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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, 2001
OR
/ / 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
(Address of principal 91770
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 (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 the number of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:
Class Outstanding at November 9, 2001
----------------------------------------------------------- ---------------------------------------------------
Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 1
Consolidated Statements of Income (Loss) - Three, Nine and
Twelve Months Ended September 30, 2001, and 2000 2
Consolidated Statements of Comprehensive Income (Loss) -
Three, Nine and Twelve Months Ended September 30, 2001, and 2000 2
Consolidated Balance Sheets - September 30, 2001,
December 31, 2000, and September 30, 2000 3
Consolidated Statements of Cash Flows -
Three, Nine and Twelve Months Ended
September 30, 2001, and 2000 5
Consolidated Statements of Common Shareholder's
Equity - Three, Nine and Twelve Months Ended
September 30, 2001, and 2000 6
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 39
Part II. Other Information:
Item 1. Legal Proceedings 59
Item 6. Exhibits and Reports on Form 8-K 61
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
Report of Independent Public Accountants
To Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern California Edison Company (SCE, a
California corporation) and its subsidiaries as of September 30, 2001, December 31, 2000, and September 30, 2000,
and the related consolidated statements of income (loss), comprehensive income (loss), cash flows and changes in
common shareholder's equity for each of the three-, nine- and twelve-month periods ended September 30, 2001, and
2000. These financial statements are the responsibility of SCE's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of SCE and its subsidiaries as of September 30, 2001, December 31, 2000, and September 30,
2000, and the results of their operations and their cash flows for each of the three-, nine- and twelve-month
periods ended September 30, 2001, and 2000, in conformity with accounting principles generally accepted in the
United States.
The accompanying financial statements have been prepared assuming that SCE will continue as a going concern. As
discussed in Notes 2 and 3 to the consolidated financial statements, the recent energy crisis in California has
resulted in uncertainty for SCE associated with its ability to collect certain costs through the regulatory
process and has resulted in legal and regulatory uncertainties which have adversely impacted SCE's liquidity.
These issues raise substantial doubt about SCE's ability to continue as a going concern. Management's plans in
regard to these matters are also described in Notes 2 and 3. The financial statements do not include any
adjustments relating to the recoverability and classification of asset carrying amounts or the amount and
classification of liabilities that might result should SCE be unable to continue as a going concern.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 8, 2001
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
In millions
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
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2001 2000 2001 2000 2001 2000
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Operating revenue $ 2,726 $ 2,432 $ 5,830 $ 6,115 $ 7,585 $ 7,942
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Fuel 57 57 154 139 212 198
Purchased power 759 1,915 3,290 3,103 4,872 3,897
Provisions for regulatory adjustment clauses - net (5) (861) (124) (856) 3,033 (1,057)
Other operation and maintenance 432 430 1,293 1,295 1,771 1,719
Depreciation, decommissioning and amortization 161 415 479 1,162 789 1,532
Property and other taxes 28 29 86 98 114 123
Net gain on sale of utility plant -- -- (9) (7) (27) (7)
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Total operating expenses 1,432 1,985 5,169 4,934 10,764 6,405
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Operating income (loss) 1,294 447 661 1,181 (3,179) 1,537
Interest and dividend income 25 45 76 89 159 107
Other nonoperating income 6 6 28 79 67 117
Interest expense - net of amounts capitalized (221) (136) (581) (392) (761) (512)
Other nonoperating deductions (2) (15) (18) (74) (54) (111)
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Income (loss) before taxes 1,102 347 166 883 (3,768) 1,138
Income tax expense (benefit) 445 169 68 426 (1,380) 535
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Net income (loss) 657 178 98 457 (2,388) 603
Dividends on preferred stock 6 6 17 16 22 21
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Net income (loss) available for common stock $ 651 $ 172 $ 81 $ 441 $ (2,410) $ 582
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
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2001 200019991999 2001 2000 2001 2000
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Net income (loss) $ 657 $ 178 $ 98 $ 457 $ (2,388) $ 603
Other comprehensive income, net of tax:
Unrealized gain (loss) on securities - net -- (2) -- 3 -- 6
Cumulative effect of change in
accounting for derivatives -- -- 397 -- 397 --
Unrealized loss on cash flow hedges 1 -- (420) -- (420) --
Reclassification adjustment for gains
included in net income (loss) -- -- -- (24) -- (24)
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Comprehensive income (loss) $ 658 $ 176 $ 75 $ 436 $ (2,411) $ 585
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The accompanying notes are an integral part of these financial statements.
Page 2
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In millions
September 30, December 31, September 30,
2001 2000 2000
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ASSETS
Cash and equivalents $ 2,775 $ 583 $ 50
Receivables, less allowances of $30, $23 and $23
for uncollectible accounts at respective dates 1,353 919 682
Accrued unbilled revenue 568 377 553
Fuel inventory 12 12 21
Materials and supplies, at average cost 140 132 131
Accumulated deferred income taxes - net 593 545 546
Prepayments and other current assets 196 124 160
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Total current assets 5,637 2,692 2,143
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Nonutility property - less accumulated provision for
depreciation of $15, $11 and $8 at respective dates 142 102 102
Nuclear decommissioning trusts 2,268 2,505 2,542
Other investments 112 90 336
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Total investments and other assets 2,522 2,697 2,980
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Utility plant, at original cost:
Transmission and distribution 13,453 13,129 12,912
Generation 1,725 1,745 1,723
Accumulated provision for depreciation and decommissioning (7,852) (7,834) (7,759)
Construction work in progress 592 636 675
Nuclear fuel, at amortized cost 129 143 127
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Total utility plant 8,047 7,819 7,678
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Regulatory assets - net 2,874 2,390 6,669
Other deferred charges 513 368 371
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Total deferred charges 3,387 2,758 7,040
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Total assets $ 19,593 $ 15,966 $ 19,841
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The accompanying notes are an integral part of these financial statements.
Page 3
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In millions, except share amounts
September 30, December 31, September 30,
2001 2000 2000
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LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ 2,131 $ 1,451 $ 1,276
Long-term debt classified as due within one year 2,797 646 647
Preferred stock to be redeemed within one year 105 -- --
Accounts payable 3,315 1,055 885
Accrued taxes 713 536 574
Regulatory liabilities - net 136 195 1,005
Other current liabilities 2,000 1,502 1,800
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Total current liabilities 11,197 5,385 6,187
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Long-term debt 3,166 5,631 4,807
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Accumulated deferred income taxes - net 2,234 2,009 3,360
Accumulated deferred investment tax credits 155 164 175
Customer advances and other deferred credits 801 755 771
Power-purchase contracts 384 467 490
Accumulated provision for pensions and benefits 439 296 293
Other long-term liabilities 97 94 101
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Total deferred credits and other liabilities 4,110 3,785 5,190
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Commitments and contingencies
(Notes 1, 2, 3, 11 and 12)
Preferred stock:
Not subject to mandatory redemption 129 129 129
Subject to mandatory redemption 151 256 256
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Total preferred stock 280 385 385
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Common stock (434,888,104 shares
outstanding at each date) 2,168 2,168 2,168
Additional paid-in capital 335 334 334
Accumulated other comprehensive income (loss) (23) -- --
Retained earnings (deficit) (1,640) (1,722) 770
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Total common shareholder's equity 840 780 3,272
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Total liabilities and shareholder's equity $ 19,593 $ 15,966 $ 19,841
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The accompanying notes are an integral part of these financial statements.
