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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 September 30, 2005
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________________ to______________________________
Commission File Number 1-2313
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 by check mark whether the registrant is a shell company (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 October 31, 2005
-------------------------- -------------------------------
Common Stock, no par value 434,888,104
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Page
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 Nine Months
Ended September 30, 2005 and 2004 1
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2005 and 2004 1
Consolidated Balance Sheets - September 30, 2005
and December 31, 2004 2
Consolidated Statements of Cash Flows -
Nine Months Ended September 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 28
Item 3. Quantitative and Qualitative Disclosures About Market Risk 51
Item 4. Controls and Procedures 51
Part II. Other Information:
Item 1. Legal Proceedings 52
Item 6. Exhibits 53
Signature
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SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Operating revenue $ 3,084 $ 2,655 $ 7,195 $ 6,527
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Fuel 296 254 817 550
Purchased power 502 915 1,633 2,022
Provisions for regulatory adjustment clauses - net 766 (34) 790 (85)
Other operation and maintenance 670 607 1,838 1,767
Depreciation, decommissioning and amortization 234 188 688 628
Property and other taxes 48 43 144 134
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Total operating expenses 2,516 1,973 5,910 5,016
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Operating income 568 682 1,285 1,511
Interest and dividend income 15 5 35 14
Other nonoperating income 33 2 68 42
Interest expense - net of amounts capitalized (91) (98) (289) (302)
Other nonoperating deductions (35) (6) (54) (27)
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Income before tax and minority interest 490 585 1,045 1,238
Income tax 52 174 176 398
Minority interest 151 151 283 236
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Net income 287 260 586 604
Dividends on preferred and preference stock
not subject to mandatory redemption 7 1 14 4
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Net income available for common stock $ 280 $ 259 $ 572 $ 600
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Net income $ 287 $ 260 $ 586 $ 604
Other comprehensive income, net of tax:
Amortization of cash flow hedges -- 1 2 3
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Comprehensive income $ 287 $ 261 $ 588 $ 607
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The accompanying notes are an integral part of these financial statements.
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions 2005 2004
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(Unaudited)
ASSETS
Cash and equivalents $ 484 $ 122
Restricted cash 64 61
Margin and collateral deposits 149 66
Receivables, less allowances of $31 and $31
for uncollectible accounts at respective dates 1,028 618
Accrued unbilled revenue 429 320
Fuel inventory 11 8
Materials and supplies 201 188
Accumulated deferred income taxes - net 347 134
Regulatory assets 546 553
Prepayments and other current assets 485 72
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Total current assets 3,744 2,142
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Nonutility property - less accumulated provision
for depreciation of $558 and $554 at respective dates 1,034 960
Nuclear decommissioning trusts 2,861 2,757
Other investments 106 104
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Total investments and other assets 4,001 3,821
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Utility plant, at original cost:
Transmission and distribution 16,329 15,685
Generation 1,373 1,356
Accumulated provision for depreciation (4,667) (4,506)
Construction work in progress 931 789
Nuclear fuel, at amortized cost 146 151
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Total utility plant 14,112 13,475
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Regulatory assets 2,934 3,285
Other deferred charges 659 567
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Total deferred charges 3,593 3,852
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Total assets $ 25,450 $ 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
September 30, December 31,
In millions, except share amounts 2005 2004
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ -- $ 88
Long-term debt due within one year 597 246
Preferred stock to be redeemed within one year -- 9
Accounts payable 780 700
Accrued taxes 585 357
Accrued interest 80 115
Counterparty collateral 354 --
Customer deposits 181 168
Book overdrafts 271 232
Regulatory liabilities 1,263 490
Other current liabilities 611 643
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Total current liabilities 4,722 3,048
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Long-term debt 4,738 5,225
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Accumulated deferred income taxes - net 2,802 2,865
Accumulated deferred investment tax credits 121 126
Customer advances and other deferred credits 607 510
Power-purchase contracts 76 130
Preferred stock subject to mandatory redemption -- 139
Accumulated provision for pensions and benefits 488 417
Asset retirement obligations 2,263 2,183
Regulatory liabilities 3,302 3,356
Other long-term liabilities 292 232
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Total deferred credits and other liabilities 9,951 9,958
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Total liabilities 19,411 18,231
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Commitments and contingencies (Notes 2, 4, and 6)
Minority interest 451 409
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 350 350
Accumulated other comprehensive loss (15) (17)
Retained earnings 2,356 2,020
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Total common shareholder's equity 4,859 4,521
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Preferred and preference stock
not subject to mandatory redemption 729 129
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Total shareholders' equity 5,588 4,650
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Total liabilities and shareholders' equity $ 25,450 $ 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
Nine Months Ended
September 30,
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In millions 2005 2004
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(Unaudited)
Cash flows from operating activities:
Net income $ 586 $ 604
Adjustments to reconcile to net cash provided by
operating activities:
Depreciation, decommissioning and amortization 688 628
Other amortization 72 72
Minority interest 283 236
Deferred income taxes and investment tax credits (273) 271
Regulatory assets - long-term 372 318
Regulatory liabilities - long-term (92) (38)
Other assets (91) (27)
Other liabilities 83 49
Margin and collateral deposits - net of collateral
received 271 11
Receivables and accrued unbilled revenue (519) (217)
Inventory, prepayments and other current assets (430) (93)
Regulatory assets - short-term 7 (1,050)
Regulatory liabilities - short-term 773 698
Accrued interest and taxes 192 112
Accounts payable and other current liabilities 92 278
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Net cash provided by operating activities 2,014 1,852
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Cash flows from financing activities:
Long-term debt issued and issuance costs 980 1,598
Long-term debt repaid (1,041) (967)
Bonds remarketed - net -- 350
Issuance of preference stock 592 --
Redemption of preferred stock (148) (2)
Rate reduction notes repaid (177) (177)
Short-term debt financing - net (88) (200)
Change in book overdrafts 39 (189)
Shares purchased for stock-based compensation (95) (29)
Proceeds from stock option exercises 50 19
Minority interest (241) (178)
Dividends paid (224) (599)
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Net cash used by financing activities (353) (374)
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Cash flows from investing activities:
Capital expenditures (1,295) (1,121)
Acquisition costs related to nonutility generation plant -- (285)
Contributions to and earnings from
nuclear decommissioning trusts - net (76) (62)
Customer advances for construction and other investments 72 4
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Net cash used by investing activities (1,299) (1,464)
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Effect of consolidation of variable interest entities on cash -- 79
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Net increase in cash and equivalents 362 93
Cash and equivalents, beginning of period 122 95
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Cash and equivalents, end of period $ 484 $ 188
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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 September 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 September 30, 2005 financial statement
presentation.
Counterparty Collateral
Counterparty collateral includes cash received related to financial gas trading activities.
Income Taxes
SCE's effective tax rates were 16% and 24% for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to 40% for both the same periods in 2004. The decreased effective tax rates
resulted primarily from recording a $61 million benefit, including $45 million of interest income, in the
third quarter of 2005 related to a settlement reached with the IRS on tax issues and pending affirmative
claims relating to Edison International's 1991 - 1993 tax years. See "Other Developments--Federal Income
Taxes" for further discussion of this matter. Additional decreases to the effective rates resulted from
reductions made to accrued tax liabilities in 2005 to reflect progress made in settlement negotiations
related to tax audits other than the 1991 - 1993 tax years, changes in property-related flow-through items
and adjustments made to tax balances in 2005.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under
margining agreements for power and gas trading activities. The amount of margin and collateral deposits
varies based on changes in the value of the agreements. Deposits with counterparties and brokers earn
interest at various rates.
New Accounting Principles
In March 2005, the FASB issued an interpretation related to accounting for conditional asset retirement
obligations (AROs). This Interpretation clarifies that an entity is required to recognize a liability for
the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty
Page 5
exists about the timing and/or method of settlement. This Interpretation is effective December 31, 2005.
Thus far, SCE has identified conditional AROs related to: treated wood poles, hazardous materials such as
mercury and polychlorinated biphenyls-containing equipment; and asbestos removal costs at buildings,
operating stations and retired units. Additional assessment is necessary to value these AROs. However,
since SCE follows accounting principles for rate-regulated enterprises and receives recovery of these costs
through rates, implementation of this Interpretation at SCE will not affect earnings.
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 related to stock options granted is shown below under "Stock-Based Compensation." SCE
is assessing the impact of this accounting standard on its performance shares.
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. In October 2005, the IRS issued proposed regulations
for this tax deduction. The tax deduction is not expected to materially affect SCE's 2005 financial
statements. SCE is evaluating the effect that the manufacturer's deduction will have in subsequent years.
Page 6
Regulatory Assets and Liabilities
Regulatory assets included in the consolidated balance sheets are:
September 30, December 31,
In millions 2005 2004
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(Unaudited)
Current:
Regulatory balancing accounts $ 348 $ 371
Direct access procurement charges 112 109
Purchased-power settlements 57 62
Other 29 11
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546 553
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Long-term:
Flow-through taxes - net 1,008 1,018
Rate reduction notes - transition cost deferral 520 739
Unamortized nuclear investment - net 493 526
Nuclear-related ARO investment - net 261 272
Unamortized coal plant investment - net 81 78
Unamortized loss on reacquired debt 328 250
Direct access procurement charges 63 141
Environmental remediation 55 55
Purchased-power settlements 50 91
Other 75 115
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2,934 3,285
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Total regulatory assets $ 3,480 $ 3,838
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Regulatory liabilities included in the consolidated balance sheets are:
September 30, December 31,
In millions 2005 2004
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(Unaudited)
Current:
Regulatory balancing accounts $ 680 $ 357
Direct access procurement charges 112 109
Energy derivatives 398 --
Other 73 24
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1,263 490
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Long-term:
ARO 806 819
Costs of removal 2,151 2,112
Direct access procurement charges 63 141
Energy derivatives 47 --
Employee benefits plans 235 200
Other -- 84
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3,302 3,356
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Total regulatory liabilities $ 4,565 $ 3,846
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SCE's regulatory liabilities related to energy derivatives are an offset to unrealized gains on recorded
derivatives.
