2005
decision adopted a methodology that retains the cost-follows-contract allocation of the avoidable costs, and
allocates the unavoidable costs associated with the contracts: 42.2% to Pacific Gas and Electric's (PG&E)
customers, 47.5% to SCE's customers and 10.3% to SDG&E's customers. This newly adopted allocation methodology
decreases the total costs allocated to SDG&E's customers and increases the total costs allocated to SCE's and
PG&E's customers, relative to the December 2004 decision.
Amounts billed to SCE's customers for electric power purchased and sold by the CDWR are remitted directly to the
CDWR and are not recognized as revenue by SCE and therefore have no impact on SCE's earnings. In SCE's 2006 ERRA
forecast proceeding, SCE is proposing to consolidate the impact of the June 30, 2005 decision, as well as other
CDWR revenue requirement changes, with other changes in rates beginning on January 1, 2006 (see "--Energy Resource
Recovery Account Proceedings--2006 ERRA Forecast").
Generation Procurement Proceedings
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan was filed on March 7, 2005. On July 21, 2005, the CPUC issued a decision
approving SCE's 2005 renewable procurement plan and deferred a ruling on SCE's renewable procurement plan for
2006 through 2014. This decision also approved the methodology advocated by SCE for determining the amount by
which reported renewable procurement should be adjusted to reflect line losses.
In addition, the decision states that SCE cannot count procurement from certain geothermal facilities towards its
1% annual renewable procurement requirement, unless such procurement is from production certified as
"incremental" by the California Energy Commission. A 2003 CPUC decision had held that SCE could count procurement
from these geothermal facilities toward its 1% annual renewable procurement requirement.
The geothermal facilities have applied to the California Energy Commission for certification of a portion of the
facilities' production as "incremental." A decision from the California Energy Commission is expected in late
August or early September 2005. It is not clear whether any of the facilities' production will be certified as
"incremental" or how much, if any, of the "incremental" production from the facilities will be allocated to SCE's
procurement under its contract with the facilities if the California Energy Commission certification is granted.
Depending upon the amount, if any, of California Energy Commission certified "incremental" production allocated
to SCE's procurement under its contract and the manner in which the CPUC implements its flexible rules for
compliance with renewable procurement obligations, SCE may not be in compliance with its statutory renewable
procurement obligations for 2003 through 2006 and could be subject to penalties for those years. The maximum
penalty is $25 million per year. To comply with renewable procurement mandates and avoid penalties for years
beyond 2006, SCE will either need to sign new contracts and/or extend existing renewable qualifying facility (QF)
contracts.
Page 29
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and
conducted negotiations with bidders regarding potential procurement contracts. On June 30, 2005, the CPUC issued
a resolution approving six renewable contracts resulting from the solicitation. The CPUC's July 21, 2005
decision referenced above also approved SCE's proposed new request for offers for additional renewable contracts,
which SCE contemplates initiating in the third quarter of 2005.
Request for Offers for New Generation Resources
According to California state agencies, beginning in 2006, there is a need for new generation capacity in
southern California. SCE has issued a Request for Offers (RFO) for new generation resources. SCE has solicited
offers for power-purchase agreements lasting up to 10 years from new generation facilities with delivery under
the agreement beginning between June 1, 2006 and August 1, 2008. SCE has filed an application with the CPUC
seeking approval of the RFO and the power-purchase agreements executed under the RFO. SCE is seeking recovery of
the costs of the contracts, through the FERC-jurisdictional rates, from all affected customers. In addition, SCE
seeks CPUC assurance of full cost recovery in CPUC-approved rates, if the FERC denies any recovery. Any
power-purchase agreement that SCE executes as a result of the RFO will be contingent on CPUC approval of the
contract and assurance of full cost recovery.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2004 MD&A,
the CPUC issued a final decision in December 2004 on SCE's application regarding the post-2005 operation of
Mohave, which is partly owned by SCE.
In parallel with and since the conclusion of the CPUC proceeding, negotiations have continued among the relevant
parties in an effort to resolve Mohave's post-2005 coal and water supply issues, but no resolution has been
reached to date. Because resolution has not been reached and because of the lead times required for installation
of certain pollution-control equipment and other upgrades necessary for post-2005 operation, it is probable that
Mohave will shut down for at least several years, and perhaps permanently, at the end of 2005. The outcome of
the coal and water negotiations are not expected to impact Mohave's operation through 2005, but the presence or
absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. SCE's 2006
ERRA forecast application assumes Mohave is an unavailable resource for power for 2006 (see "--Energy Resource
Recovery Account Proceedings--2006 ERRA Forecast" for further discussion). Because SCE expects to recover Mohave
shut-down costs in future rates, the outcome of this matter is not expected to have a material impact on earnings.
San Onofre Nuclear Generating Station
As discussed in the "San Onofre Nuclear Generating Station" disclosure in the year-ended 2004 MD&A, there are
several issues related to the operation and maintenance of San Onofre Units 2 and 3. The following are new
developments with respect to San Onofre.