Page 4
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In millions
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
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2001 2000 2001 2000 2001 2000
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Cash flows from operating activities:
Net income (loss) $ 657 $ 178 $ 98 $ 457 $ (2,388) $ 603
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 161 415 479 1,162 789 1,532
Other amortization 24 25 60 75 82 101
Deferred income taxes and investment tax credits 123 233 (35) 125 (1,087) 317
Regulatory assets - long-term - net (135) (1,451) (388) (1,994) 3,365 (2,459)
Net gain on sale of marketable securities -- -- (41) -- (41)
Other assets (8) (132) (93) (206) 158 (233)
Other liabilities (15) (1) 60 30 17 (52)
Changes in working capital:
Receivables and accrued unbilled revenue (488) (105) (620) (222) (681) 64
Regulatory liabilities - short-term - net (61) 510 (59) 907 (869) 1,110
Fuel inventory, materials and supplies (4) 14 (9) 21 (1) 19
Prepayments and other current assets (84) (110) (71) (49) (35) (31)
Accrued interest and taxes 470 (55) 258 58 248 (432)
Accounts payable and other current liabilities 337 496 2,662 652 2,598 572
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Net cash provided by operating activities 977 17 2,342 975 2,196 1,070
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Cash flows from financing activities:
Long-term debt issued -- 218 -- 466 1,293 466
Long-term debt repaid -- -- -- (325) (200) (325)
Bonds repurchased and funds held in trust -- (219) (130) (219) (350) (219)
Rate reduction notes repaid (61) (62) (174) (175) (245) (243)
Nuclear fuel financing - net (4) 15 (14) (6) 1 (21)
Short-term debt financing - net 10 421 680 480 855 671
Dividends paid -- (97) (1) (298) (98) (420)
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Net cash provided (used) by financing activities (55) 276 361 (77) 1,256 (91)
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Cash flows from investing activities:
Additions to property and plant (172) (285) (525) (807) (814) (1,074)
Funding of nuclear decommissioning trusts (18) (64) 3 (123) 57 (144)
Proceeds from sales of marketable securities -- -- -- 41 -- 41
Sales of investments in other assets -- -- 11 15 30 20
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Net cash used by investing activities (190) (349) (511) (874) (727) (1,157)
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Net increase (decrease) in cash and equivalents 732 (56) 2,192 24 2,725 (178)
Cash and equivalents, beginning of period 2,043 106 583 26 50 228
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Cash and equivalents, end of period $ 2,775 $ 50 $ 2,775 $ 50 $ 2,775 $ 50
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Cash payments for interest and taxes:
Interest - net of amounts capitalized $ 107 $ 92 $ 310 $ 237 $ 376 $ 308
Taxes -- 90 -- 293 13 633
The accompanying notes are an integral part of these financial statements.
Page 5
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
In millions
Accumulated Total
Additional Other Retained Common
Common Paid-in Comprehensive Earnings Shareholder's
Stock Capital Income (Loss) (Deficit) Equity
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Balance at June 30, 2000 $ 2,168 $ 334 $ 2 $ 690 $ 3,194
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Net income 178 178
Unrealized gain on securities
Tax effect (2) (2)
Dividends declared on common stock (92) (92)
Dividends declared on preferred stock (6) (6)
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Balance at September 30, 2000 $ 2,168 $ 334 $ -- $ 770 $ 3,272
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Balance at June 30, 2001 $ 2,168 $ 334 $ (24) $ (2,291) $ 187
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Net income 657 657
Unrealized loss on cash flow hedges 1 1
Dividends accrued on preferred stock (6) (6)
Capital stock expense and other 1 1
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Balance at September 30, 2001 $ 2,168 $ 335 $ (23) $ (1,640) $ 840
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Balance at December 31, 1999 $ 2,168 $ 335 $ 22 $ 608 $ 3,133
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Net income 457 457
Unrealized gain on securities 8 8
Tax effect (5) (5)
Reclassified adjustment for gains
included in net income (41) (41)
Tax effect 16 16
Dividends declared on common stock (279) (279)
Dividends declared on preferred stock (16) (16)
Stock option appreciation (1) (1)
Capital stock expense and other (1) 1 --
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Balance at September 30, 2000 $ 2,168 $ 334 $ -- $ 770 $ 3,272
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Balance at December 31, 2000 $ 2,168 $ 334 $ -- $ (1,722) $ 780
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Net income 98 98
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (420) (420)
Dividends accrued on preferred stock (17) (17)
Capital stock expense and other 1 1 2
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Balance at September 30, 2001 $ 2,168 $ 335 $ (23) $ (1,640) $ 840
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The accompanying notes are an integral part of these financial statements.
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
In millions
Accumulated Total
Additional Other Retained Common
Common Paid-in Comprehensive Earnings Shareholder's
Stock Capital Income (Loss) (Deficit) Equity
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Balance at September 30, 1999 $ 2,168 $ 335 $ 18 $ 585 $ 3,106
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Net income 603 603
Unrealized gain on securities 10 10
Tax effect (4) (4)
Reclassified adjustment for gain
included in net income (41) (41)
Tax effect 17 17
Dividends declared on common stock (395) (395)
Dividends declared on preferred stock (21) (21)
Stock option appreciation (2) (2)
Capital stock expense and other (1) (1)
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Balance at September 30, 2000 $ 2,168 $ 334 $ -- $ 770 $ 3,272
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Net income (loss) (2,388) (2,388)
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (420) (420)
Dividends accrued on preferred stock (22) (22)
Capital stock expense and other 1 1
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Balance at September 30, 2001 $ 2,168 $ 335 $ (23) $ (1,640) $ 840
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Authorized common stock is 560 million shares with no par value.
The accompanying notes are an integral part of these financial statements.
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Nature of Operations
Southern California Edison Company (SCE) is a rate-regulated electric utility that supplies electric energy to a
50,000 square-mile area of central, coastal and Southern California. SCE also produces electricity. SCE
operates in a highly regulated environment and has an exclusive franchise within its service territory. SCE has
an obligation to deliver electric service to its customers and regulatory authorities have an obligation to
provide just and reasonable rates. In the mid-1990s, state lawmakers and the California Public Utilities
Commission (CPUC) initiated an electric utility industry restructuring process. SCE was directed by the CPUC to
divest the bulk of its generation portfolio. Today, independent power companies own the divested generating
plants. See Notes 2 and 3 for a further discussion of regulatory changes in the electric utility industry.
Basis of Presentation
The consolidated financial statements include SCE and its subsidiaries. Intercompany transactions have been
eliminated. Certain prior-period amounts were reclassified to conform to the September 30, 2001, financial
statement presentation.
SCE's accounting policies conform with accounting principles generally accepted in the United States, including
the accounting principles for rate-regulated enterprises, which reflect the rate-making policies of the CPUC and
the Federal Energy Regulatory Commission (FERC). Since 1997, as a result of industry restructuring legislation
enacted by the State of California and related changes in the rate-recovery of generation-related assets, SCE has
used accounting principles applicable to enterprises in general for its investment in generation facilities.