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 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 Nine Months Ended
September 30, September 30,
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In millions 2005 2004 2005 2004
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(Unaudited)
Net income available for common stock, as reported $ 280 $ 259 $ 572 $ 600
Add: stock-based compensation expense using the
intrinsic value accounting method - net of tax 9 2 23 6
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 10 2 27 6
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Pro forma net income available for common stock $ 279 $ 259 $ 568 $ 600
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Supplemental Cash Flows Information
Nine Months Ended
September 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 $ 279 $ 283
Tax payments (receipts) 329 8
Non-cash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed $ (452) --
Pollution-control bonds issued 452 --
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 Contingencies
Further information on these regulatory matters is described in Note 2 of "Notes to Consolidated Financial
Statements" included in SCE's 2004 Annual Report. See Note 4 for additional contingencies.
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 December 2004, the California
Public Utilities Commission (CPUC) issued its decision on how the CDWR's power charge revenue requirement for
2004 through 2013 would 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.
The burden of the additional costs, relative to the December 2004 decision, is borne almost entirely by SCE's
customers for the period 2004-2009, and then shifts almost entirely to PG&E's customers in 2010-2011, when
contract deliveries of the CDWR energy to PG&E's customers falls by approximately 75%. SCE, joined by The
Utility Reform Network and the California Large Electricity Consumers Association, filed a petition for
modification of the June 30, 2005 decision, seeking to levelize the allocation of additional costs under the
decision to SCE's and PG&E's customers and requesting
Page 9
clarification on other implementation issues. On November 2, 2005, the CPUC issued a proposed decision
denying the petition for modification. The final decision is expected in December 2005.
The CDWR has submitted its 2006 revenue requirement determination to the CPUC for implementation. The CPUC
must issue its final decision implementing the 2006 CDWR revenue requirement in December 2005. The November
2, 2005 proposed decision mentioned above also implements the CDWR's 2006 revenue requirement. A final
decision is expected in December 2005.
Amounts billed to SCE's customers for electric power purchased and sold by the CDWR are remitted directly to
the CDWR and are not recognized as revenue by SCE and therefore have no impact on SCE's earnings.
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. On October 27,
2005, the CPUC approved the settlement agreement which found it reasonable for SCE to recover approximately
$42 million of these claims which include all of SCE's outstanding claims, as well as future claims related
to SCE's pre-1998 energy efficiency programs (of which approximately $9 million has already been collected in
rates). The remaining portion of claims in the amount of $33 million will be recognized in the fourth
quarter of 2005. As a result of the decision, during the third quarter of 2005, SCE
recognized $14 million of incentives previously awarded for which revenue recognition was deferred pending
final resolution of these matters. The $14 million is reflected in the income statement caption "Other
nonoperating income." In addition, $4 million related to interest on the claims was reflected in the caption
"Interest and dividend income."
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
Page 10
"trigger" mechanism, whereby SCE can request an emergency rate adjustment in addition to the annual forecast
and reasonableness ERRA applications.
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. In August 2005, the ORA recommended a
$16 million disallowance associated with SCE's 2004 sales of energy in the hour-ahead market, alleging that
the price at which SCE sold its hour-ahead energy was unreasonable. SCE submitted its rebuttal testimony on
September 15, 2005, contesting the ORA's recommendation. In addition, in its opening briefs, the ORA
recommended that SCE be penalized $37 million for allegedly having failed to prove that its least-cost
dispatch operations complied with the methodology presented by the ORA. SCE believes the disallowance and
recommended penalty are without merit. A decision is expected by the end of 2005.
Generation Procurement Proceedings
SCE resumed power procurement responsibilities for its net-short position (expected load requirements exceed
generation supply) on January 1, 2003, pursuant to CPUC orders and California statutes passed in 2002. The
current regulatory and statutory framework requires SCE to assume limited responsibilities for CDWR contracts
allocated by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term
procurement plans, long-term resource plans and increased procurement of renewable resources. Currently, the
CPUC and the California Energy Commission are working together to set rules for various aspects of generation
procurement which are described below.
Procurement Plan
In December 2003, the CPUC adopted a short-term procurement plan for SCE which established a target level for
spot market purchases equal to 5% of monthly need, and allowed SCE to enter into contracts of up to five
years. Currently, SCE is operating under this approved short-term procurement plan. To the extent SCE
procures power in accordance with the plan, SCE receives full-cost recovery of its procurement transactions
pursuant to Assembly Bill 57. Accordingly, the plan is referred to as the Assembly Bill 57 component of the
procurement plan.
Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related
transactions associated with serving the demands of its bundled electricity customers were in conformance
with SCE's adopted short-term procurement plan. SCE has submitted quarterly compliance filings covering the
period from January 1, 2003 through September 30, 2005. The CPUC issued one resolution approving SCE's first
compliance report for the period January 1, 2003 to March 31, 2003 and issued a resolution approving the
other transactions for calendar year 2003 in a June 16, 2005 resolution.
Resource Adequacy Requirements
Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving entities in California
have an obligation to procure sufficient resources to meet their customers' needs. On
Page 11
October 27, 2005, the CPUC issued a decision clarifying the January 2004 decision and a subsequent October
2004 decision on resource adequacy requirement. The October 2005 decision requires load-serving entities to
ensure that adequate resources have been contracted to meet that entity's peak forecasted energy resource
demand and an additional planning reserve margin of 15-17% in every month of the year, beginning in June
2006. The October 2005 decision requires that SCE demonstrate that it has contracted 90% of its
June-September 2006 resource adequacy requirement by January 2006. By the end of May 2006, SCE will be
required to fill out the remaining 10% of its resource adequacy requirement one month in advance of expected
need. A month-ahead showing demonstrating that SCE has procured 100% of its resource adequacy requirement
will be required every month thereafter. The October 2005 decision also adopted limits on the amount of a
portfolio-sourced, as opposed to a unit-specific, firm energy contract that can be used to meet a load
serving entity's resource adequacy requirement. Under the October 2005 decision, a load-serving entity can
have no more than 75% of its portfolio of resource adequacy resources met by such contracts in 2006, no more
than 50% met by such contracts in 2007, and no more than 25% met by such contracts in 2008. No such
contracts can be used to meet a load-serving entities' resource adequacy requirement after December 31,
2008. The October 2005 decision also clarified that the CDWR contracts, some of which are firm energy
contracts, are not subject to the limitations. Additionally, the October 2005 decision adopted minimum
elements for contracts upon which load-serving entities' may rely on to meet their resource adequacy
obligations. Further, the October 2005 decision deferred implementation of a local resource adequacy
requirement until 2007. Lastly, the October 2005 decision adopted penalties of 150% of the cost of new
monthly capacity for load serving entities that fail to acquire sufficient resources in 2006, and a 300%
penalty in 2007 and beyond. SCE expects to meet its resource adequacy requirements by the deadlines set
forth in the decision.
In July 2005, SCE issued a Request for Offers (RFO) whereby SCE solicited offers from sellers in the ISO
control area for products that provide capacity, energy and resource adequacy benefits. In early October,
SCE executed a number of contracts for these products for terms up to 56 months.
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan for 2005 through 2014 was filed on March 7, 2005. On July 21, 2005,
the CPUC issued a decision approving SCE's renewable procurement plan for 2005 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. On October 6, 2005, the CPUC issued a decision conditionally approving SCE's renewable procurement
plan for 2006 through 2014.
The CPUC's July 21, 2005 decision referenced above 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. SCE is currently pursuing reconsideration of the July 21, 2005 decision.
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
November 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.
Page 12
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, the CPUC could deem SCE to be out of compliance
with its statutory renewable procurement obligations for the years 2003, 2004 and 2005, and therefore SCE
could be subject to penalties for those years. In addition, the California Energy Commission's and the
CPUC's treatment of the production from the geothermal facilities could result in SCE being deemed to be out
of compliance with its obligations for 2006. The maximum penalty for noncompliance 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. On August 11, 2005
and August 31, 2005, SCE submitted advice letters seeking CPUC approval of two additional renewable contracts
resulting from the solicitation.
The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new request for proposals for
additional renewable contracts. SCE issued its 2005 request for proposals for renewable contracts on
September 2, 2005. Proposals for renewable contracts have been received and are being evaluated.
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 an RFO for new generation resources. SCE 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 filed an application with the CPUC seeking
approval of the RFO and the power-purchase agreements executed under the RFO. SCE sought recovery of the
costs of the contracts, through the Federal Energy Regulatory Commission (FERC)-jurisdictional rates, from
all affected customers. In addition, SCE sought CPUC assurance of full cost recovery in CPUC-approved rates,
if the FERC denies any recovery. On September 9, 2005, the CPUC issued a scoping memorandum rejecting SCE's
proposal. Since the scoping memorandum did not provide a mechanism for SCE to secure new generation on
behalf of these customers, SCE terminated its RFO and moved to stay the proceeding and withdraw the CPUC
application. A stay was granted on September 22, 2005. The motion to withdraw is still pending.
Holding Company Proceeding and Order Instituting Rulemaking (OIR)
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
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appropriateness of the large utilities' holding company structure and dividend policies), the CPUC may rule
on or investigate these issues in the future.
On October 27, 2005, the CPUC issued an OIR to allow the CPUC to re-examine the relationships of the major
California energy utilities with their parent holding companies and nonregulated affiliates. The OIR was
issued in part in response to the recent repeal of the Public Utility Holding Company Act of 1935.
By means of the OIR, the CPUC will consider whether additional rules to supplement existing rules and
requirements governing relationships between the public utilities and their holding companies and
nonregulated affiliates should be adopted. Any additional rules will focus on whether (1) the public
utilities retain enough capital or access to capital to meet their customers' infrastructure needs and
(2) mitigation of potential conflicts between ratepayer interests and the interests of holding companies and
affiliates that could undermine the public utilities' ability to meet their public service obligations at the
lowest cost. The CPUC expects to issue proposed rules in January 2006, and a final decision is expected in
March 2006.