San Onofre Steam Generators
A decision on the reasonableness of the proposed replacement of the San Onofre Units 2 and 3 steam generators and
the establishment of appropriate ratemaking for recovery in rates of the reasonable cost of the replacement
project is expected in the fourth quarter of 2005. By the time of the expected decision, SCE anticipates that it
will have incurred approximately $80 million in steam generator fabrication and associated project costs. SCE
will seek recovery of these costs in the event that the CPUC does not authorize SCE to go forward with steam
generator replacement. If the CPUC authorizes SCE to go forward with steam generator replacement, SCE will
recover costs that are reasonably incurred as part of the steam generator replacement capital costs.
Page 30
2005 Outage Schedule, O&M and Capital Budget Disputes
On April 20, 2005, the San Onofre Units 2 and 3 Board of Review (BOR) held a special meeting to consider the
5-year outage schedule, revisions to the 2005 operation and maintenance (O&M) budget, and the 2005 capital
budget. These matters require unanimous approval of the BOR. The representatives of SDG&E did not agree with the
information presented for approval. Consequently, a vote was not taken. SCE and SDG&E agreed to consolidate the
disputes over the 2005 O&M and 2005 capital budgets and to treat the dispute over the 5-year outage schedule as a
separate dispute. The BOR subsequently approved a modified 5-year outage schedule. The parties are proceeding
with the dispute resolution procedures in the Second Amended San Onofre Operating Agreement for the consolidated
2005 O&M and capital budget disputes, which provide for binding arbitration if the disputes cannot be resolved
through informal methods.
Transmission and Distribution
2006 General Rate Case Proceeding
On December 21, 2004, SCE filed its application for a 2006 GRC, requesting an increase of $370 million in SCE's
2006 base rate revenue, primarily for capital-related expenditures to accommodate infrastructure replacement,
customer and load growth. This increase is also necessary to fund substantially higher O&M expenses,
particularly in SCE's transmission and distribution business unit. SCE also requested that the CPUC authorize
continuation of SCE's existing post-test year rate-making mechanism, which would result in base rate revenue
increases of $159 million and $122 million in 2007 and 2008, respectively. If the CPUC approves these requested
increases and allocates them to ratepayer groups on a system average percentage change basis, the total increase
over current base rates is estimated to be 10%.
On April 15, 2005, the ORA submitted testimony recommending that SCE's 2006 base rate revenue be decreased by $93
million, a difference of $463 million from SCE's request. In addition, the ORA recommended that an additional
year, 2009, be added to SCE's GRC cycle and that the CPUC use a Consumer Price Indexed (CPI) method, applied to
the test year revenue requirement, to determine base rate revenue adjustments in the attrition years (2007 and
2008). SCE had used a budget-based approach to projected capital additions in the attrition years in its
filing. This approach was previously authorized in the 2003 GRC decision. The ORA's CPI methodology would raise
SCE's 2007 base rate revenue by $2 million (as opposed to SCE's requested increase of $159 million) and would
decrease SCE's 2008 base rate revenue by $10 million (as opposed to SCE's requested increase of $122 million).
Portions of the ORA's proposed adjustments reflect an updated rate of return, authorized by the CPUC subsequent
to the filing of SCE's GRC application. On May 6, 2005, several intervenors filed testimony proposing reductions
to SCE's 2006 GRC request, which, when combined with the ORA's recommendation, would result in a reduction of
$326 million in revenue, a difference of $696 million from SCE's request.
During the course of the GRC proceeding, SCE agreed to certain revisions to its request, updated the revenue
requirement for the 2005 cost of capital, and incorporated a second refueling O&M expense forecast for San Onofre
in 2006, which reduced SCE's test year request by $29 million. In a joint comparison exhibit filed by all
parties on August 2, 2005, SCE requested an increase of $341 million in 2006 base rate revenue, followed by a
requested increase of $106 million in 2007 and $111 million in 2008. In this exhibit, the ORA revised its
requested decrease in 2006 revenue to $47 million, a difference of $388 million from SCE's request. The revised
ORA request, when combined with proposed reductions from several other intervenors, would result in a reduction
of $273 million in revenue, a difference of $614 million from SCE's request. A decision in this matter is
expected in January 2006.
On August 2, 2005 SCE filed a motion requesting the establishment of a GRC Memo Account which would make the GRC
decision retroactive to January 9, 2006, or the first CPUC meeting in January 2006, whichever is earlier.
Page 31
In SCE's 2006 ERRA forecast proceeding, SCE is proposing to consolidate the rate changes arising from the 2006
GRC proceeding with other changes in rates beginning on January 1, 2006 (see "--Generation and Power
Procurement--Generation Procurement Proceedings--Energy Resource Recovery Account Proceedings--2006 ERRA Forecast").