Financial statements prepared in compliance with accounting principles generally accepted in the United States
require management to make estimates and assumptions that affect the amounts reported in the financial statements
and disclosure of contingencies. Actual results could differ from those estimates. Certain significant
estimates related to liquidity, regulatory matters, decommissioning and contingencies are further discussed in
Notes 2, 3, 11 and 12 to the Consolidated Financial Statements, respectively.
SCE's outstanding common stock is owned entirely by its parent company, Edison International.
Regulatory Balancing Accounts
During the four-year rate freeze period, recovery of generation-related transition costs has been tracked through
the transition cost balancing account (TCBA) mechanism. The gains resulting from the sale of 12 of SCE's
generating plants during 1998 have been credited to the TCBA.
The coal and hydroelectric generation balancing accounts tracked the differences between market revenue from coal
and hydroelectric generation and the plants' operating costs after April 1, 1998. Overcollections were credited
to the TCBA in 1998 and 1999, in accordance with a 1997 CPUC decision. Due to a January 2001 interim CPUC
decision, the balance at year-end 2000 was not credited to the TCBA, pending further testimony and evidence on
the implications of crediting the overcollections to the transition revenue account (TRA) rather than the TCBA.
The TRA is a CPUC-authorized regulatory asset in which SCE recorded the difference between revenue received from
customers through currently frozen rates and the costs of providing service to customers, including power
procurement costs. On March 27, 2001, the CPUC issued a decision stating, among other things, that the rate
freeze had not ended, and the TCBA mechanism was to remain in place. However, the decision required SCE to
recalculate the TCBA retroactive to January 1, 1998, the beginning of the rate freeze period. The new calculation
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
required the coal and hydroelectric balancing accounting overcollections (which amounted to $1.5 billion as of
December 31, 2000) to be transferred monthly to the TRA, rather than annually to the TCBA. In addition, it
required the TRA to be transferred to the TCBA on a monthly basis. Previous rules had called only for
overcollections to be transferred to the TCBA monthly, while undercollections were to remain in the TRA until
they were recovered from future overcollections or the end of the rate freeze, whichever came first. Based on
the new rules, the $4.5 billion TRA undercollection as of December 31, 2000, and the coal and hydroelectric
balancing account overcollections, were reclassified to the TCBA, and the TCBA balance as of December 31, 2000,
was determined to be a $2.9 billion undercollection.
Because the regulatory and legislative actions that made recovery of the TCBA probable were not taken, (as
discussed in Note 3), SCE was unable to conclude as of December 31, 2000, that the recalculated TCBA net
undercollection was probable of recovery through the rate-making process. As a result, the TCBA undercollection
was charged to earnings as of that date. An additional $1.1 billion in TCBA undercollections was charged to
earnings during 2001.
An October 2001 settlement between the CPUC and SCE calls for the end of the TCBA mechanism as of August 31,
2001, and continuation of the rate freeze (including surcharges) until the earlier of December 31, 2003, or the
date SCE recovers its previously incurred (undercollected) power procurement costs. During fourth quarter 2001,
it is expected that the TCBA will become inactive retroactive to September 1, 2001, and the procurement-related
obligations account (PROACT) will be created in accordance with the October 2001 settlement agreement with the
CPUC. During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has
recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will apply
to the PROACT the difference between SCE's revenue from retail electric rates (including surcharges) and the
costs that SCE is authorized by the CPUC to recover in retail electric rates. If SCE has not recovered the
entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an additional two years.
Balancing account undercollections and overcollections accrue interest. Income tax effects on all balancing
account changes are deferred.
Regulatory Assets and Liabilities
In accordance with accounting principles for rate-regulated enterprises, SCE records regulatory assets, which
represent probable future revenue associated with certain costs that will be recovered from customers through the
rate-making process, and regulatory liabilities, which represent probable future reductions in revenue associated
with amounts that are to be credited to customers through the rate-making process. SCE's discontinuance of the
application of accounting principles for rate-regulated enterprises to its generation assets in 1997 did not
result in a write-off of its generation-related regulatory assets at that time since the CPUC had approved
recovery of these assets through the TCBA mechanism.
There are many factors that affect SCE's ability to recover its regulatory assets. SCE assessed the probability
of recovery of its generation-related regulatory assets in light of the CPUC's March 27, 2001, decisions
(discussed in Note 3), including the retroactive transfer of balances from SCE's TRA to the TCBA and related
changes. These decisions and other regulatory and legislative actions did not meet SCE's prior expectation that
the CPUC would provide adequate cost recovery mechanisms. SCE was unable to conclude that its generation-related
regulatory assets were probable of recovery through the rate-making process as of December 31, 2000. Therefore,
in accordance with accounting rules, SCE recorded a $2.5 billion after-tax charge to earnings at that time, to
write off the TCBA and other regulatory assets (see below).
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition to the TCBA, generation-related regulatory assets totaling $1.3 billion (including unamortized
nuclear investment, flow-through taxes, unamortized loss on sale of plant, purchased-power settlements and other
regulatory assets) were written off as of December 31, 2000.
Regulatory assets and liabilities included in the consolidated balance sheets are:
September 30, December 31, September 30,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Generation-related:
Unamortized nuclear investment - net $ -- $ -- $ 783
Flow-through taxes -- -- 221
Unamortized loss on sale of plant -- -- 76
Purchased-power settlements -- -- 458
Regulatory balancing accounts and other -- -- (414)
---------------------------------------------------------------------------------------------------------------
Subtotal -- -- 1,124
---------------------------------------------------------------------------------------------------------------
Rate reduction notes - transition cost deferral 1,366 1,090 1,001
---------------------------------------------------------------------------------------------------------------
Transition revenue account -- -- 2,358
---------------------------------------------------------------------------------------------------------------
Other:
Flow-through taxes 1,075 874 960
Unamortized loss on reacquired debt 258 273 277
Environmental remediation 60 52 52
Regulatory balancing accounts and other (21) (94) (108)
---------------------------------------------------------------------------------------------------------------
Subtotal 1,372 1,105 1,181
---------------------------------------------------------------------------------------------------------------
Total $ 2,738 $ 2,195 $ 5,664
---------------------------------------------------------------------------------------------------------------
The regulatory asset related to the rate reduction notes will be recovered over the terms of those notes. The
other regulatory assets and liabilities are being recovered through other components of the unbundled rates.
The unamortized nuclear investment regulatory asset was created during the second quarter of 1998. SCE reduced
its remaining nuclear plant investment by $2.6 billion (as of June 30, 1998) and recorded a regulatory asset on
its balance sheet for the same amount in accordance with asset impairment accounting standards. For this
impairment assessment, the fair value of the investment was calculated by discounting expected future net cash
flows. The reclassification had no effect on SCE's 1998 results of operations.
In accordance with the CPUC settlement agreement, in fourth quarter 2001, it is expected that the CPUC will issue
implementing decisions or orders allowing SCE to establish the PROACT regulatory asset for previously incurred
energy procurement costs, retroactive to August 31, 2001.
Nuclear
SCE had been recovering its investments in San Onofre Nuclear Generating Station Units 2 and 3 and Palo Verde
Nuclear Generating Station on an accelerated basis, as authorized by the CPUC. The accelerated recovery was to
continue through December 2001, earning a 7.35% fixed rate of return on investment. San Onofre's operating
costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were
recovered through an incentive pricing plan that allows SCE to receive about 4(cent)per kilowatt-hour through 2003.