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, Colton 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, which was stayed
pending resolution of SCE's rehearing request, SCE would be charged a certain amount as the Participating
Transmission Owner but also would be credited in its role as an SC and through the California Power Exchange,
to the extent it acted as SCE's SC. 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 Court of Appeals
for the D.C. Circuit. A briefing schedule has been set in the appeal with SCE's opening brief due on
December 23, 2005. 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; and
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, water studies and other
efforts have continued among the relevant parties in an attempt to resolve Mohave's post-2005 coal and water
supply issues. Although progress has been made with respect to certain issues, no complete resolution has
been reached to date. Because resolution has not been reached and because of the lead
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times required for installation of certain pollution-control equipment and other upgrades necessary for
post-2005 operation, it appears probable that Mohave will temporarily shut down at the end of 2005, and a
permanent shutdown remains possible. The outcome of the efforts to resolve the post-2005 coal and water
supply issues is 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.
System Reliability Incentive Mechanism
SCE's 2003 General Rate Case (GRC) decision provided for performance incentives or penalties for differences
between SCE's actual results and CPUC-authorized standards for system reliability measures beginning in
2004. In a March 30, 2005 advice letter, SCE reported a $2 million penalty and recorded an accrual in 2004
for its 2004 results under the modified reliability mechanism. On April 28, 2005, the CPUC agreed to suspend
its review of SCE's advice letter for 2004 results until the CPUC's Consumer Protection and Safety Division
(CPSD) has completed its investigation regarding performance incentive rewards discussed in Note 4. Based on
preliminary recorded data through September 2005 and a forecast of normal results through December 2005, SCE
projects it will incur a penalty of $26 million under the reliability performance mechanism for 2005. The
maximum penalty that could be assessed under the reliability performance mechanism is approximately $40
million. As a result, during the third quarter of 2005, SCE recorded an accrual of $26 million that is
reflected in the income statement caption "Other nonoperating deductions."
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 Court of Appeals for the Federal Circuit. On July 12, 2005, the Court of
Appeals for the Federal Circuit vacated the FERC's August and November 2002 orders, and remanded the case to
the FERC for further proceedings. SCE believes that the Court of Appeals for the Federal Circuit'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.
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
Page 15
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 was approved by the Enron bankruptcy court on October 20, 2005,
but remains subject to approval by the FERC. Effective August 24, 2005, the CPUC approved the settlement by
entering into an agreement incorporating its terms. The Enron settlement proceeds will be refunded to
ratepayers as described below.
On August 12, 2005, SCE, PG&E, SDG&E, several governmental entities and certain other parties agreed to
settlement terms with Reliant Energy, Inc. and a number of its affiliates (collectively Reliant). Among
other things, the settlement terms provide for Reliant to provide cash and cash equivalents having a total
value of at least $460 million, which would be in addition to the $65 million in refunds that Reliant was
already required to provide pursuant to FERC orders. SCE expects that its allocable share of the entire
settlement value of $525 million (including the amounts previously ordered by the FERC) will be approximately
$130 million. The settlement remains subject to FERC approval, which is anticipated in the first quarter of
2006. Effective October 12, 2005, the CPUC approved the settlement by entering into an agreement
incorporating its terms. The Reliant 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
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(excluding the El Paso settlement) from energy providers and allocating them in accordance with the terms of
the October 2001 settlement agreement entered into by SCE and the CPUC which settled SCE's lawsuit against
the CPUC. This lawsuit sought full recovery of SCE's electricity procurement costs incurred during the
energy crisis. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in
the ESMA will be allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings
described above and a 10% shareholder incentive pursuant to the CPUC litigation settlement agreement.
Remaining amounts for each settlement are to be refunded to ratepayers through the ERRA mechanism. In the
second quarter of 2005, SCE recorded a $7 million increase to other nonoperating income as a shareholder
incentive related to the Mirant refund received during the second quarter of 2005.
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
September 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 Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
---------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 24 $ 22 $ 73 $ 66
Interest cost 40 41 120 123
Expected return on plan assets (54) (58) (162) (173)
Net amortization and deferral 6 5 18 16
---------------------------------------------------------------------------------------------------------------
Expense under accounting standards 16 10 49 32
Regulatory adjustment - deferred (2) -- (6) --
---------------------------------------------------------------------------------------------------------------
Total expense recognized $ 14 $ 10 $ 43 $ 32
---------------------------------------------------------------------------------------------------------------
Page 17
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 September 30, 2005, $18 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 Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------------------------------------------------
In millions 2005 2004 2005 2004
---------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 12 $ 8 $ 34 $ 30
Interest cost 30 29 90 94
Expected return on plan assets (26) (27) (77) (82)
Amortization of unrecognized prior service costs (7) (1) (21) (16)
Amortization of unrecognized loss 12 -- 36 31
---------------------------------------------------------------------------------------------------------------
Total expense $ 21 $ 9 $ 62 $ 57
---------------------------------------------------------------------------------------------------------------
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 $81 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
Page 18
$115 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 $29 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 $55 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.
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 $11 million to $25 million. Recorded costs for the twelve
months ended September 30, 2005 were $11 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, resulted in a third quarter 2005 net earnings benefit for SCE of approximately $61 million,
including interest. This benefit was reflected in the income statement caption "Income tax".
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.
Page 19
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 GRC decision) provides for performance incentives or penalties for
differences between actual results and GRC-determined standards of employee injury and illness reporting, and
system reliability.
SCE has been conducting investigations into its performance under these mechanisms and has reported to the
CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported
events, the CPUC could institute its own proceedings to determine whether and in what amounts to order
refunds or disallowances of past and potential PBR rewards for customer satisfaction, injury and illness
reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional
penalties on SCE. SCE cannot predict with certainty the outcome of these matters or estimate the potential
amount of refunds, disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service
planning group of SCE's transmission and distribution business unit altered or omitted data in attempts to
influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The
results of these surveys are used, along with other factors, to determine the amounts of any incentive
rewards or penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate
customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer
satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have
not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer
satisfaction rewards of about $10 million for 2003.
SCE has been keeping the CPUC informed of the progress of SCE's internal investigation. On June 25, 2004,
SCE submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees in
the design organization of the transmission and distribution business unit deliberately altered customer
contact information in order to affect the results of customer satisfaction surveys. At least 36 design
organization personnel engaged in deliberate misconduct including alteration of customer information before
the data were transmitted to the independent survey company. Because of the apparent scope of the
misconduct, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forego
an additional $5 million of the PBR rewards pending that are both attributable to the design organization's
portion of the customer satisfaction rewards for the entire PBR period (1997-2003). In addition, during its
investigation, SCE determined that it could not confirm the integrity of the method used for obtaining
customer satisfaction survey data for meter reading. Thus, SCE also proposed to refund all of the
approximately $2 million of customer satisfaction rewards associated
Page 20
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 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. In
addition, the CPSD has conducted interviews of four senior managers and executives of the Transmission and
Distribution Business Unit regarding the design organization.
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation
into the accuracy of SCE's employee injury and illness reporting. The yearly results of employee injury and
illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE
under the PBR mechanism. Since the inception of PBR in 1997, SCE has received $20 million in employee safety
incentives for 1997 through 2000 and, based on SCE's records, would have been entitled to an additional
$15 million for 2001 through 2003 ($5 million for each year).
On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings
concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. Under the
PBR mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident
rate, which included two equally weighted measures: Occupational Safety and Health Administration (OSHA)
recordable incidents and first aid incidents. The major issue disclosed in the investigative findings to the
CPUC was that SCE failed to implement an effective recordkeeping system sufficient to capture all required
data for first aid incidents. SCE's investigation also found reporting inaccuracies for OSHA recordable
incidents, but the impact of these inaccuracies did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the PBR
mechanism for any year before 2004, and it return to ratepayers the $20 million it has already received.
Therefore, SCE accrued a $20 million charge in 2004 for the potential refund of these rewards. SCE has also
proposed to withdraw the pending requests for rewards for the 2001-2002 time frames. SCE has not yet filed a
request related to its performance for 2003 under the PBR mechanism.
SCE is taking other remedial action to address the issues identified, including revising its organizational
structure and overall program for environmental, health and safety compliance. SCE also took disciplinary
action against twenty-four individuals in several SCE business areas in early June 2005. SCE submitted a
report on the results of its investigation to the CPUC on December 3, 2004.
As with the customer satisfaction matter, the CPUC has not yet opened a formal investigative proceeding into
this matter. However, the CPSD did submit several data requests to SCE to which SCE has responded.
Page 21
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, 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. On
July 28, 2005, the D.C. District Court issued an order removing the lawsuit from the Court's active docket.
Page 22
The Court of Appeals for the Federal Circuit, 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 Federal Circuit decision. Both petitions were denied on March 9, 2004. On March 16,
2004, the Federal Circuit 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 Court of Federal Claims ordered the Navajo Nation and the Government to brief the remaining
issues following remand (described below). 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 considered 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 Navajo Nation's motion to strike took place
at a hearing on September 28, 2005, at which time the motion was denied. At the same hearing, the Court of
Federal Claims heard argument on the issues remanded by the Federal Circuit, which are focused on (1) whether
the Navajo Nation previously waived its "network of other laws" argument and, (2) if not, whether the Navajo
Nation can establish that the Government breached any fiduciary duties pursuant to such "network." At the
conclusion of the September 28, 2005 hearing, the Court of Federal Claims took the remanded issues under
submission.
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 current maximum deferred premium for
each nuclear incident is $101 million per reactor, but not more than $15 million per reactor may be charged
in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per
reactor for each nuclear incident will be adjusted for inflation on a 5-year schedule. The next inflation
adjustment will occur on August 31, 2008. 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 $30 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.
Page 23
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 $44 million per year. Insurance premiums are charged to operating
expense.
Schedule Coordinator Tariff Dispute
SCE serves as an SC for the Los Angeles Department of Water & Power (DWP) over the ISO-controlled grid. In
mid-2003, SCE filed a petition asking that the FERC accept a tariff that provides for a direct pass-through
of the FERC-authorized charges incurred by SCE on the DWP's behalf. The DWP protested SCE's filing. The DWP
asked the FERC to declare that SCE was obligated to serve as the DWP's SC without charge. In late 2003, the
FERC accepted the tariff, subject to refund. The FERC held that the proposed tariff has not been shown to be
just and reasonable.