2006 Cost of Capital
On May 9, 2005, SCE filed an application requesting that the CPUC authorize a return on SCE's common equity and
an overall rate of return for SCE's CPUC-jurisdictional assets for 2006. In its application, SCE requests that
the CPUC maintain its 2005 authorized rate-making capital structure of 43% long-term debt, 9% preferred equity,
and 48% common equity for 2006. SCE's application also requests that the CPUC authorize SCE's 2006 cost of
long-term debt of 6.53%, cost of preferred equity of 6.43% and a return on common equity of 11.80%. A proposed
decision is scheduled for November 15, 2005, and a final CPUC decision is anticipated on or before December 15,
2005. CPUC adoption of SCE's application request would result in a projected $10 million increase in its annual
revenue requirements.
ISO Disputed Charges
On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim,
Azusa, Banning and Riverside, California over the proper allocation and characterization of certain charges. The
order reversed an arbitrator's award that had affirmed the ISO's characterization in May 2000 of the charges as
Intra-Zonal Congestion costs and allocation of those charges to Scheduling Coordinators (SCs) in the affected
zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from SCs in
the affected zone to the responsible Participating Transmission Owner, SCE, and to do so within 60 days of the
April 20, 2004 order. Under the April 20, 2004 order, SCE will be charged a certain amount as the Participating
Transmission Owner but also will be credited through the California Power Exchange, SCE's SC at the time. SCE
obtained a stay of the April 20, 2004 order pending resolution of its request for rehearing. On March 30, 2005,
the FERC issued an Order Denying Rehearing. SCE obtained an extension of the stay pending resolution of the
appeal SCE has filed with the United States Court of Appeals for the D.C. Circuit (D.C. Circuit Court). The
potential net impact on SCE is estimated to be approximately $20 million to $25 million, including interest. SCE
filed a request for clarification with the FERC asking the FERC to clarify that SCE can reflect and recover the
disputed costs in SCE's reliability services rates. On June 8, 2005, the FERC denied the clarification, noting
that during the appeal, the FERC's order is stayed, therefore SCE is not required to pay at this time. SCE may
seek recovery in its reliability service rates of the costs should SCE be required to pay these costs.
Transmission Proceeding
In August and November 2002, the FERC issued opinions affirming a September 1999 administrative law judge
decision to disallow, among other things, recovery by SCE and the other California public utilities of costs
reflected in network transmission rates associated with ancillary services and losses incurred by the utilities
in administering existing wholesale transmission contracts after implementation of the restructured California
electric industry. SCE has incurred approximately $80 million of these unrecovered costs since 1998. In
addition, SCE has accrued interest on these unrecovered costs. The three California utilities appealed the
decisions to the D.C. Circuit Court. On July 12, 2005, the D.C. Circuit Court vacated the FERC's August and
November 2002 orders, and remanded the case to FERC for further proceedings. SCE believes that the D.C. Circuit
Court's decision increases the likelihood that it will recover these costs.
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Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in the year-ended 2004 MD&A, SCE
is participating in several related proceedings seeking recovery of refunds from sellers of electricity and
natural gas who allegedly manipulated the electric and natural gas markets.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including
SCE, PG&E, the State of California and various consumer class action representatives) settling various claims
stated in proceedings at the FERC and in San Diego County Superior Court that El Paso had manipulated interstate
capacity and engaged in other anticompetitive behavior in the natural gas markets in order to unlawfully raise
gas prices at the California border in 2000-2001. The United States District Court has issued an order approving
the stipulated judgment and the settlement agreement has become effective. Pursuant to a CPUC decision, SCE was
required to refund to customers amounts received under the terms of the El Paso settlement (net of legal and
consulting costs) through its ERRA mechanism. In June 2004, SCE received its first settlement payment of
$76 million. Approximately $66 million of this amount was credited to purchased-power expense, and was refunded
to SCE's ratepayers through the ERRA over the following twelve months, and the remaining $10 million was used to
offset SCE's incurred legal costs. El Paso has elected to prepay the additional settlement payments due over a
20-year period and, as a result, SCE received $66 million in May 2005. Amounts El Paso refunds to the CDWR will
result in reductions in the CDWR's revenue requirement allocated to SCE in proportion to SCE's share of the
CDWR's power charge revenue requirement.
On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant
Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in Chapter 11
bankruptcy proceedings pending in Texas. Among other things, the settlement terms provide for cash and
equivalent refunds totaling $320 million, of which SCE's allocated share is approximately $68 million. The
settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of one of the
Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual value of
the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies. The Mirant
settlement was approved by the FERC on April 13, 2005 and by the bankruptcy court on April 15, 2005. In April
and May 2005, SCE received its allocated $68 million in cash settlement proceeds. SCE continues to hold its $33
million share of the allowed, unsecured bankruptcy claim. The Mirant settlement will be refunded to ratepayers
as described below.