Any differences between these costs and the incentive price would flow through to the shareholders. Palo Verde's
accelerated plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing costs,
and incremental capital
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
expenditures, were subject to balancing account treatment through December 31, 2001. The San Onofre and Palo
Verde rate recovery plans and the Palo Verde balancing account were part of the TCBA.
The nuclear rate-making plans and the TCBA mechanism were to continue for rate-making purposes at least through
2001 for Palo Verde operating costs and through 2003 for the San Onofre incentive pricing plan. However, due to
the various unresolved regulatory and legislative issues (as discussed in Note 3), as of December 31, 2000, SCE
was no longer able to conclude that the unamortized nuclear investment was probable of recovery through the
rate-making process. As a result, this balance was written off as a charge to earnings at that time.
SCE requested in its utility-retained generation (URG) application to recover the unamortized cost of the nuclear
investment regulatory asset over a ten-year period, retroactive to January 1, 2001. Should this application be
approved, SCE would reestablish for financial reporting purposes its unamortized nuclear investment and related
flow-through taxes as regulatory assets with a corresponding credit to earnings.
The benefits of operation of the San Onofre units and the Palo Verde units were required to be shared equally
with ratepayers beginning in 2004 and 2002, respectively. In a June 2001 decision, the CPUC granted SCE's
request to eliminate the San Onofre post-2003 benefit sharing mechanism. The CPUC based its action on compliance
with recently enacted state law. In a September 2001 decision, the CPUC granted SCE's request to eliminate the
Palo Verde post-2001 benefit sharing mechanism and to continue the current rate treatment for Palo Verde,
including the continuation of the existing nuclear unit incentive procedure with a 5(cent)per kWh cap on replacement
power costs, until resolution of SCE's next general rate case or further CPUC action. Palo Verde's existing
nuclear unit incentive procedure calculates a reward for performance of any unit above an 80% capacity factor for
a fuel cycle.
Cash Equivalents
Cash equivalents include time deposits and other investments with original maturities of three months or less.
Planned Major Maintenance
Certain plant facilities require major maintenance on a periodic basis. All such costs are expensed as
incurred.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and under the first-in, first-out
method for coal.
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end of each period.
Investments
Net unrealized gains (losses) on equity investments are recorded as a separate component of shareholder's equity
under the caption "Accumulated other comprehensive income." Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative Financial Instruments
SCE uses the hedge accounting method to record its derivative financial instruments. Hedge accounting requires
an assessment that the transaction reduces risk, that the derivative is designated as a hedge at the inception of
the derivative contract, and that the changes in the market value of a hedge move in an inverse direction to the
item being hedged. Mark-to-market accounting would be used if the hedge accounting criteria were not met. If
the derivatives were terminated before the maturity of the corresponding debt issuance, the realized gain or loss
on the transaction would be amortized over the remaining term of the debt.
On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. The
new standard requires all derivatives to be recognized on the balance sheet at fair value. Prior to adoption,
hedges were not recorded on the balance sheet. Gains or losses from changes in the fair value of a recognized
asset or liability or a firm commitment are reflected in earnings for the ineffective portion of the hedge. For
a hedge of the cash flows of a forecasted transaction, the effective portion of the gain or loss is initially
recorded as a separate component of shareholder's equity under the caption "accumulated other comprehensive
income," and subsequently reclassified into earnings when the forecasted transaction affects earnings. The
ineffective portion of the gain or loss is reflected in earnings immediately. Under the new standard, SCE's
derivatives qualify for hedge accounting or for the normal purchase and sales exemption from derivatives
accounting rules. See Note 4 for a further discussion.
Utility Plant
Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct
material and labor, construction overhead and an allowance for funds used during construction (AFUDC). AFUDC
represents the estimated cost of debt and equity funds that finance utility-plant construction. AFUDC is
capitalized during plant construction and reported in current earnings in other nonoperating income. AFUDC is
recovered in rates through depreciation expense over the useful life of the related asset. Depreciation of
utility plant is computed on a straight-line, remaining-life basis.
AFUDC - equity was $2 million, $6 million and $8 million for the three, nine and twelve months ended
September 30, 2001, respectively, and $2 million, $9 million and $12 million for the three, nine and twelve months
ended September 30, 2000, respectively. AFUDC - debt was $2 million, $7 million and $9 million for the three,
nine and twelve months ended September 30, 2001, respectively, and $2 million, $8 million and $11 million for the
three, nine and twelve months ended September 30, 2000, respectively.
Replaced or retired property and removal costs less salvage are charged to the accumulated provision for
depreciation. Depreciation expense stated as a percent of average original cost of depreciable utility plant was
3.5%, 3.6% and 3.6% for the three, nine and twelve months ended September 30, 2001, and 3.6%, 3.5% and 3.6% for
the three, nine and twelve months ended September 30, 2000, respectively.
SCE's net investment in generation-related utility plant was approximately $1.0 billion at September 30, 2001, at
December 31, 2000, and at September 30, 2000.
Related Party Transactions
Certain Edison Mission Energy (a wholly owned subsidiary of Edison International) subsidiaries have ownership
interests in partnerships that sell electricity generated by their project facilities to SCE under long-term
power purchase agreements. Such sales to SCE were $106 million, $446 million and $560 million for the three,
nine and twelve months ended September 30, 2001, respectively, and $125 million,
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$242 million and $290 million for the three, nine and twelve months ended September 30, 2000, respectively.
As a result of SCE's liquidity crisis, SCE has deferred some payments for power purchases from these facilities.
Purchased Power
SCE purchased power through the California Power Exchange (PX) from April 1998 through mid-January 2001. Since
January 18, 2001, power purchased by the California Department of Water Resources (CDWR) or through the ISO for
SCE's customers is not considered a cost to SCE, since SCE is acting as an agent for these transactions.
Further, amounts billed to and collected from its customers for these power purchases are being remitted to the
CDWR and are not considered revenue to SCE. See further discussion in Note 3. SCE also has bilateral forward
contracts with other entities (as discussed in Note 4) and power-purchase contracts with other utilities and
independent power producers classified as qualifying facilities (QFs). Purchased power detail is provided below:
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
PX/ISO:
Purchases $ 26 $ 3,079 $ 660 $ 5,121 $ 3,988 $ 5,863
Generation sales 2 2,019 324 3,737 2,708 4,248
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Purchased power - PX/ISO - net 24 1,060 336 1,384 1,280 1,615
Purchased power - bilateral contracts 53 -- 142 -- 142 --
Purchased power - interutility/QF contracts 682 855 2,812 1,719 3,450 2,282
-------------------------------------------------------------------------------------------------------------------
Total $ 759 $ 1,915 $ 3,290 $ 3,103 $ 4,872 $ 3,897
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Other Nonoperating Income and Deductions
Other nonoperating income and deductions was comprised of:
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Gain on sale of marketable securities $-- $-- $ -- $ 41 $ -- $ 41
AFUDC 4 5 12 17 17 23
Key person life insurance income (expense) (1) (6) 7 1 12 5
Other 3 7 9 20 38 48
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Total other nonoperating income $ 6 $ 6 $ 28 $ 79 $ 67 $ 117
-------------------------------------------------------------------------------------------------------------------
Provisions for regulatory issues and refunds $-- $ 1 $ (7) $ 55 $ 16 $ 85
O&M services-- labor -- 8 -- 8 -- 8
Other 2 6 25 11 38 18
-------------------------------------------------------------------------------------------------------------------
Total other nonoperating deductions $ 2 $15 $ 18 $ 74 $ 54 $ 111
-------------------------------------------------------------------------------------------------------------------
New Accounting Standards
In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets. Although the statement supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
measurement of long-lived assets to be disposed of by sale. Under the new accounting standard, asset write-downs
from discontinuing a business segment will be treated the same as other assets held for sale. The new standard
also broadens the financial statement presentation of discontinued operations to include the disposal of
an asset group (rather than a segment of a business). The standard is effective for SCE beginning January 1,
2002, unless early adoption is implemented.