In accordance with the terms of the tariff, SCE issued several invoices for charges to the DWP. The DWP has
objected to all of the charges but has paid, under protest, approximately $18 million. The DWP has protested
specific charges totaling approximately $5 million based on its allegations that those specific charges are
improper for various reasons.
The FERC has not issued a final order on this issue. SCE could be required to refund all or part of the
amounts collected under the tariff. SCE continues to invoice the DWP. Monthly invoices have been averaging
approximately $1 million. SCE cannot predict with certainty the outcome of the FERC final order.
Spent Nuclear Fuel
Under federal law, the United States Department of Energy (DOE) is responsible for the selection and
construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive
waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than
January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or
other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives
and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to
nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is
also paying the required quarterly fee equal to 0.1(cent)-per-kWh of nuclear-generated electricity sold after
April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United
States Court of Federal Claims seeking damages for DOE's failure to meet its obligation to begin accepting
spent nuclear fuel from San Onofre. The case is currently stayed pending development in other spent nuclear
fuel cases also before the United States Court of Federal Claims.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent
nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent
fuel storage installation. Movement of Unit 1 spent fuel from the Unit 2 spent fuel pool to the independent
spent fuel storage installation is complete. There is now sufficient space in the Unit 2 and 3 spent fuel
pools to meet plant requirements through mid-2007 and mid-2008, respectively.
Page 24
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 September 30, 2005:
Cash $ 367 $ 117 $ -- $ 484
Accounts receivable-net 973 188 (133) 1,028
Materials and supplies 186 15 -- 201
Prepayments and other current assets 479 6 -- 485
Nonutility property-net of depreciation 685 349 -- 1,034
Other deferred charges 649 10 -- 659
Total assets 24,898 685 (133) 25,450
Accounts payable 748 165 (133) 780
Accrued interest 79 1 -- 80
Other current liabilities 609 2 -- 611
Long-term debt 4,684 54 -- 4,738
Asset retirement obligations 2,250 13 -- 2,263
Minority interest 1 450 -- 451
Total liabilities and shareholder's equity 24,898 685 (133) 25,450
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 25
Electric
In millions Utility VIEs Eliminations* SCE
---------------------------------------------------------------------------------------------------------------
Income Statement Items for the (Unaudited)
Three Months Ended September 30, 2005:
Operating revenue $ 2,968 $ 406 $ (290) $ 3,084
Fuel 71 225 -- 296
Purchased power 792 -- (290) 502
Other operation and maintenance 649 21 -- 670
Depreciation, decommissioning and amortization 225 9 -- 234
Total operating expenses 2,551 255 (290) 2,516
Operating income 417 151 -- 568
Minority interest -- 151 -- 151
Net income 287 -- -- 287
Income Statement Items for the
Nine Months Ended September 30, 2005:
Operating revenue $ 6,876 $1,003 $ (684) $ 7,195
Fuel 193 624 -- 817
Purchased power 2,317 -- (684) 1,633
Other operation and maintenance 1,770 68 -- 1,838
Depreciation, decommissioning and amortization 660 28 -- 688
Total operating expenses 5,874 720 (684) 5,910
Operating income 1,002 283 -- 1,285
Minority interest -- 283 -- 283
Net income 586 -- -- 586
Income Statement Items for the
Three Months Ended September 30, 2004:
Operating revenue $ 2,559 $ 366 $ (270) $ 2,655
Fuel 67 187 -- 254
Purchased power 1,185 -- (270) 915
Other operation and maintenance 588 19 -- 607
Depreciation, decommissioning and amortization 179 9 -- 188
Total operating expenses 2,028 215 (270) 1,973
Operating income 531 151 -- 682
Minority interest -- 151 -- 151
Net income 260 -- -- 260
Income Statement Items for the
Nine Months Ended September 30, 2004:
Operating revenue $ 6,337 $ 668 $ (478) $ 6,527
Fuel 175 375 -- 550
Purchased power 2,500 -- (478) 2,022
Other operation and maintenance 1,729 38 -- 1,767
Depreciation, decommissioning and amortization 609 19 -- 628
Total operating expenses 5,062 432 (478) 5,016
Operating income 1,275 236 -- 1,511
Minority interest -- 236 -- 236
Net income 604 -- -- 604
---------------------------------------------------------------------------------------------------------------
* 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 26
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 $31 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: $100 cumulative preferred - 12 million, $25 cumulative preferred - 24 million,
and preference - 50 million. SCE issued 4 million shares of 5.349% Series A preference stock
(non-cumulative, $100 liquidation value) on April 27, 2005. The Series A preference stock may not be
redeemed prior to April 30, 2010. After April 30, 2010, SCE may, at its option, redeem the shares in whole
or in part and the dividend rate may be adjusted. SCE issued 2 million shares of 6.125% Series B preference
stock (non-cumulative, $100 liquidation value) on September 21, 2005. The Series B preference stock may not
be redeemed prior to September 30, 2010. After September 30, 2010, SCE may, at its option, redeem the shares
in whole or in part. There is no sinking fund for the redemption or repurchase of the shares. The Series A
and B preference stock rank junior to all of the preferred stock and senior to all common stock. The Series
A and B 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 27
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 nine-month periods ended September 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 nine-month periods ended September 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 the market structure rules applicable to each market and 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 availability of labor, equipment and materials;
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 the cost and availability of coal, natural gas, and fuel oil, and associated transportation costs;
o the ability to provide sufficient collateral in support of hedging activities and purchases of fuel
and electric energy;
o general political, economic and business decisions;
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.
Page 28
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 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
On December 21, 2004, SCE filed its application for a 2006 General Rate Case (GRC) requesting a 2006 base
rate revenue requirement of $4.06 billion, an increase of $370 million over SCE's 2005 base rate revenue.
The increase is primarily for capital-related expenditures to accommodate infrastructure replacement, and
customer and load growth. The requested increase is also necessary to fund substantially higher operating
and maintenance (O&M) expenses, particularly in SCE's transmission and distribution business unit. SCE also
requested that the CPUC authorize the continuation of SCE's existing post-test year rate-making mechanism.
As part of the GRC process, the CPUC's Office of Ratepayer Advocates (ORA) submitted testimony proposing
adjustments to reduce SCE's requested 2006 base rate revenue requirement to $3.55 billion. In addition,
several intervenors have proposed further adjustments, totaling $230 million, to reduce SCE's requested 2006
base rate revenue requirement.
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 and maintenance outage in the
O&M expense forecast for San Onofre Nuclear Generating Station (San Onofre) in 2006. SCE's revised requested
2006 base rate revenue requirement is $3.96 billion, an increase of $325 million over SCE's 2005 base rate
revenue. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for
2008.
A final CPUC decision is expected in January 2006. SCE cannot predict with certainty the final outcome of
SCE's GRC application. See "Regulatory Matters--Transmission and Distribution--2006 General Rate Case
Proceeding" for further discussion.
Passage of Comprehensive Energy Legislation by Congress
A comprehensive energy bill was passed by the House and Senate in July 2005 and was signed by the President
on August 8, 2005. Known as "EPAct 2005," this comprehensive legislation includes provisions for the repeal
of the Public Utility Holding Company Act, for amendments to 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
Page 29
to be promulgated 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 September 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 September 30, 2005, SCE's short-term
(commercial paper) credit ratings from Standard & Poor's and Moody's Investors Service were A2 and P2,
respectively.
As of September 30, 2005, SCE had cash and equivalents of $484 million ($117 million of which was held by
SCE's consolidated Variable Interest Entities (VIEs)). As of September 30, 2005, long-term debt, including
current maturities of long-term debt, was $5.34 billion. 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
terms of the credit facility agreement. As of September 30, 2005, SCE's credit facility supported $12
million in letters of credit, leaving $1.24 billion available under the credit facility.
As discussed in "Regulatory Matters--Generation and Power Procurement--Energy Resource Recovery Account
Proceedings," the CPUC established the Energy Resource Recovery Account (ERRA) as the rate-mechanism to track
and recover energy procurement-related costs. As of September 30, 2005, the ERRA was overcollected by $112
million.
SCE has entered into margining agreements for power and gas trading activities to support the risk of
nonperformance. SCE's margin deposit requirements can vary depending upon the level of unsecured credit
extended by counterparties and brokers, the California Independent System Operator (ISO) credit requirements,
changes in market prices relative to contractual commitments, and other factors. At September 30, 2005, SCE
had deposited $130 million in cash with a broker in margin accounts in support of gas trading activities and
had deposited $31 million (comprised of $19 million in cash and $12 million in letters of credit) with
counterparties in support of power-purchase agreements and to enter into transactions for imbalance energy
through the ISO. Deposits with counterparties and brokers earn interest at various rates. The $149 million
of cash deposited with brokers and counterparties are reflected in the caption "Margin and Collateral
Deposits" on the balance sheet.
SCE's estimated cash outflows, during the twelve-month period following September 30, 2005, consist of:
o Debt maturities of approximately $597 million, including approximately $247 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 each of April 28, 2005, July 28, 2005 and September 30, 2005;
o Fuel and procurement-related costs; and
o General operating expenses.
Page 30
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.
SCE has debt covenants that require certain interest coverage, interest and preferred dividend coverage, and
debt to total capitalization ratios to be met. At September 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
Page 31
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 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. In August, 2005, the ORA recommended a
$16 million disallowance associated with SCE's 2004 sales of energy in the hour-ahead market, alleging that
the price at which SCE sold its hour-ahead energy was unreasonable. SCE submitted its rebuttal testimony on
September 15, 2005 contesting the ORA's recommendation. In addition, in its opening briefs, the ORA
recommended that SCE be penalized $37 million for allegedly having failed to prove that its least-cost
dispatch operations complied with the methodology presented by the ORA. SCE believes the disallowance and
recommended penalty are without merit. A decision is expected by the end of 2005.
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 forecasted a procurement-related
revenue requirement for the 2006 calendar year of $3.8 billion, an increase of $509 million over SCE's
adopted 2005 ERRA proceeding revenue requirement. The increase was 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), 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 requested that the CPUC 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).
Page 32
SCE expects the 2006 system average rate for bundled service customers to range between 14.3(cent)-per-kWh and
15.0(cent)-per-kWh.