On July 15, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Enron
Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11
bankruptcy proceedings pending in New York. Among other things, the settlement terms provide for cash and
equivalent payments from Enron totaling approximately $47 million and an allowed, unsecured claim in the
bankruptcy against one of the Enron entities in the amount of $875 million. SCE's allocable share of both the
cash and allowed claim portions of the settlement consideration has not yet been finally determined, and the
value of an allocable share of the allowed claim will be determined as part of the resolution of the Enron
parties' bankruptcies. The settlement remains subject to the approvals of the FERC, the CPUC and the Enron
bankruptcy court. The Enron settlement proceeds will be refunded to ratepayers as described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement Memorandum
Account (ESMA) for the purpose of recording the foregoing settlement proceeds (excluding the El Paso settlement)
from energy providers and allocating them in accordance with the terms of the October 2001 settlement agreement
entered into by SCE and the CPUC which settled SCE's lawsuit against the CPUC. This lawsuit sought full recovery
of SCE's electricity procurement costs incurred during the energy crisis. The resolution provides a mechanism
whereby portions of the settlement proceeds recorded in the ESMA will be allocated to recovery of SCE's
litigation costs and expenses in the FERC refund proceedings described above and a 10% shareholder incentive
pursuant to the CPUC litigation settlement agreement. Remaining amounts for each settlement are to be refunded
to
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ratepayers through the ERRA mechanism. In the second quarter of 2005, SCE recorded a $7 million increase to
other nonoperating income as a shareholder incentive related to the Mirant refund received during the second
quarter of 2005.
Other Regulatory Matters
Catastrophic Event Memorandum Account
Fire-Related CEMA
In October and November of 2003, wildfires damaged SCE's electrical infrastructure, primarily in the
San Bernardino Mountains of southern California where an estimated 2,085 power poles, 2,059 services,
371 transformers, 557,033 of overhead conductors and 25,822 feet of underground cable were replaced or repaired.
SCE notified the CPUC that it initiated a CEMA on October 21, 2003 to track the incremental costs to restore and
repair damage to its facilities. SCE filed an application with the CPUC on December 2, 2004 to seek recovery of
its fire-related costs over a one-year period commencing January 1, 2006. On June 23, 2005, SCE and the ORA
filed a settlement agreement with the CPUC which (i) allows the authorized CEMA Firestorm revenue requirement
calculation to be based on approximately $8 million of incremental operations and maintenance expenses and $20 of
incremental capital plant additions and (ii) allows SCE to continue to record in its Firestorm CEMA the revenue
requirement associated with these costs, plus accrued interest, until the effective date of the final decision in
SCE's 2006 GRC. The revenue requirement recorded in SCE's Firestorm CEMA through April 2005 is approximately
$12 million. SCE has forecast the recorded revenue requirement in this account to total approximately $14 million
in December 2005. SCE expects to recover the costs recorded in the Firestorm CEMA account through a mechanism
approved in SCE's 2006 GRC.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary. For a
discussion of item (1) above, see the "Holding Company Proceeding" disclosure in the year-ended 2004 MD&A.
On May 5, 2005, the CPUC issued a final decision that closed the proceeding. However, because the CPUC closed
the proceeding without addressing some of the issues the proceeding raised (such as the appropriateness of the
large utilities' holding company structure and dividend policies), the CPUC may rule on or investigate these
issues in the future.
Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms
Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain shareholder
incentives for its performance achievements in delivering demand-side management and energy efficiency programs.
On June 10, 2005, SCE and the ORA executed a settlement agreement for SCE's outstanding issues concerning SCE
shareholder incentives and performance achievements resulting from the demand-side management, energy efficiency,
and low-income energy efficiency programs from program years 1994-2004. In addition, the settlement addresses
shareholder incentives and performance achievements for program years 1994-1998, anticipated but not yet
claimed. The settlement agreement recommends, among other things, that SCE be entitled to immediately recover 92%
of the total of SCE's current claims and future claims related to SCE's pre-1998 energy efficiency programs.
SCE's total claim for program years 1994-2004 made in 2000 through 2008, including interest, franchise fees and
uncollectibles, is approximately $46 million. The settling parties agreed that it is reasonable for SCE to
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recover approximately $42 million of these claims in the near future as full recovery of all of SCE's outstanding
claims as well as future claims related to SCE's pre-1998 energy efficiency programs. The settlement agreement
requires CPUC approval. On June 13, 2005, SCE and the ORA filed a joint motion requesting CPUC adoption of the
settlement agreement. A decision is expected in the fourth quarter of 2005, which if approved, would result in
the recognition of a $42 million increase in earnings. SCE has collected and deferred most the of the expected
claims in rates, and expects to recover the remaining portion of the claims over a 12-month period beginning on
January 1, 2006 through the 2006 ERRA Forecast application (see "--Generation and Power Procurement--Energy
Resource Recovery Account Proceedings--2006 ERRA Forecast").
OTHER DEVELOPMENTS
Environmental Matters
SCE 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.
Environmental Remediation
SCE 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. SCE 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, SCE records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 22 identified sites is $84 million. The ultimate
costs to clean up SCE'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. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $113 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In
addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE
also has 33 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to
$10 million.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $31 million of its
recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this
mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at
its remaining sites through customer rates. SCE has recorded a regulatory asset of $57 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer rates.