In July and August 2001, three new accounting standards were issued: Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.
The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (record goodwill for excess of
costs over the net assets acquired).
The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective
January 1, 2002. Goodwill initially recognized after June 30, 2001, will not be amortized. Goodwill on the
balance sheet at June 30, 2001, will be amortized until January 1, 2002. Under the new standard, goodwill will
be tested for impairment using a fair-value approach when events or circumstances occur indicating that
impairment might exist. Also, a benchmark assessment for goodwill is required within six months of the date of
adoption of the standard.
The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred. When the liability is
initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived
asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier application encouraged.
SCE is studying the impact of the new Asset Retirement Obligations and Asset Impairment standards, and is unable
to predict at this time the effect on its financial statements. SCE does not anticipate any material impact on
its results of operations or financial position from the other two new accounting standards.
Note 2. Liquidity Crisis
SCE's liquidity is primarily affected by debt maturities, dividend payments, capital expenditures and power
purchases. Capital resources include cash from operations and external financings.
Undercollections in the TRA and TCBA mechanisms, coupled with SCE's anticipated near-term capital requirements
and the adverse reaction of the credit markets to regulatory uncertainty regarding SCE's ability to recover its
power procurement costs, materially and adversely affected SCE's liquidity. As a result of its liquidity crisis,
SCE has taken and is taking steps to conserve cash so that it can continue to provide service to its customers.
As a part of this process, beginning in January 2001, SCE suspended payments of certain obligations for principal
and interest on outstanding debt and for purchased power. As of October 31, 2001, SCE had $3.3 billion in
obligations that were unpaid and overdue including: (1) $940 million to the PX or the ISO; (2) $1.2 billion to
QFs; (3) $231 million in PX energy credits for energy service providers; (4) $531 million of matured commercial
paper; and (5) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior
to the energy crisis. As applicable, unpaid obligations will continue to accrue interest. At October 31, 2001,
SCE had estimated cash reserves of approximately $2.7 billion (after deducting $530 million of designated funds),
which is approximately $650 million less than its outstanding unpaid obligations and preferred stock dividends in
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
arrears (see below), not including its credit facilities that are subject to forbearance agreements. If SCE
is found responsible for purchases of power by the ISO for delivery to SCE's customers on or after January 18,
2001, SCE's unpaid obligations as of October 31, 2001, could increase by as much as $1.6 billion. This
amount could increase or decrease depending on CPUC or FERC decisions regarding payments and refunds.
See additional discussion in Note 3. These stated amounts representing past or future obligations for
purchased power, PX energy credits and certain other items include amounts that are in dispute, and the
publishing of these amounts is not an admission by SCE of liability for any disputed amounts.
SCE's failure to pay when due the principal amount of the 5-7/8% and 6-1/2% senior unsecured notes constituted a
default on each series, entitling those noteholders to exercise their remedies (see Note 5).
SCE has been unable to obtain financing of any kind. As a result of investors' concerns regarding the California
energy crisis and its impact on SCE's liquidity and overall financial condition, SCE has repurchased $550 million
of pollution-control bonds that could not be remarketed in accordance with their terms. These bonds may be
remarketed in the future if SCE's credit status improves sufficiently. In addition, SCE has been unable to
market its commercial paper and other short-term financial instruments. As of March 31, 2001, SCE resumed
payment of interest on its debt obligations. However, since June 30, 2001, SCE has deferred the interest
payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the
securities. All interest in arrears must be paid in full at the end of the deferral period.
In March 2001, the CPUC issued decisions ordering SCE and other investor-owned utilities to pay QFs for power
deliveries on a going forward basis, commencing with April 2001 deliveries, and on the California Procurement
Adjustment (CPA) calculation including the approval of a 3(cent)per kWh rate increase. One of the CPUC decisions
also modified the formula used in calculating payments to QFs by substituting natural gas index prices based on
deliveries at the Oregon border rather than the index prices at the Arizona border. The changes apply to all
QFs, where appropriate, regardless of whether they use natural gas or other resources such as solar or wind.
In light of SCE's liquidity crisis, its Board of Directors has not declared quarterly common stock dividends to
SCE's parent, Edison International, since September 2000. Also, SCE's Board has not declared the regular
quarterly dividends for any of SCE's cumulative preferred stock in 2001. The total preferred stock dividends in
arrears were $17 million as of October 31, 2001. Dividends are additionally restricted as detailed in Note 3.
SCE has implemented other cost-cutting measures, such as freezing new hiring and postponing certain capital
expenditures. SCE's current cost-cutting measures are intended to allow it to continue to operate while efforts
to restore its creditworthiness (such as that contemplated in the CPUC litigation settlement agreement) are
underway.
Unless the court of appeals issues a stay pending appeal (described below) or the settlement is successfully
challenged on appeal, SCE's litigation settlement agreement with the CPUC, if implemented, is expected to allow
SCE to obtain financing which, combined with SCE's increasing cash reserves arising from the 2001 surcharges,
should allow SCE to pay all of its past due obligations by the end of first quarter 2002. Until these
obligations are paid, resolution of SCE's liquidity crisis and its ability to continue to operate outside
bankruptcy is uncertain. SCE's independent public accountants' opinion on the accompanying financial statements
includes an explanatory paragraph which states that the issues associated with the California energy crisis
continue to raise substantial doubt about SCE's ability to continue as a going concern.
For a more detailed discussion of the matters discussed above, see Notes 3 through 7.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Regulatory Matters
CPUC Litigation Settlement Agreement
In November 2000, SCE filed a lawsuit against the CPUC in federal district court in California, seeking a ruling
that SCE is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs
filed with the FERC. By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE
sought implementation of legislative, regulatory and executive actions to resolve the California energy crisis
and SCE's related financial and liquidity problems. On October 5, 2001, the district court entered a stipulated
judgment approving an agreement between the CPUC and SCE to settle the pending lawsuit.