CDWR-Related Matters
CDWR Power Purchases and Revenue Requirement Proceedings
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended
2004 MD&A, in December 2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement
for 2004 through 2013 would 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.
The burden of the additional costs, relative to the December 2004 decision, is borne almost entirely by SCE's
customers for the period 2004-2009, and then shifts almost entirely to PG&E's customers in 2010-2011, when
contract deliveries of CDWR energy to PG&E's customers falls by approximately 75%. SCE, joined by The
Utility Reform Network (TURN) and the California Large Electricity Consumers Association (CLECA), filed a
petition for modification of the June 30, 2005 decision, seeking to levelize the allocation of additional
costs under the decision to SCE's and PG&E's customers and requesting clarification on other implementation
issues. On November 2, 2005, the CPUC issued a proposed decision denying the petition for modification. The
final decision is expected in December 2005.
The CDWR has submitted its 2006 revenue requirement determination to the CPUC for implementation. The CPUC
must issue its final decision implementing the 2006 CDWR revenue requirement in December 2005. The November
2, 2005 proposed decision mentioned above also implement the CDWR's 2006 revenue requirement. A final
decision is expected in December 2005.
Amounts billed to SCE's customers for electric power purchased and sold by the CDWR are remitted directly to
the CDWR and are not recognized as revenue by SCE and therefore have no impact on SCE's earnings. 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
SCE resumed power procurement responsibilities for its net-short position (expected load requirements exceed
generation supply) on January 1, 2003, pursuant to CPUC orders and California statutes passed in 2002. The
current regulatory and statutory framework requires SCE to assume limited responsibilities for CDWR contracts
allocated by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term
procurement plans, long-term resource plans and increased procurement of renewable resources. Currently, the
CPUC and the California Energy Commission are working together to set rules for various aspects of generation
procurement which are described below.
Procurement Plan
In December 2003, the CPUC adopted a short-term procurement plan for SCE which established a target level for
spot market purchases equal to 5% of monthly need, and allowed SCE to enter into contracts
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of up to five years. Currently, SCE is operating under this approved short-term procurement plan. To the
extent SCE procures power in accordance with the plan, SCE receives full-cost recovery of its procurement
transactions pursuant to Assembly Bill 57. Accordingly, the plan is referred to as the Assembly Bill 57
component of the procurement plan.
Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related
transactions associated with serving the demands of its bundled electricity customers were in conformance
with SCE's adopted short-term procurement plan. SCE has submitted quarterly compliance filings covering the
period from January 1, 2003 through September 30, 2005. The CPUC issued one resolution approving SCE's first
compliance report for the period January 1, 2003 to March 31, 2003 and issued a resolution approving the
other transactions for calendar year 2003 in a June 16, 2005 resolution.
Resource Adequacy Requirements
Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving entities in California
have an obligation to procure sufficient resources to meet their customers' needs. On October 27, 2005, the
CPUC issued a decision clarifying the January 2004 decision and a subsequent October 2004 decision on
resource adequacy requirement. The October 2005 decision requires load-serving entities to ensure that
adequate resources have been contracted to meet that entity's peak forecasted energy resource demand and an
additional planning reserve margin of 15-17% in every month of the year, beginning in June 2006. The October
2005 decision requires that SCE demonstrate that it has contracted 90% of its June-September 2006 resource
adequacy requirement by January 2006. By the end of May 2006, SCE will be required to fill out the remaining
10% of its resource adequacy requirement one month in advance of expected need. A month-ahead showing
demonstrating that SCE has procured 100% of its resource adequacy requirement will be required every month
thereafter. The October 2005 decision also adopted limits on the amount of a portfolio-sourced, as opposed
to unit-specific, firm energy contract that can be used to meet a load serving entity's resource adequacy
requirement. Under the October 2005 decision, a load-serving entity can have no more than 75% of its
portfolio of resource adequacy resources met by such contracts in 2006, no more than 50% met by such
contracts in 2007, and no more than 25% met by such contracts in 2008. No such contracts can be used to meet
a load-serving entities' resource adequacy requirement after December 31, 2008. The October 2005 decision
also clarified that the CDWR contracts, some of which are firm energy contracts, are not subject to the
limitations. Additionally, the October 2005 decision adopted minimum elements for contracts upon which
load-serving entities' may rely to meet their resource adequacy obligations. Further, the October 2005
decision deferred implementation of a local resource adequacy requirement until 2007. Lastly, the October
2005 decision adopted penalties of 150% of the cost of new monthly capacity for load serving entities that
fail to acquire sufficient resources in 2006, and a 300% penalty in 2007 and beyond. SCE expects to meet its
resource adequacy requirements by the deadlines set forth in the decision.
In July 2005, SCE issued a request for offers whereby SCE solicited offers from sellers in the ISO control
area for products that provide capacity, energy and resource adequacy benefits. In early October 2005, SCE
executed a number of contracts for these products for terms up to 56 months.
Procurement of Renewable Resources
SCE's 2005 renewable procurement plan for 2005 through 2014 was filed on March 7, 2005. On July 21, 2005,
the CPUC issued a decision approving SCE's renewable procurement plan for 2005 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. On October 6, 2005, the CPUC issued a decision conditionally approving SCE's renewable procurement
plan for 2006 through 2014.
The CPUC's July 21, 2005 decision referenced above states that SCE cannot count procurement from certain
geothermal facilities towards its 1% annual renewable procurement requirement, unless such
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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. SCE is currently pursuing reconsideration of the July 21, 2005 decision.
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
November 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, the CPUC could deem SCE to be out of compliance
with its statutory renewable procurement obligations for the years 2003, 2004 and 2005, and therefore SCE
could be subject to penalties for those years. In addition, the California Energy Commission's and the
CPUC's treatment of the production from the geothermal facilities could result in SCE being deemed to be out
of compliance with its obligations for 2006. The maximum penalty for non-compliance is $25 million per
year. To comply with renewable procurement mandates and avoid penalties for years beyond 2006, SCE will
either need to sign new contracts and/or extend existing renewable qualifying facility (QF) contracts.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and
conducted negotiations with bidders regarding potential procurement contracts. On June 30, 2005, the CPUC
issued a resolution approving six renewable contracts resulting from the solicitation. On August 11, 2005
and August 31, 2005, SCE submitted advice letters seeking CPUC approval of two additional renewable contracts
resulting from the solicitation.
The CPUC's July 21, 2005 decision referenced above also approved SCE's proposed new request for proposals for
additional renewable contracts. SCE issued its 2005 request for proposals for renewable contracts on
September 2, 2005. Proposals for renewable contracts have been received and are being evaluated.
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 an RFO for new generation resources. SCE 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 filed an application with the CPUC seeking
approval of the RFO and the power-purchase agreements executed under the RFO. SCE sought recovery of the
costs of the contracts, through the FERC-jurisdictional rates, from all affected customers. In addition, SCE
sought CPUC assurance of full cost recovery in CPUC-approved rates, if the FERC denies any recovery. On
September 9, 2005, the CPUC issued a scoping memorandum rejecting SCE's proposal. Since the scoping
memorandum did not provide a mechanism for SCE to secure new generation on behalf of these customers, SCE
terminated its RFO and moved to stay the proceeding and withdraw the CPUC application. A stay was granted on
September 22, 2005. The motion to withdraw is still pending.
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.
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In parallel with and since the conclusion of the CPUC proceeding, negotiations, water studies, and other
efforts have continued among the relevant parties in an attempt to resolve Mohave's post-2005 coal and water
supply issues. Although progress has been made with respect to certain issues, no complete 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
appears probable that Mohave will temporarily shut down at the end of 2005, and a permanent shutdown remains
possible. The outcome of the efforts to resolve the post-2005 coal and water supply issues is 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
On October 31, 2005, an assigned administrative law judge issued a proposed 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. The proposed
decision found that: (1) steam generator replacement is "marginally cost-effective" (2) $680 million ($569
million for replacement steam generator installation and $111 million for removal and disposal of the
original steam generators) is a reasonable estimate; (3) SCE will not be allowed to recover costs above $680
million for steam generator replacement; (4) SCE will be required to file an application for reasonableness
review of steam generator replacement upon completion of that work; (5) SCE can recover 20% of the estimated
costs of removal and disposal of the steam generators through depreciation during 2006-2011; (6) SCE will be
prohibited from recovering San Onofre Units 2 and 3 O&M costs above levels forecast in its test year 2006 GRC
forecast plus 10% through 2022; (7) SCE will be prohibited from recovering San Onofre Units 2 and 3 capital
expenditures above levels forecast in its test year 2006 GRC plus 25% through 2022; and (8) SCE acted
reasonably in relation to the issue of potential claims against the manufacturer of the steam generators or
its successors. Opening comments on the proposed decision are due November 21, 2005, and reply comments are
due November 28, 2005. The CPUC may adopt, reject, or modify a proposed decision. SCE anticipates that the
CPUC will issue a final decision by early next year. If the CPUC authorizes SCE to go forward with steam
generator replacement under terms that reasonably compensate SCE for the risk of operating San Onofre Units 2
and 3, SCE will recover costs that are reasonably incurred as part of the steam generator replacement capital
costs. By the time of the expected final 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 under
terms that reasonably compensate it for the risk that it undertakes by operating San Onofre Units 2 and 3.
However, there is no assurance that the CPUC would approve such a request.
San Onofre Reactor Vessel Heads
During the ongoing San Onofre Unit 3 refueling outage in the fourth quarter of 2004, SCE conducted a planned
inspection of the Unit 3 reactor vessel head and found indications of degradation. Although the indications
of degradation were far below the level at which leakage would occur, SCE repaired these
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indications of degradation using readily available tooling and a Nuclear Regulatory Commission-approved
repair technique. While this was San Onofre's first experience of this kind of degradation to the reactor
vessel head, the detection and repair of similar degradation is now common in the industry. SCE plans to
replace the Unit 2 and 3 reactor vessel heads during the planned refueling outages in 2011-2012.