SCE'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 SCE may be held
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responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of
cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
next several years are expected to range from $12 million to $25 million. Recorded costs for the twelve months
ended June 30, 2005 were $12 million.
Based on currently available information, SCE 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, SCE believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of new sites, will not require
material revisions to such estimates.
Federal Income Taxes
Edison International has reached a settlement with the Internal Revenue Service (IRS) on tax issues and pending
affirmative claims relating to its 1991-1993 tax years. This settlement, which was signed by Edison
International in March 2005 and approved by the United States Congress Joint Committee on Taxation on July 27,
2005, will result in a third quarter 2005 net earnings benefit for Edison International of approximately
$56 million, most of which relates to SCE.
Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting
deficiencies, including deficiencies asserted against SCE, 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 benefit
SCE as future tax deductions.
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 the SCE subsidiary contingent liability company transaction described above. Edison
International filed these amended returns under protest retaining its appeal rights.
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
Earnings from Continuing Operations
SCE's earnings from continuing operations were $161 million and $292 million for the three- and six-month periods
ended June 30, 2005, respectively, compared to $242 million and $341 million for the
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same periods in 2004. SCE's 2004 earnings from continuing operations included net positive regulatory items of
$117 million or 36(cent)per common share primarily related to the implementation of SCE's 2003 GRC decision. The
decrease in earnings for the three- and six-month period ended June 30, 2005, compared to the same periods in
2004, is primarily due to the net positive regulatory items recorded in 2004, partially offset by higher revenue
associated with the timing of the 2003 GRC decision. SCE received the 2003 GRC decision in July 2004, which
resulted in a catch-up adjustment in the third quarter of 2004 for the amounts related to the first half of 2004,
as well as an increase in earnings for the second half of 2004. The variances for both periods also reflects
higher revenue authorized by the CPUC for 2005, the favorable resolution of certain tax issues and lower net
interest costs (quarter only), which were mostly offset by higher operating expenses.
Operating Revenue
SCE's retail sales represented approximately 83% of operating revenue for both the three- and six-month periods
ended June 30, 2005, compared to approximately 82% and 85% of operating revenue for the three- and six-month
periods ended June 30, 2004, respectively. Due to warmer weather during the summer months, operating revenue
during the third quarter of each year is generally significantly higher than other quarters.
The following table sets forth the major changes in operating revenue:
Three-Month Period Six-Month Period
Ended June 30, Ended June 30,
In millions 2005 vs. 2004 2005 vs. 2004
-------------------------------------------------------------------------------------------------------
Operating revenue
Rate changes (including unbilled) $ (93) $ (102)
Sales volume changes (including unbilled) 118 170
Sales for resale (14) 44
SCE's variable interest entities 8 109
Other (including intercompany transactions) 8 17
-------------------------------------------------------------------------------------------------------
Total $ 27 $ 238
-------------------------------------------------------------------------------------------------------
Total operating revenue increased by $27 million and $238 million for the three- and six-month periods ended June
30, 2005, respectively (as shown in the table above), as compared to the same periods in 2004. The variance in
operating revenue from rate changes reflects the implementation of the 2003 GRC, effective in August 2004. As a
result, generation rates decreased revenue by approximately $30 million and $150 million for the three- and
six-month periods ended June 30, 2005, respectively, and distribution rates increased revenue by approximately
$100 million and $255 million for the three- and six-month periods ended June 30, 2005, respectively. Included
in the variance in operating revenue from rate changes are higher deferrals of revenue of approximately $210
million and $275 million for the three- and six-month periods ended June 30, 2005, respectively, related to
balancing account overcollections in 2005, as compared to 2004. The increase in operating 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. Operating revenue from sales for resale represents the sale of excess energy. As a
result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times, which
then is resold in the energy markets. SCE's variable interest entities revenue represents the recognition of
revenue resulting from the consolidation of SCE's variable interest entities on March 31, 2004.
Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's
customers (beginning January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access
exit fees (beginning January 1, 2003) are remitted to the CDWR and are not
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recognized as revenue by SCE. These amounts were $409 million and $919 million for the three- and six-month
periods ended June 30, 2005, respectively, compared to $546 million and $1.2 billion for the same periods in
2004.
Operating Expenses
Fuel Expense
Fuel expense for the six-month period ended June 30, 2005 increased $224 million, as compared to the same period
in 2004, mainly due to the consolidation of SCE's variable interest entities in March 31, 2004. Fuel expense
related to SCE's variable interest entities for the six-month period ended June 30, 2005 was $398 million,
compared to $187 million for the comparable period in 2004.