Key elements of the settlement agreement include the following items:
o The CPUC will establish an account called the procurement-related obligations account (PROACT) as of
September 1, 2001, which will have an opening balance equal to the amount of SCE's procurement-related
liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and cash equivalents as of
that date (approximately $2.5 billion), and less $300 million. The opening balance of approximately $3.6
billion has been verified by the CPUC.
o During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has
recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will
apply to the PROACT, on a monthly or other basis established by the CPUC, the difference between SCE's
revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC
to recover in retail electric rates. Unrecovered obligations in the PROACT will accrue interest from
September 1, 2001.
o The parties agree that SCE will recover in retail electric rates its procurement-related obligations in
the PROACT, with interest, by December 31, 2005. Subject to certain adjustments, the CPUC will maintain
current rates (including surcharges) in effect until December 31, 2003, or, if earlier, until the date that
SCE recovers the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003,
the unrecovered balance will be amortized for up to an additional two years. The parties currently project
that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will
likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior
to the end of 2003.
o If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
procurement-related obligations, the parties will work together to achieve the securitization. Proceeds of
any securitization will be credited to the PROACT when they are actually received.
o During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed
by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.
o SCE intends to apply for CPUC approval to incur up to $250 million of recoverable costs to acquire
financial instruments and engage in other transactions intended to hedge fuel cost risks associated with
SCE's retained generation assets and power purchase contracts with qualifying facilities and other
utilities. The CPUC indicated that it will schedule proceedings reasonably promptly and consider SCE's
application on an expedited basis.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o SCE will not declare or pay dividends or other distributions on its common stock (all of which is held by its
parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations in the
PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-related obligations by
December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends, and the CPUC will
not unreasonably withhold its consent.
o To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's
next general rate case, SCE may make capital expenditures above the level contained in current rates, up to
$900 million per year, which will be treated as recoverable costs.
o Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General
to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses
to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of
California or its agencies against the same adverse parties. During the recovery period discussed above,
refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the
PROACT.
The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.
The settlement agreement states that the CPUC shall adopt such decisions or orders it deems necessary to
implement and carry out the provisions of the agreement, with the understanding that the agreement and stipulated
judgment shall be binding and irrevocable upon the parties. SCE expects that these implementing decisions or
orders will be issued during fourth quarter 2001.
On October 26, 2001, a California consumer group asked a federal court of appeals for a stay of judgment pending
appeal of the federal district court's judgment approving the settlement. The group alleged that it was denied
due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze. On
October 30, 2001, the court of appeals granted a temporary stay, and instructed the consumer group to return to
district court to argue the merits of the stay. On November 9, 2001, the district court denied the consumer
group's request for a stay. The consumer group indicated that it intends to ask the court of appeals for a stay
of judgment pending appeal. If the stay of judgment pending appeal is granted, or the settlement is successfully
challenged on appeal, the ability of SCE and the CPUC to implement the settlement agreement would be affected
adversely, which in turn would have an adverse effect on SCE's ability to restore its financial condition, repay
its creditors, and avoid an involuntary bankruptcy petition.
CDWR Power Purchases
In accordance with an emergency order signed by the Governor, the CDWR began making emergency power purchases for
SCE's customers on January 18, 2001. Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not considered
revenue to SCE. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to
retail customers being served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.
On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to
the applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5,
2001), for each kWh the CDWR sells to SCE's customers. The CPUC determined that the
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
generation-related retail rate should be equal to the total bundled electric rate (including the 1(cent)per kWh
surcharge adopted by the CPUC on January 4, 2001) less certain nongeneration-related rates or charges. For the
period January 19 through January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277(cent)per kWh for
power delivered to SCE's customers. The CPUC determined that the applicable rate component is 7.277(cent)per kWh
(which increased to 10.277(cent)per kWh for electricity delivered after March 27, 2001, due to the 3(cent)surcharge
discussed in Rate Stabilization Proceedings), for electricity delivered by the CDWR to SCE's retail customers
after February 1, 2001, until more specific rates are calculated. The CPUC ordered SCE to pay the CDWR within 45
days after the CDWR supplies power to retail customers, subject to penalties for each day the payment is late.
On September 4, 2001, the CPUC issued a proposed decision authorizing a CDWR revenue requirement of $12.1 billion
to pay its bonds' costs and energy procurement costs for 2001 and 2002. The proposed decision states that SCE's
allocated share of this revenue requirement (based on a cost-of-service approach) would be approximately $4
billion, and changes SCE's payment from 10.277(cent)per kWh to 10.03(cent)per kWh. A balancing account would be
established to record the difference between the two rates, with the difference to be trued up in a subsequent
CPUC order. In comments filed with the CPUC on September 12, 2001, SCE requested that the CPUC refrain from
adopting a final revenue requirement until hearings are held to determine how the revenue requirement was
calculated and its relationship to SCE's revenue requirement to be determined in the URG proceeding. In a
November 5, 2001, filing with the CPUC, the CDWR reduced its revenue requirement to $10.0 billion, due to
conservation efforts, lower natural gas prices and other changes in market conditions. The CPUC has not
determined SCE's share of the $10.0 billion. A final decision on the URG and CDWR matters is not expected until
early 2002.
SCE believes that the intent of AB 1X was for the CDWR to assume full responsibility for purchasing all power
needed to serve the retail customers of electric utilities, in excess of the output of generating plants owned by
the electric utilities and power delivered to the utilities under existing contracts. However, the CDWR stated
that it would only purchase power that it considers to be reasonably priced, leaving the ISO to purchase in the
short-term market the additional power necessary to meet system requirements. The ISO, in turn, took the
position that it will charge SCE for the costs of power it purchases in this manner. If SCE is found responsible
for purchases of power by the ISO for delivery to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs for the nine months ended September 30, 2001, could increase by as much as $1.6 billion
(which includes bills received for January through July 2001, and an estimate for August and September 2001).
This amount could increase or decrease depending on CPUC or FERC decisions regarding payments and refunds. In
its March 2001 interim order, the CPUC stated that it cannot assume that the CDWR will pay for the ISO purchases
and that it does not have the authority to order the CDWR to do so. Litigation among certain power generators,
the ISO and the CDWR (to which SCE is not a party), and proceedings before the FERC (to which SCE is a party),
may result in rulings clarifying the CDWR's financial responsibility for purchases of power. In April 2001, the
FERC issued an order confirming its February 2001 order that the ISO must have a creditworthy buyer for any
transactions. SCE has not met the ISO's creditworthiness requirements since its credit ratings were downgraded
in mid-January 2001. As a result, SCE has protested and returned the bills it has received from the ISO. On
November 7, 2001, the FERC issued an order directing the ISO to invoice CDWR (within 15 days of the date of the
order) for all transactions it entered into on behalf of SCE's customers. The ISO was also directed to file a
report with the FERC within 15 days from the date of the order indicating overdue amounts from CDWR and a
schedule for payments of those amounts within three months of the date of the order. In any event, SCE takes the
position that it is not responsible for purchases of power by the CDWR or the ISO on or after January 18, 2001.
SCE cannot predict the outcome of any of these proceedings or issues.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Status of Transition and Power-Procurement Cost Recovery
The electric utility industry restructuring plan instituted a multi-year freeze on the rates that SCE could
charge its customers and transition cost recovery mechanisms designed to allow SCE to recover its stranded costs
associated with generation-related assets. California's electric utility industry restructuring statute included
provisions to finance a portion of the stranded costs that residential and small commercial customers would have
paid between 1998 and 2001, which allowed SCE to reduce rates by at least 10% to these customers, effective
January 1, 1998. These frozen rates (except for the surcharges effective in 2001) were to remain in effect until
the earlier of March 31, 2002, or the date when the CPUC-authorized costs for utility-owned generation assets and
obligations were recovered. However, between May 2000 and June 2001, the prices charged by generators and other
sellers escalated far beyond what SCE could charge its customers. As a result, SCE incurred a $4 billion
undercollection in transition costs.