Palo Verde Steam Generators
Palo Verde Steam Generator Replacement
The steam generators at Palo Verde, in which SCE owns a 15.8% interest, have material properties that are
similar to the San Onofre units. During 2003, the Palo Verde Unit 2 steam generators were replaced. In
addition, the Palo Verde owners have approved the manufacture and installation of steam generators in Units 1
and 3. On October 8, 2005, Palo Verde Unit 1 commenced an outage during which the steam generators will be
replaced. Unit 1 will return to service after the successful completion of its planned refueling and
maintenance outage including steam generator replacement. The outage is scheduled to last 75 days. The Palo
Verde owners expect that replacement steam generators will be installed in Unit 3 in the 2007 to 2008 time
frame. SCE's share of the costs of manufacturing and installing all the replacement steam generators at Palo
Verde is estimated to be about $115 million; SCE expects to recover these costs through the rate-making
process.
Inspections of Palo Verde Units 1, 2 and 3 reactor vessel heads were performed during scheduled refueling and
maintenance outages in 2003 and 2004 and no indications of leakage or degradation were found.
Transmission and Distribution
2006 General Rate Case Proceeding
On December 21, 2004, SCE filed its application for a 2006 GRC, requesting a 2006 base rate revenue
requirement of $4.06 billion, an increase of $370 million over SCE's base rate revenue. The increase is
primarily for capital-related expenditures to accommodate infrastructure replacement, and customer and load
growth. The requested 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 the
continuation of SCE's existing post-test year rate-making mechanism, which would result in further base rate
revenue increases of $159 million above the 2006 request in 2007, and $122 million above the 2007 request in
2008.
As part of the GRC process, on April 15, 2005, the ORA submitted testimony proposing adjustments to reduce
SCE's requested 2006 base rate revenue requirement to $3.55 billion. 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 as previously authorized in the 2003 GRC decision.
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 and maintenance outage in the
O&M expense forecast for San Onofre in 2006. In addition, on September 26, 2005, SCE submitted updated
testimony and revised its requested revenue requirement to reflect the current forecast of 2006-2008
escalation rates, a pending postage rate increase, revised tax depreciation rates, and the company's current
scenario for costs to operate the Mohave Generating Station. SCE's revised requested 2006 base rate revenue
requirement is $3.96 billion, an increase of $325 million over SCE's 2005 base rate revenue, as set forth in
an exhibit on October 17, 2005. SCE also proposed revised base rate revenue increases of $108 million for
2007 and $113 million for 2008.
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During the course of the GRC proceeding, the ORA revised its proposed 2006 base rate revenue requirement for
SCE to also incorporate a second refueling outage in the O&M expense forecast for San Onofre in 2006 among
other changes. The ORA's current proposed 2006 base rate revenue requirement is $3.59 billion, with further
base rate increases of $24 million for 2007 and $75 million for 2008. In addition, several intervenors have
proposed further adjustments, totaling $230 million to reduce SCE's requested 2006 rate base revenue
requirement.
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.
A final CPUC decision is expected in January 2006. SCE cannot predict with certainty the final outcome of
SCE's GRC application.
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
requested 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 requested 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. Based on the September 2005 economic forecasts of
average long-term utility bond and other interest rates for 2006, adoption of SCE's application request is
expected to now result in a projected $10 million decrease in SCE's annual revenue requirements with an
anticipated 2006 cost of long-term debt of 6.17% and cost of preferred equity of 6.09%.
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, Colton 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, which was stayed
pending resolution of SCE's rehearing request, SCE would be charged a certain amount as the Participating
Transmission Owner but also would be credited in its role as an SC and through the California Power Exchange,
to the extent it acted as SCE's SC. On March 30, 2005, the FERC issued an Order Denying Rehearing. SCE
obtained an extension of the stay pending resolution of the appeal SCE filed with the Court of Appeals for
the D.C. Circuit. A briefing schedule has been set in the appeal with SCE's opening brief due on December
23, 2005. 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, and 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.
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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 Court of Appeals for the Federal Circuit. On July 12, 2005, the Court of
Appeals for the Federal Circuit vacated the FERC's August and November 2002 orders, and remanded the case to
the FERC for further proceedings. SCE believes that the Court of Appeals for the Federal Circuit's decision
increases the likelihood that it will recover these costs.
Wholesale Electricity and Natural Gas Markets
As discussed in the "Wholesale Electricity and Natural Gas Markets" disclosure in the year-ended 2004 MD&A,
SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity
and natural gas who allegedly manipulated the electric and natural gas markets.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including
SCE, PG&E, the State of California and various consumer class action representatives) settling various claims
stated in proceedings at the FERC and in San Diego County Superior Court that El Paso had manipulated
interstate capacity and engaged in other anticompetitive behavior in the natural gas markets in order to
unlawfully raise gas prices at the California border in 2000-2001. The United States District Court has
issued an order approving the stipulated judgment and the settlement agreement has become effective.
Pursuant to a CPUC decision, SCE was required to refund to customers amounts received under the terms of the
El Paso settlement (net of legal and consulting costs) through its ERRA mechanism. In June 2004, SCE
received its first settlement payment of $76 million. Approximately $66 million of this amount was credited
to purchased-power expense, and was refunded to SCE's ratepayers through the ERRA over the following twelve
months, and the remaining $10 million was used to offset SCE's incurred legal costs. El Paso has elected to
prepay the additional settlement payments due over a 20-year period and, as a result, SCE received $66
million in May 2005. Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue
requirement allocated to SCE in proportion to SCE's share of the CDWR's power charge revenue requirement.
On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with
Mirant Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in
Chapter 11 bankruptcy proceedings pending in Texas. Among other things, the settlement terms provide for cash
and equivalent refunds totaling $320 million, of which SCE's allocated share is approximately $68 million.
The settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of one
of the Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim. The actual
value of the unsecured claim will be determined as part of the resolution of the Mirant parties'
bankruptcies. The Mirant settlement was approved by the FERC on April 13, 2005 and by the bankruptcy court
on April 15, 2005. In April and May 2005, SCE received its allocated $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
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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 was approved by the Enron bankruptcy
court on October 20, 2005, but remains subject to approval by the FERC. Effective August 24, 2005, the CPUC
approved the settlement by entering into an agreement incorporating its terms. The Enron settlement proceeds
will be refunded to ratepayers as described below.
On August 12, 2005, SCE, PG&E, SDG&E, several governmental entities and certain other parties agreed to
settlement terms with Reliant Energy, Inc. and a number of its affiliates (collectively Reliant). Among
other things, the settlement terms provide for Reliant to provide cash and cash equivalents having a total
value of at least $460 million, which would be in addition to the $65 million in refunds that Reliant was
already required to provide pursuant to prior FERC orders. SCE expects that its allocable share of the
entire settlement value of $525 million (including the amounts previously ordered by the FERC) will be
approximately $130 million. The settlement remains subject to FERC approval, which is anticipated in the
first quarter of 2006. Effective as of October 12, 2005, the CPUC approved the settlement by entering into
an agreement incorporating its terms. The Reliant settlement proceeds will be refunded to ratepayers as
described below.
On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an Energy Settlement
Memorandum Account (ESMA) for the purpose of recording the foregoing settlement proceeds (excluding the El
Paso settlement) from energy providers and allocating them in accordance with the terms of the October 2001
settlement agreement entered into by SCE and the CPUC which settled SCE's lawsuit against the CPUC. This
lawsuit sought full recovery of SCE's electricity procurement costs incurred during the energy crisis. The
resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will be
allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above
and a 10% shareholder incentive pursuant to the CPUC litigation settlement agreement. Remaining amounts for
each settlement are to be refunded to ratepayers through the ERRA mechanism. In the second quarter of 2005,
SCE recorded a $7 million increase to other nonoperating income as a shareholder incentive related to the
Mirant refund received during the second quarter of 2005.
Schedule Coordinator Tariff Dispute
SCE serves as an SC for Los Angeles Department of Water & Power (DWP) over the ISO-controlled grid. In
mid-2003, SCE filed a petition asking that the FERC accept a tariff that provides for a direct pass-through
of the FERC-authorized charges incurred by SCE on the DWP's behalf. The DWP protested SCE's filing. The DWP
asked the FERC to declare that SCE was obligated to serve as the DWP's SC without charge. In late 2003, the
FERC accepted the tariff, subject to refund. The FERC held that the proposed tariff has not been shown to be
just and reasonable.
In accordance with to the terms of the tariff, SCE issued several invoices for charges to the DWP. The DWP
has objected to all of the charges but has paid, under protest, approximately $18 million. The DWP has
protested specific charges totaling approximately $5 million based on its allegations that those specific
charges are improper for various reasons.
The FERC has not issued a final order on this issue. SCE could be required to refund all or part of the
amounts collected under the tariff. SCE continues to invoice the DWP. Monthly invoices have been averaging
approximately $1 million. SCE cannot predict with certainty the outcome of the FERC final order.
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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. In an August
25, 2005 decision, the CPUC approved the settlement agreement between SCE and the ORA which (1) allows the
authorized fire-related CEMA revenue requirement calculation to be based on approximately $8 million of
incremental operations and maintenance expenses and $20 million of incremental capital plant additions and
(2) allows SCE to continue to record in its fire-related 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 fire-related 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 fire-related CEMA account through a mechanism approved
in SCE's 2006 GRC.
Holding Company Proceeding and Order Instituting Rulemaking
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 "Regulatory Matters--Other Regulatory
Matters--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.
On October 27, 2005, the CPUC issued an order instituting rulemaking (OIR) to allow the CPUC to re-examine
the relationships of the major California energy utilities with their parent holding companies and
non-regulated affiliates. The OIR was issued in part in response to the recent repeal of the Public Utility
Holding Company Act of 1935.
By means of the OIR the CPUC will consider whether additional rules to supplement existing rules and
requirements governing relationships between the public utilities and their holding companies and
non-regulated affiliates should be adopted. Any additional rules will focus on whether (1) the public
utilities retain enough capital or access to capital to meet their customers' infrastructure needs and (2)
mitigation of potential conflicts between ratepayer interests and the interests of holding companies and
affiliates that could undermine the public utilities' ability to meet their public service obligations at the
lowest cost. The CPUC expects to issue proposed rules in January 2006, and a final decision is expected in
March 2006.