Purchased-Power Expense
Purchased-power expense increased $216 million and $24 million for the three- and six-month periods ended June
30, 2005, respectively, as compared to the same periods in 2004. The quarter increase was mainly due to higher
unrealized losses of approximately $205 million related to economic hedging transactions resulting from increased
hedging activities in 2005, as compared to 2004, higher expenses of approximately $100 million (an approximate
increase of $175 million for the year-to-date period) resulting from an increase in the number of bilateral
contracts in 2005, as compared to 2004, and higher expenses of approximately $30 million related to QFs
purchases. These increases were partially offset by approximately $130 million of energy settlement refunds
received in 2005 (see "Regulatory Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas
Markets"). In addition to the items discussed above, the year-to-date increase also resulted from an increase in
exchanged energy of approximately $50 million due to higher volumes and a true-up of exchanged energy. The
year-to-date variance was partially offset by higher unrealized gains of approximately $150 million in the first
quarter of 2005, as well as a decrease of $186 million reduction in purchased-power resulting from the
consolidation of SCE's variable interest entities on March 31, 2004.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated
prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002,
energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)-per-kWh. Average spot natural
gas prices were slightly higher during 2005 as compared to 2004. The higher expenses related to power purchased
from QFs were mainly due to higher average spot natural gas prices, partially offset by lower kWh purchases.
Provisions for Regulatory Adjustment Clauses - Net
Provisions for regulatory adjustment clauses - net increased $8 million and $75 million for the three- and
six-month periods ended June 30, 2005, respectively, as compared to the same periods in 2004. The quarter and
year-to-date increases reflect a net effect of approximately $180 million of regulatory adjustments related to
the implementation of SCE's 2003 GRC decision recorded in the second quarter of 2004 and lower costs incurred and
deferred (approximately $50 million and $60 million for the three- and six-month periods ended June 30, 2005,
respectively, as compared to the same periods in 2004) associated with the bark beetle infestation. The 2003 GRC
regulatory adjustments primarily related to recognition of revenue from the rate recovery of pension
contributions during the time period that the pension plan was fully funded, the resolution over the allocation
of costs between transmission and distribution for 1998 through 2000, partially offset by the deferral of revenue
previously collected during the incremental cost incentive pricing mechanism for dry cask storage. These items
which resulted in increases in the provision for regulatory adjustment clauses were partially offset by net
unrealized losses of $205 million and $55 million for the three- and six-month period ended June 30, 2005,
respectively, related to economic hedging transactions (mentioned above in purchased-power expense) that, if
realized, would be refunded to ratepayers and net undercollections of purchased-power, fuel, and O&M costs of
approximately $70 million
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and $135 million for the three- and six-months ended June 30, 2005, respectively, which were deferred in
balancing accounts for future recovery.
Other Operation and Maintenance Expense
SCE's other operation and maintenance expense decreased $10 million for the three-month period ended June 30,
2005, and increased $10 million for the six-month period ended June 30, 2005, as compared to the same periods in
2004. The decrease was due to lower costs of approximately $50 million incurred in 2005 compared to 2004 related
to the removal of trees and vegetation associated with the bark beetle infestation, almost entirely offset by
higher benefit-related costs of approximately $10 million in 2005 compared to 2004, higher worker's compensation
accruals of approximately $10 million in 2005 compared to 2004, and an increase of approximately $10 million in
demand side management and energy efficiency costs in 2005 as compared to 2004 (which are recovered through
regulatory mechanisms approved by the CPUC). In addition to the above mentioned variance explanations, the
year-to-date variance was also due to the recognition of approximately $30 million in O&M expenses as a result of
the consolidation of SCE's variable interest entities, an increase in reliability costs of approximately $45
million due to an increase in must run units to improve the reliability of the California ISO systems operations
(which are recovered through regulatory mechanisms approved by the FERC), and a decrease of approximately $55
million in generation-related expenses primarily related to lower outage and refueling costs in 2005, as compared
to 2004. In 2004, there was a scheduled major overhaul at SCE's Four Corners coal facility, as well as a
refueling outage at SCE's San Onofre Unit 2.
Other Income and Deductions
Interest and Dividend Income
SCE's interest and dividend income increased $11 million for the six-month period ended June 30, 2005, as
compared to the same period in 2004, mainly due to higher interest income on balancing account undercollections
in 2005 compared to 2004.
Other Nonoperating Income
SCE's other nonoperating income for the three-month period ended June 30, 2005 includes a $7 million shareholder
incentive related to the Mirant settlement received in the second quarter of 2005 (see "Regulatory
Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas Markets"). The year-to-date 2005
amount also includes a $10 million reward for the efficient operation of Palo Verde during 2003, which was
approved by the CPUC in 2005. SCE's other nonoperating income for the six-month period ended June 30, 2004
includes $19 million in rewards for the efficient operation of Palo Verde during 2001 and 2002, which were
approved by the CPUC in 2004.
Income Taxes
SCE's income tax expense decreased $97 million and $99 million for the three- and six-month periods ended June
30, 2005, respectively, as compared to the same periods in 2004, primarily due to a decrease in pre-tax income as
well as changes in property-related flow-through items, reductions in accrued tax liabilities made in 2005 to
reflect progress in settlement negotiations relating to prior year tax liabilities, and adjustments to tax
balances made in 2005.
SCE's composite federal and state statutory rate was approximately 40% for the three- and six-month periods ended
June 30, 2005. The lower effective tax rate of 26% and 29% realized in the three- and six-month periods ended
June 30, 2005, respectively, was primarily due to property-related flow-through items, a reduction in accrued tax
liabilities, as well as adjustments to tax balances.