SCE's transition costs include power purchases from QF contracts (which are the direct result of prior
legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide
service to customers. Other costs include the recovery of income tax benefits previously flowed through to
customers, postretirement benefit transition costs and accelerated recovery of investment in SCE's nuclear
plants. Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract. Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most
of the remaining transition costs to be recovered through the end of the four-year transition period (not later
than March 31, 2002). Because regulatory and legislative actions that make such recovery probable were not taken
in a timely manner during the energy crisis, as of December 31, 2000, SCE was unable to conclude that the net
regulatory assets related to purchased-power settlements, the unamortized loss on SCE's generating plant sales in
1998, and various other generation regulatory assets were probable of recovery through the rate-making process.
As a result, these balances were written off as a charge to earnings at that time.
There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001. Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism. State legislation enacted in January 2001 prohibits the sale of SCE's remaining generation assets
until 2006. SCE stopped selling power from its generation into the ISO and PX markets in January 2001, after
SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges.
CTC revenue was determined residually (i.e., CTC revenue was the residual amount remaining from monthly gross
customer revenue under the rate freeze after subtracting the revenue requirements for transmission, distribution,
nuclear decommissioning and public benefit programs, and ISO payments and power purchases from the PX and ISO).
The CTC applied to all customers who were using or began using utility services on or after the CPUC's 1995
restructuring decision date. Residual CTC revenue was calculated through the TRA mechanism. In accordance with
the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue was transferred
from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998. A previous decision had called only
for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had not been any
positive residual CTC revenue between May 2000 and June 2001. The cumulative transition cost undercollection (as
recalculated) was $4.0 billion as of September 30, 2001, and $2.9 billion as of December 31, 2000.
Page 19
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rate Stabilization Proceedings
In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery. In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.
In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates. The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition. The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates. In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into: whether the holding companies violated CPUC requirements to give priority to the capital
needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the requirements to give priority to the
capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary. SCE believes the holding company
decision refers to equity investment, not working capital for operating costs. The CPUC ordered testimony and
briefing on these matters, which SCE filed in May and June 2001. SCE cannot predict what effects this
investigation or any subsequent actions by the CPUC may have on SCE.
In March 2001, the CPUC ordered a rate increase in the form of a 3(cent)per kWh surcharge applied only to
going-forward electric power procurement costs, effective immediately, and affirmed that a 1(cent)interim surcharge
granted in January 2001 is now permanent. The 3(cent)surcharge is to be added to the rate paid to the CDWR.
Although the 3(cent)increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the
CPUC established a rate design in early June 2001.
Also, in the March 2001 order, the CPUC granted a petition previously filed by The Utility Reform Network and
directed that the balance in SCE's TRA account, whether over or undercollected, be transferred on a monthly basis
to the TCBA, retroactive to January 1, 1998. Previous rules called only for TRA overcollections (residual CTC
revenue) to be transferred to the TCBA. The CPUC also ordered SCE to transfer the coal and hydroelectric
balancing account overcollections to the TRA on a monthly basis before any transfer of residual CTC revenue to
the TCBA, retroactive to January 1, 1998. Previous rules called for overcollections in these two balancing
accounts to be transferred directly to the TCBA on an annual basis. Based upon the transfer of balances into the
TCBA, the CPUC denied SCE's December 2000 filing to have the current rate freeze end, and stated that the
four-year rate freeze will not end until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze. The CPUC also said that it will
monitor the balances remaining in the TCBA and consider how to address remaining balances in the ongoing
proceedings. In accordance with the October 2001 settlement with the CPUC, it is expected that the TCBA
mechanism will be discontinued and the PROACT mechanism will be established retroactive to August 31, 2001.
Utility Retained Generation Proceeding
In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
cost-of-service ratemaking for utility retained generation through the end of 2002. The URG proposal calls for
balancing accounts for SCE-owned generation, QF and interutility contracts,
Page 20
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
procurement costs and ISO charges based on either actual or CPUC-authorized revenue requirements. Under the
proposal, the four new balancing accounts would be effective January 1, 2001, for capital-related costs, and
February 1, 2001, for non-capital-related costs. In addition, SCE's unamortized nuclear investment would be
amortized and recovered in rates over a 10-year period effective January 1, 2001. Should this application be
approved, SCE expects to reestablish for financial reporting purposes its unamortized nuclear investment and
related flow-through taxes as regulatory assets with a corresponding credit to earnings. Hearings were held in
July 2001. A final decision is not expected until early 2002.
Wholesale Electricity Markets
In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds. In December 2000, the FERC took limited action and failed
to impose a price cap. SCE filed an emergency petition in the federal Court of Appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates. The Court denied SCE's
petition in January 2001.
In its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling
coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In May 2001, the
FERC indicated that it will make a determination regarding the suspension of the underscheduling penalty in a
future order in response to a complaint filed by SCE that asked the FERC to eliminate the penalty. As of October
31, 2001, SCE's share of the accumulated penalties were estimated to be as much as $360 million. The ISO has not
billed SCE for any amounts associated with the underscheduling penalty. SCE cannot predict the outcome of this
matter.
On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power). The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.
After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter. SCE
cannot predict the amount of any potential refunds. Under the settlement of litigation with the CPUC, refunds
will be applied to the balance in the PROACT.
Note 4. Financial Instruments
SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on
its investments, fluctuations in interest rates and energy prices, but prohibits the use of these instruments for
speculative or trading purposes.
SCE used the mark-to-market accounting method for its gas call options, which were used to mitigate SCE's
transition cost recovery exposure to increases in energy prices. Gains and losses from monthly changes in market
prices were recorded as income or expense. In addition, the options' costs and market price changes were
included in the TCBA. As a result, the mark-to-market gains or losses had
Page 21
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
no effect on earnings. In October 2000, SCE sold its gas call options resulting in a $190 million gain. The
options covered various periods through 2001. The gains were credited to the TCBA.
The PX block forward market allowed SCE to purchase monthly blocks of energy and ancillary services for six days
a week (excluding Sundays and holidays) for 8 to 16 hours a day, up to 12 months in advance of the delivery
date.
SCE purchased block forward energy contracts through the PX, with various terms and prices, to hedge its exposure
to fluctuations in energy prices. Due to the downgrades in SCE's credit ratings and SCE's failure to pay its
obligations to the PX, the PX suspended SCE's market trading privileges and sought to liquidate SCE's block
forward contracts. On February 2, 2001, SCE's motion for a preliminary injunction was denied, freeing the PX to
liquidate the contracts and apply the proceeds to amounts owed by SCE to the PX. On the same day, the state
seized the contracts for the benefit of the state before the PX could sell them. See further discussion below.
SCE also has bilateral forward contacts, which are considered normal purchases under accounting rules. Due to
its deteriorating credit ratings, SCE has been unable to purchase additional bilateral forward contracts, and, in
early 2001, the counterparties terminated $379 million (nominal value) of SCE's contracts. At September 30,
2001, SCE's bilateral forward contracts had a nominal value of $291 million. SCE is exposed to credit loss in
the event of nonperformance by the counterparties to its bilateral forward contracts, but does not expect the
counterparties to fail to meet their obligations. The counterparties are required to post collateral depending
on the creditworthiness of each counterparty. SCE is exposed to market risk resulting from changes in the spot
market price for power.