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System Reliability Incentive Mechanism
SCE's 2003 GRC decision provided for performance incentives or penalties for differences between SCE's actual
results and CPUC-authorized standards for system reliability measures beginning in 2004. In a March 30, 2005
advice letter, SCE reported a $2 million penalty and recorded an accrual in 2004 for its 2004 results under
the modified reliability mechanism. On April 28, 2005, the CPUC agreed to suspend its review of SCE's advice
letter for 2004 results until the CPUC's Consumer Protection and Safety Division has completed its
investigation regarding performance incentive rewards discussed in the 2004 year-ended MD&A. Based on
preliminary recorded data through September 2005 and a forecast of normal results through December 2005, SCE
projects it will incur a penalty of $26 million under the reliability performance mechanism for 2005. The
maximum penalty that could be assessed under the reliability performance mechanism is approximately $40
million. As a result, during the third quarter of 2005, SCE recorded an accrual of $26 million that is
reflected in the income statement caption "Other nonoperating deductions."
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. On October 27,
2005, the CPUC approved the settlement agreement which found it reasonable for SCE to recover approximately
$42 million of these claims which include all of SCE's outstanding claims, as well as future claims related
to SCE's pre-1998 energy efficiency programs (of which approximately $9 million has already been collected in
rates). The remaining portion of claims in the amount of $33 million will be recognized in the fourth
quarter of 2005. As a result of the decision, during the third quarter of 2005, SCE
recognized $14 million of incentives previously awarded for which revenue recognition was deferred pending
final resolution of these matters. The $14 million is reflected in the income statement caption "Other
nonoperating income." In addition, $4 million related to interest on the claims was reflected in the caption
"Interest and dividend income."
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
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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 $81 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 $115 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 $29 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 $55 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.
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 $11 million to $25 million. Recorded costs for the twelve
months ended September 30, 2005 were $11 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, resulted in a third quarter 2005 net earnings benefit for SCE of approximately $61 million,
including interest. This benefit was reflected in the income statement caption "Income tax."
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
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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 $280 million and $572 million for the three- and nine-month
periods ended September 30, 2005, respectively, compared to $259 million and $600 million for the same
periods in 2004. SCE's earnings reflect a positive tax item of $61 million related to a favorable tax
settlement (see "Other Developments--Federal Income Taxes) for both periods in 2005, as well as net positive
regulatory adjustments of $50 million and $172 million for the three- and nine-month periods ended September
30, 2004, respectively, primarily from the implementation of SCE's 2003 GRC decision. The increases for both
periods were due to higher net revenue for 2005 and a tax benefit from a new IRS regulation. The quarter
increase was partially offset by the expected timing difference related to the implementation of the 2003 GRC
decision in July 2004. The year-to-date increase was further increased by the favorable resolution of tax
issues.
Operating Revenue
SCE's retail sales represented approximately 85% and 83% of operating revenue for the three- and nine-month
periods ended September 30, 2005, respectively, compared to approximately 88% and 86% of operating revenue
for the three- and nine-month periods ended September 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.
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The following table sets forth the major changes in operating revenue:
Three-Month Period Nine-Month Period
Ended September 30, Ended September 30,
In millions 2005 vs. 2004 2005 vs. 2004
-----------------------------------------------------------------------------------------------------
Operating revenue
Rate changes (including unbilled) $ 316 $ 497
Sales volume changes (including unbilled) 190 352
Deferred revenue (200) (473)
Sales for resale 90 134
SCE's variable interest entities 20 129
Other (including intercompany transactions) 13 29
-----------------------------------------------------------------------------------------------------
Total $ 429 $ 668
-----------------------------------------------------------------------------------------------------
Total operating revenue increased by $429 million and $668 million for the three- and nine-month periods
ended September 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 increased revenue by approximately $295 million and
$235 million for the three- and nine-month periods ended September 30, 2005, respectively, and distribution
rates increased revenue by approximately $20 million and $260 million for the three- and nine-month periods
ended September 30, 2005, respectively. The change in deferred revenue reflects the deferral of
approximately $90 million and $290 million of revenue in the three- and nine-month periods ended September
30, 2005, respectively, resulting from balancing account overcollections, compared to the recognition of
approximately $110 million and $180 million of deferred revenue in the three- and nine-month periods ended
September 30, 2004, respectively. 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. 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 recognized as revenue by
SCE. These amounts were $534 million and $1.5 billion for the three- and nine-month periods ended September
30, 2005, respectively, compared to $693 million and $1.9 billion for the same periods in 2004.
Operating Expenses
Fuel Expense
SCE's fuel expense increased $42 million and $267 million for the three- and nine-month periods ended
September 30, 2005, as compared to the same periods 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 was
approximately $225 million and $624 million for the three- and nine-month periods ended September 30, 2005,
respectively, compared to approximately $187 million and $375 million for the comparable periods in 2004.
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Purchased-Power Expense
Purchased-power expense decreased $413 million and $389 million for the three- and nine-month periods ended
September 30, 2005, respectively, as compared to the same periods in 2004. The decreases were mainly due to
net realized and unrealized gains on economic hedging transactions and lower ISO-related purchases, partially
offset by higher firm energy and QF purchases. Net realized and unrealized gains related to economic hedging
transactions, resulting from increased hedging activities, were approximately $585 million and $530 million
for the three- and nine-month periods ended September 30, 2005, respectively, as compared to net realized and
unrealized losses of approximately $75 million for both periods in 2004. ISO-related purchases decreased
approximately $50 million and $95 million for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to the same periods in 2004. These decreases were partially offset by higher firm
energy expenses of approximately $315 million and $490 million for the three- and nine-month periods ended
September 30, 2005, respectively, as compared to the same periods in 2004, resulting from an increase in the
number of bilateral contracts in 2005, as compared to 2004, and higher QF-related purchases of approximately
$30 million and $70 million for the three- and nine-month periods ended September 30, 2005, respectively, as
compared to the same periods in 2004. The nine-month period decrease also reflects approximately $130
million of energy settlement refunds received in 2005 (see "Regulatory Matters--Transmission and
Distribution--Wholesale Electricity and Natural Gas Markets"), as compared to approximately $65 million
received during the same period in 2004, as well as a reduction of $205 million 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 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 $800 million and $875 million for the three- and
nine-month periods ended September 30, 2005, respectively, as compared to the same periods in 2004. The
increases mainly result from higher net unrealized gains on economic hedging transactions, net
overcollections related to balancing accounts, lower CEMA-related costs, and GRC regulatory adjustments. The
quarter and year-to-date increases reflect higher net unrealized gains of approximately $575 million and
$525 million for the three- and nine-month periods ended September 30, 2005, respectively, related to economic
hedging transactions (mentioned above in purchased-power expense) that, if realized, would be refunded to
ratepayers; net overcollections of purchased power, fuel, and operating and maintenance expenses of
approximately $180 million and $45 million for the three- and nine-month periods ended September 30, 2005
which were deferred in balancing accounts for future recovery; lower costs incurred and deferred
(approximately $25 million and $85 million for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to the same periods in 2004) associated with CEMA-related costs; and the net effect
of regulatory adjustments related to the implementation of SCE's 2003 GRC decision in the amount of $180
million recorded in the second quarter of 2004 and approximately $15 million recorded in the third quarter of
2004. 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, 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.
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Other Operation and Maintenance Expense
SCE's other operation and maintenance expense increased $63 million and $71 million for the three- and
nine-month periods ended September 30, 2005, as compared to the same periods in 2004. The increases were
mainly due to an increase in reliability costs, demand-side management and energy efficiency costs, and
benefit-related costs, partially offset by lower CEMA-related costs and generation-related costs. The
quarter and year-to-date increases reflect an increase in reliability costs of approximately $35 million and
$75 million for the three- and nine-month periods ended September 30, 2005, respectively, as compared to the
same periods in 2004, 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); an increase in
demand side management and energy efficiency costs of approximately $25 million and $50 million for the
three- and nine-month periods ended September 30, 2005 in 2005, respectively (which are recovered through
regulatory mechanisms approved by the CPUC); and higher benefit-related costs of approximately $40 million
and $50 million for the three- and nine-month periods ended September 30, 2005, respectively, resulting from
an increase in heath care costs and value of performance shares. The quarter and year-to-date increases were
partially offset by lower CEMA-related costs of approximately $25 million and $85 million for the three- and
nine-month periods, respectively, compared to the same periods in 2004; and a decrease in generation-related
expenses of approximately $10 million and $65 million, for the three- and nine-month periods ended September
30, 2005, respectively, as compared to 2004, resulting from lower outage and refueling costs (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). The year-to-date variance was also due to an increase of approximately $30 million in
O&M expenses as a result of the consolidation of SCE's variable interest entities, as well as higher worker's
compensation accruals of approximately $10 million in 2005 compared to 2004.
Depreciation, decommissioning and amortization
SCE's depreciation, decommissioning and amortization increased $46 million and $60 million for the three- and
nine-month periods ended September 30, 2005, as compared to the same periods in 2004, mainly due to a
decrease in depreciation expense recorded in the third quarter of 2004 as a result of the implementation of
the 2003 GRC related to the Palo Verde incremental cost incentive pricing rate-making mechanism, as well as
depreciation expense associated with additions to transmission and distribution assets.
Other Income and Deductions
Interest and Dividend Income
SCE's interest and dividend income increased $10 million and $21 million for the three- and nine-month
periods ended September 30, 2005, as compared to the same period in 2004, mainly due to interest income
related to balancing account undercollections, as well as $4 million related to interest on demand-side
management and energy efficiency performance incentive claims resulting from a CPUC-approved settlement. See
"Regulatory Matters--Other Regulatory Matters--Demand-Side Management and Energy Efficiency Performance
Incentive Mechanisms" for further discussion.
Other Nonoperating Income
SCE's other nonoperating income for the three- and nine-month periods ended September 30, 2005 includes a $14
million incentive related to demand-side management and energy efficiency performance for the portion of the
incentives previously collected in rates but which were deferred. See "Regulatory Matters--Other Regulatory
Matters--Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms" for further discussion
of this matter. In addition, the quarter and year-to-date amounts include approximately $10 million and $20
million for the three- and nine-months ended September 30, 2005, respectively, related to an allowance for
funds used during construction (AFUDC),
Page 47
which represents the estimated cost of equity funds that finance utility-plant construction, compared to
approximately $5 million and $15 million in the same periods in 2004. The nine-month period ended September
30, 2005, also 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"), as well as 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 nine-month period ended
September 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.