Page 39
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.
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 was $939 million for the six months ended June 30, 2005, and $946
million for the comparable period in 2004. The change in cash provided by operating activities was mainly due to
the timing of cash receipts and disbursements related to working capital items.
Cash Flows from Financing Activities
Net cash used by financing activities was $71 million for the six months ended June 30, 2005, compared to net
cash provided by financing activities of $324 million for the six months ended June 30, 2004. Cash used by
financing activities from continuing operations in 2005 mainly consisted of long-term and short-term debt
payments.
Financing activities in the six-month period ended June 30, 2005, included the issuance of $650 million of first
and refunding mortgage bonds. The issuance included $400 million of 5% bonds due in 2016 and $250 million of
5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of its 8% first and refunding
mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding
mortgage bonds due February 2007 (Series 2003B). SCE's second quarter financing activity included the issuance
of $350 million of its 5.35% first and refunding mortgage bond due in 2035 (Series 2005E). A portion of the
proceeds was used to redeem $316 million of its 8% first and refunding mortgage bonds due in 2007 (Series
2003B). In addition, in April 2005, SCE issued 4,000,000 shares of Series A preference stock (non-cumulative,
$100 liquidation value) and received net proceeds of approximately $394 million. Approximately $81 million of
the proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred stock, 7.23% Series,
and approximately $64 million of the proceeds was used to redeem all the outstanding shares of its $100
cumulative preferred stock, 6.05% Series. SCE's financing activity in 2005 also included a dividend payment of
$74 million to Edison International.
Financing activities in the six-month period ended June 30, 2004 included the issuance of $300 million of 5%
bonds due in 2014, $525 million of 6% bonds due in 2034 and $150 million of floating rate bonds due in 2006. The
proceeds from these issuances were used to redeem $300 million of its 7.25% first and refunding mortgage bonds
due March 2026, $225 million of its 7.125% first and refunding mortgage bonds due July 2025, $200 million of its
6.9% first and refunding mortgage bonds due October 2018, and $100 million of its junior subordinated deferrable
interest debentures due June 2044. In the first quarter of 2004, SCE paid the $200 million outstanding balance
of its credit facility, as well as remarketed approximately $550 million of pollution-control bonds with varying
maturity dates ranging from 2008 to 2040, of which approximately $196 million of these pollution-control bonds
were reoffered. In March 2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds due in 2015
and $350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the proceeds from the
March 2004 first and refunding mortgage bond issuances were used to fund the acquisition and construction of the
Mountainview project. Financing activities in 2004 also included dividend payments of $448 million to Edison
International.
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Cash Flows from Investing Activities
Net cash used by investing activities was $814 million for the six months ended June 30, 2005, compared to $1
billion for the comparable period in 2004. Cash flows from investing activities are affected by additions to
property and plant and funding of nuclear decommissioning trusts.
Investing activities for the six-month period ended June 30, 2005, reflect $774 million in capital expenditures,
primarily for transmission and distribution assets, including approximately $21 million for nuclear fuel
acquisitions.
Investing activities for the six-month period ended June 30, 2004 reflect, $718 million in capital expenditures
at SCE, primarily for transmission and distribution assets, including approximately $31 million for nuclear fuel
acquisitions. In addition, investing activities include $285 million of acquisition costs related to the
Mountainview project.
NEW AND PROPOSED 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 (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. SCE 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. SCE 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. SCE will implement the new standard effective January 1, 2006 by
applying the modified prospective transition method. The difference in expense between the two accounting
methods is an increase of $1 million in expense for both the three- and six-month periods ended June 30, 2005.
The American Jobs Creation Act of 2004 included a tax deduction on qualified production activities income
(including income from the sale of electricity). In December 2004, the FASB issued guidance that this deduction
should be accounted for as a special deduction, rather than a tax rate reduction. Accordingly, the special
deduction is recorded in the year it is earned. The tax deduction is not expected to materially affect SCE's
2005 financial statements. SCE is evaluating the potential effect for future years.
On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax positions. An enterprise
would recognize, in its financial statements, the benefit of a tax position only if that position is probable of
being sustained on audit based solely on the technical merits of the position. The comment period for the
exposure draft ends on September 12, 2005; the earliest the guidance would be implemented would be December 31,
2005. SCE is evaluating the potential impact of the proposal on its financial statements.
COMMITMENTS AND GUARANTEES
The following is an update to SCE's commitments and guarantees. See the "Commitments and Guarantees" section of
the year-ended 2004 MD&A for a detailed discussion of commitments and guarantees.
Page 41
Fuel Supply Contracts
During the second quarter of 2005, SCE amended one of its coal fuel contracts which reduced the term of the
contract. As a result of this modification, the fuel supply contract payments for the thereafter period
decreased by $152 million.
Power-Purchase Contracts
During the first quarter of 2005, SCE entered into additional power call option contracts. SCE's revised
purchased-power capacity payment commitments under these contracts are currently estimated to be $32 million for
2005, $95 million for 2006, $101 million for 2007 and $84 million for 2008.
Leases
During the first quarter of 2005, SCE entered into new power contracts in which SCE takes virtually all of the
power. In accordance with an accounting standard, these power contracts are classified as operating leases.
SCE's commitments under these operating leases are currently estimated to be $39 million for 2005, $55 million for
2006, $50 million for 2007 and $43 million for 2008.
Page 42
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 heading "Market Risk Exposures," is incorporated herein
by this reference.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
Southern California Edison Company'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 Southern
California Edison Company'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, Southern California Edison Company's disclosure controls and
procedures are effective.
Internal Control Over Financial Reporting
There were no changes in Southern California Edison Company'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, Southern California Edison
Company's internal control over financial reporting.
Page 43
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
There were no significant developments with respect to material litigation of SCE during the quarterly period
ended June 30, 2005. See Note 4, "Contingencies - Navajo Nation Litigation" of Notes to Consolidated Financial
Statements for minor updates on litigation involving SCE and the Navajo Nation which was previously reported in
Part I, Item 3 of Southern California Edison Company's Annual Report on Form 10-K for the year ended December 31,
2004, and in Part II, Item 1 of Southern California Edison Company's First Quarterly Report on Form 10-Q for the
period ending March 31, 2005.
Page 44
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 Southern California Edison
Company 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 Southern California Edison Company'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 Dollar
Purchased Value) of Shares (or
as Part of Units) that May Yet
(a) Total (b) Average Publicly Be Purchased Under
Number of Shares Price Paid per Announced the Plans or Programs
(or Units) Share (or Unit)(1) Plans or
Period Purchased(1) Programs
---------------------------- ---------------------- -------------------- ---------------------- -----------------------
April 1, 2005 to 807,000 $100.00 -- --
April 30, 2005
May 1, 2005 to 0 -- -- --
May 31, 2005
June 1, 2005 to 0 -- -- --
June 30, 2005
---------------------------- ---------------------- -------------------- ---------------------- -----------------------
Total 807,000 $100.00 -- --
============================ ====================== ==================== ====================== =======================
-------------------
(1) On April 30, 2005, Southern California Edison Company redeemed all shares of its $100 Cumulative Preferred
Stock, 7.23% Series ($100 par value).
Page 45
Item 4. Submission of Matters to a Vote of Security Holders
At SCE's Annual Meeting of Shareholders on May 19, 2005, shareholders elected eleven nominees to the Board of
Directors. The number of broker non-votes for each nominee was zero. The numbers of votes cast for and withheld
from each Director-nominee were as follows:
Numbers of Votes
----------------------------------------------------------------------------------------------------------
Name For Withheld
----------------------------------------------------------------------------------------------------------
John E. Bryson 465,296,296 280,238
France A. Cordova 465,281,452 295,082
Alan J. Fohrer 465,317,212 259,322
Bradford M. Freeman 464,255,634 1,320,900
Bruce Karatz 465,305,908 270,626
Luis G. Nogales 464,251,338 1,325,196
Ronald L. Olson 465,307,366 269,168
James M. Rosser 465,308,680 267,854
Richard T. Schlosberg, III 464,249,976 1,326,558
Robert H. Smith 464,239,482 1,337,052
Thomas C. Sutton 464,256,234 1,320,300
----------------------------------------------------------------------------------------------------------
Page 46
Item 6. Exhibits
Southern California Edison Company
10.1 2005 Performance Goals for Southern California Edison Executive Incentive Compensation Plan,
as adopted May 19, 2005 (File No. 1-02313, attached as Exhibit 99.1 to SCE Form 8-K dated May
25, 2005)*
10.2 Edison International Director Compensation Schedule, as adopted May 19, 2005 (File No.
1-02313, attached as Exhibit 99.2 to SCE Form 8-K dated May 25, 2005)*
10.3 Edison International Director Nonqualified Stock Options 2005 Terms and Conditions (File No.
1-02313, attached as Exhibit 99.3 to SCE Form 8-K dated May 25, 2005)*
10.4 First Amendment, dated as of May 20, 2005, to Credit Agreement, dated as of February 1, 2005,
among Southern California Edison Company and JPMorgan Chase Bank, N.A., as Administrative
Agent, Citicorp North America, Inc., as Syndication Agent, and Credit Suisse First Boston,
Lehman Commercial Paper Inc., and Union Bank of California, N.A., as Documentation Agents
(File No. 1-02313, attached as Exhibit 10.1 to SCE Form 8-K dated June 8, 2005)*
10.5 Form of Indemnity Agreement between Southern California Edison Company and its Directors and
any officer, employee or other agent designated by the Board of Directors
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. Section 1350
------------------
* Incorporated herein by reference pursuant to Rule 12b-32.
Page 47
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.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By:/s/ LINDA G. SULLIVAN
------------------------------
LINDA G. SULLIVAN
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Dated: August 8, 2005