Other Nonoperating Deductions
Other nonoperating deductions increased $29 million and $27 million for the three- and nine-month periods
ended September 30, 2005, as compared to the same periods in 2004, mainly due to an accrual of $26 million in
system reliability penalties. See "Regulatory Matters--Other Regulatory Matters--System Reliability Incentive
Mechanism" for further discussion of this matter.
Income Taxes
SCE's effective tax rates were 16% and 24% for the three- and nine-month periods ended September 30, 2005,
respectively, as compared to 40% for both the same periods in 2004. The decreased effective tax rates
resulted primarily from recording a $61 million benefit, including $45 million of interest income, in the
third quarter of 2005 related to a settlement reached with the IRS on tax issues and pending affirmative
claims relating to Edison International's 1991 - 1993 tax years. See "Other Developments--Federal Income
Taxes" for further discussion of this matter. Additional decreases to the effective rates resulted from
reductions made to accrued tax liabilities in 2005 to reflect progress made in settlement negotiations
related to tax audits other than the 1991 - 1993 tax years, changes in property-related flow-through items
and adjustments made to tax balances in 2005.
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 approximately $2.0 billion for the nine months ended September
30, 2005, and $1.9 billion for the comparable period in 2004. The 2005 change in cash provided by operating
activities from continuing operations was mainly due an increase in short-term regulatory balancing account
collections as well as the timing of cash receipts and disbursements related to working capital items.
Cash Flows from Financing Activities
Net cash used by financing activities was $353 million for the nine months ended September 30, 2005, compared
to net cash provided by financing activities of $374 million for the nine months ended September 30, 2004.
Cash used by financing activities from continuing operations in 2005 mainly consisted of long-term and
short-term debt payments.
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SCE's first quarter 2005 financing activity included the issuance of $650 million of first and refunding
mortgage bonds. The issuance included $400 million of 5% bonds due in 2016 and $250 million of 5.55% bonds
due in 2036. The proceeds were used to redeem the remaining $50,000 of its 8% first and refunding mortgage
bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding mortgage
bonds due February 2007 (Series 2003B). SCE's second quarter financing activity included the issuance of
$350 million of its 5.35% first and refunding mortgage bond due in 2035 (Series 2005E). A portion of the
proceeds was used to redeem $316 million of its 8% first and refunding mortgage bonds due in 2007 (Series
2003B). In addition, in April 2005, SCE issued 4,000,000 shares of Series A preference stock
(non-cumulative, $100 liquidation value) and received net proceeds of approximately $394 million.
Approximately $81 million of the proceeds was used to redeem all the outstanding shares of its $100
cumulative preferred stock, 7.23% Series, and approximately $64 million of the proceeds was used to redeem
all the outstanding shares of its $100 cumulative preferred stock, 6.05% Series. SCE's third quarter 2005
financing activity included the issuance of 2,000,000 shares of Series B preference stock (non-cumulative,
$100 liquidation value) and received net proceeds of approximately $197 million. SCE's financing activity in
2005 also included a dividend payment of $214 million to Edison International.
SCE financing activities include 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 during the first quarter of 2004. The
proceeds from these issuances were used to redeem $300 million of 7.25% first and refunding mortgage bonds
due March 2026, $225 million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9%
first and refunding mortgage bonds due October 2018, and $100 million of junior subordinated deferrable
interest debentures due June 2044. In addition, during the first quarter of 2004, SCE paid the $200 million
outstanding balance of its credit facility, as well as remarketed approximately $550 million of
pollution-control bonds with varying maturity dates ranging from 2008 to 2040. Approximately $354 million of
these pollution-control bonds had been held by SCE since 2001 and the remaining $196 million were purchased
and reoffered in 2004. In March 2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds
due in 2015 and $350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the
proceeds from the March 2004 first and refunding mortgage bond issuances were used to fund the acquisition
and construction of the Mountainview project. During the third quarter, SCE paid $125 million of 5.875%
bonds due in September 2004. Financing activities in 2004 also included dividend payments of $595 million to
Edison International.
Cash Flows from Investing Activities
Net cash used by investing activities was $1.3 billion for the nine months ended September 30, 2005, compared
to $1.5 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 nine-month period ended September 30, 2005 reflect $1.3 billion in capital
expenditures at SCE, primarily for transmission and distribution assets, including approximately $43 million
for nuclear fuel acquisitions.
Investing activities for the nine-month period ended September 30, 2004 reflect, $1.1 billion in capital
expenditures at SCE, primarily for transmission and distribution assets, including approximately $59 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 FASB issued an interpretation related to accounting for conditional asset retirement
obligations (AROs). This Interpretation clarifies that an entity is required to recognize a liability for
the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty
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exists about the timing and/or method of settlement. This Interpretation is effective December 31, 2005.
Thus far, SCE has identified conditional AROs related to: treated wood poles, hazardous materials such as
mercury and polychlorinated biphenyls-containing equipment; and asbestos removal costs at buildings,
operating stations and retired units. Additional assessment is necessary to value these AROs. However,
since SCE follows accounting principles for rate-regulated enterprises and receives recovery of these costs
through rates, implementation of this Interpretation at SCE will not affect earnings.
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 related to stock options granted is an increase of $1 million and $4 million in
expense for the three- and nine-month periods ended September 30, 2005, respectively. SCE is assessing the
impact of this accounting standard on its performance shares.
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. In October 2005, the IRS issued proposed regulations
for this tax deduction. 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 ended 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.
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 $158 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 $31 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 50
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 51
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
SCE is a party to certain lawsuits and legal proceedings, which are described in Part I, Item 3 of SCE's
Annual Report on Form 10-K for the year ended December 31, 2004. The following is a description of material
developments during the period covered by this Quarterly Report and should be read in conjunction with the
Annual Report referenced above. There were no significant developments with respect to litigation required
to be disclosed under Part II, Item I of Form 10-Q of SCE during the quarterly period ended September 30,
2005, except as follows:
Navajo Nation Litigation
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 SCE's Annual Report on Form 10-K for the year ended December 31, 2004, and in Part II, Item 1 of SCE's
Quarterly Report on Form 10-Q for the period ended March 31, 2005, and in SCE's Quarterly Report on Form 10-Q
for the period ended June 30, 2005.
Department of the Army, Los Angeles District, Corps of Engineers/Notice of Violation of Clean Water Act
In December 2004, the US Army Corps of Engineers (Corps) sent SCE a Notice of Violation (Notice), alleging
that SCE or its contractors had discharged fill material into wetlands adjacent to the Santa Ana River
(River), in the City of Huntington Beach, CA (City). Under Sections 301 and 404 of the Clean Water Act, the
discharge of fill material into waters of the United States is unlawful unless first permitted by the Corps
pursuant to Section 404 of the Clean Water Act.
The Notice provided a general description of the area in question but did not specify the location of the
violation. Following discussions and correspondence with the Corps, it was determined that the Corps was
concerned about the actions of a certain licensee of SCE on an SCE-owned transmission right-of-way corridor
located adjacent to the River. SCE's licensee, or its predecessor-in-interest, had obtained from the City a
Conditional Use Permit (CUP) to locate landscape nursery operations within the right-of-way corridor. The
CUP required the licensee to perform certain drainage and grading improvements to the property before
locating nursery operations on site. During the course of the grading work, the licensee brought additional
soil onto SCE's property for use as fill material.
Pursuant to the Notice, potential penalties for violation of Section 404 of the Clean Water Act include a
maximum criminal fine of $50,000 per day and imprisonment for up to three years, and a maximum civil penalty
of $25,000 per day of violation. To date, however, the Corps has not proposed to impose any specific fine or
penalty on SCE with respect to the subject matter of the Notice.
In the process of investigating the matter, the Corps has requested that SCE perform a wetlands delineation
study of the property to determine whether the property in question qualifies as a wetland area subject to
Corps jurisdiction. SCE has hired a consulting group to perform the wetlands delineation study.
Page 52
Item 6. Exhibits
Southern California Edison Company
3.1 Certificate of Amendment and Restated Articles of Incorporation of Southern California Edison
Company, effective June 1, 1993 (File No. 1-02313, filed as Exhibit 3.1 to Southern
California Edison Company's Form 10-K for the year ended December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of Southern California Edison
Company, effective August 21, 1997 (File No. 1-02313, filed as Exhibit 3.1 to Southern
California Edison Company's Form 10-Q for the quarter ended September 30, 1997)*
3.3 Certificate of Amendment to the Restated Articles of Incorporation of Southern California
Edison Company, effective January 12, 2005 (File No. 1-02313, filed as Exhibit 3 to Southern
California Edison Company's Form 8-K dated January 12, 2005, and filed January 15, 2005)*
3.4 Certificate of Determination of Preferences of the Series A Preference Stock, effective April
21, 2005 (File No. 1-02313, filed as Exhibit 4 to Southern California Edison Company's Form
8-K dated April 20, 2005, and filed April 26, 2005)*
3.5 Certificate of Determination of Preferences of the Series B Preference Stock effective
September 14, 2005 (File No. 1-02313, filed as Exhibit 4 to Southern California Edison
Company's Form 8-K dated September 14, 2005, and filed September 16, 2005)*
3.6 Bylaws of Southern California Edison Company, as Amended to and including October 20, 2005
(File No. 1-02313, filed as Exhibit 3.1 to Southern California Edison Company's Form 8-K
dated October 20, 2005, and filed October 24, 2005)*
10.1 Retirement Agreement, dated as of August 25, 2005, between Southern California Edison Company
and Robert Foster (File No. 1-02313, filed as Exhibit 10.1 to Southern California Edison
Company's Form 8-K dated August 25, 2005, and filed August 26, 2005)*
10.2 Consulting Agreement, dated as of August 25, 2005, between Southern California Edison Company
and Robert Foster (File No. 1-02313, filed as Exhibit 10.2 to Southern California Edison
Company's Form 8-K dated August 25, 2005, and filed on August 26, 2005)*
10.3 Legal Fees Reimbursement, dated September 2005, between Southern California Edison Company
and Robert Foster
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 53
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: November 4, 2005