SCE used an interest rate swap to reduce the potential impact of interest rate fluctuations on floating-rate
long-term debt. At December 31, 2000, and September 30, 2000, SCE had an interest rate swap agreement which
fixed the interest rate at 5.585% for $196 million of debt due 2008; the receive rate on the swap averaged 3.839%
in 2000. As a result of the downgrade in SCE's credit rating below the level allowed under the interest rate
hedge agreement, on January 5, 2001, the counterparty to this interest rate swap terminated the agreement. As a
result of the termination of the swap, SCE is paying a floating rate on $196 million of its debt due 2008. The
realized loss of $26 million is being amortized over a period ending in 2008.
On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. See
Note 1 for a further discussion. On the implementation date, SCE recorded its interest rate swap agreement
(terminated January 5, 2001) and its block forward power-purchase contracts at fair value on its balance sheet.
As discussed above, on February 2, 2001, the state seized the contracts, which at that time had an unrealized
gain of approximately $500 million. On September 30, 2001, a federal appeals court ruled that the Governor of
California acted illegally when he seized the power contracts held by SCE. In conjunction with its settlement
agreement with the CPUC, SCE has agreed to release any claim for compensation against the state for these
contracts.
Page 22
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair values of financial instruments were:
September 30, December 31, September 30,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Cost Fair Cost Fair Cost Fair
Instrument Basis Value Basis Value Basis Value
---------------------------------------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $ 1,717 $ 2,268 $ 1,720 $ 2,505 $ 1,774 $ 2,542
Gas call options -- -- -- -- 19 251
Financial liabilities:
DOE decommissioning and
decontamination fees 36 27 36 31 40 33
Interest rate swap -- -- -- 21 -- 13
Short-term debt 2,131 2,032 1,451 1,339 1,276 1,276
Long-term debt 3,166 3,120 5,631 5,178 4,807 4,653
Long-term debt classified as
due within one year 2,797 2,678 646 632 647 651
Preferred stock subject to
mandatory redemption 151 75 256 157 256 250
Preferred stock to be redeemed
within one year 105 53 -- -- -- --
---------------------------------------------------------------------------------------------------------------
Financial assets are carried at their fair values based on quoted market prices. Financial liabilities are
recorded at cost. Financial liabilities' fair values are based on: quoted market prices for the interest rate
swap; brokers' quotes for short-term debt, long-term debt and preferred stock; and discounted future cash flows
for U.S. Department of Energy (DOE) decommissioning and decontamination fees. Due to their short maturities,
amounts reported for cash equivalents approximated fair value at September 30, 2001, December 31, 2000, and
September 30, 2000.
Gross unrealized holding gains on debt and equity investments were:
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $ 141 $ 193 $ 202
Stocks 252 384 383
U.S. government issues 89 136 126
Short-term and other 69 72 57
-------------------------------------------------------------------------------------------------------------
Total $ 551 $ 785 $ 768
-------------------------------------------------------------------------------------------------------------
There were no unrealized holding losses for the periods presented.
Note 5. Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage
bonds as security for borrowed funds obtained from pollution control bonds issued by government agencies. SCE
uses these proceeds to finance construction of pollution control facilities. Bondholders have limited discretion
in redeeming certain pollution-control bonds, and SCE has arrangements with securities dealers to remarket or
purchase them if necessary. As a result of investors'
Page 23
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
concerns regarding SCE's liquidity difficulties and overall financial condition, SCE had to repurchase $550
million of pollution control bonds in December 2000 and early 2001 that could not be remarketed in accordance
with their terms. In addition, some of the long-term debt have subjective acceleration clauses.
In January 2001, three rating agencies lowered their credit ratings of SCE to substantially below investment
grade.
Debt premium, discount and issuance expenses are amortized over the life of each issue. Under CPUC rate-making
procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if
refinanced, the life of the new debt.
Commercial paper intended to be refinanced for a period exceeding one year and used to finance nuclear fuel
scheduled to be used more than one year after the balance sheet date is classified as long-term debt.
In December 1997, SCE Funding LLC, a special purpose entity, issued $2.5 billion of rate reduction notes on
behalf of SCE. These notes were issued to finance the 10% rate reduction mandated by state law. The proceeds of
the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as
transition property. Transition property is a current property right created by the restructuring legislation
and a financing order of the CPUC and consists generally of the right to be paid a specified amount from
nonbypassable rates charged to residential and small commercial customers. The rate reduction notes are being
repaid over 10 years through these nonbypassable residential and small commercial customer rates that constitute
the transition property purchased by SCE Funding LLC. The notes are secured by the transition property and are
not secured by, or payable from, assets of SCE or Edison International. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities. Although, as required by accounting principles
generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the rate reduction notes
are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is legally separate from
SCE. The assets of SCE Funding LLC are not available to creditors of SCE or Edison International and the
transition property is legally not an asset of SCE or Edison International. Due to SCE's credit downgrade, in
January 2001, SCE began remitting its customer collections related to the rate-reduction notes on a daily basis.
Page 24
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt consisted of:
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
First and refunding mortgage bonds:
2002 - 2026 (5.625% to 7.25%) $ 1,175 $ 1,175 $ 1,175
Rate reduction notes:
2002 - 2007 (6.22% to 6.42%) 1,550 1,724 1,795
Pollution control bonds:
2008 - 2040 (5.125% to 7.2% and variable) 1,217 1,216 1,415
Bonds repurchased (550) (420) --
Funds held by trustees (20) (20) (219)
Debentures and notes:
2001 - 2029 (5.875% to 7.625% and variable) 2,450 2,450 1,150
Subordinated debentures:
2044 (8.375%) 100 100 100
Commercial paper for nuclear fuel 66 79 64
Long-term debt classified as due within one year (2,797) (646) (647)
Unamortized debt discount - net (25) (27) (26)
-------------------------------------------------------------------------------------------------------------------
Total $ 3,166 $ 5,631 $ 4,807
-------------------------------------------------------------------------------------------------------------------
Long-term debt maturities and sinking-fund requirements for the five twelve-month periods following September 30,
2001, are: 2002 - $947 million; 2003 - $572 million; 2004 - $1.4 billion; 2005 - $247 million; and 2006 -
$447 million. These projections assume no acceleration of payments arising from default. See further discussion
below.
As a result of its liquidity crisis, SCE has taken steps to conserve cash so that it can continue to provide
service to its customers. As a part of this process, SCE has suspended payments of certain obligations. As of
October 31, 2001, SCE has failed to pay $400 million of maturing principal on its 5-7/8% and 6-1/2% senior
unsecured notes. SCE's failure to pay when due the principal amount of the 5-7/8% and 6-1/2% senior unsecured
notes constituted a default on each series, entitling those noteholders to exercise their remedies. Such failure
and the failure to pay commercial paper when due could also constitute an event of default on all the other
series of senior unsecured notes if the trustee or holders of 25% in principal amount of the notes give a notice
demanding that the default be cured, and SCE does not cure the default within 30 days. Such failures are also an
event of default under SCE's credit facilities and bilateral credit agreements, entitling those lenders to
exercise their remedies including potential acceleration of the outstanding borrowings of $1.65 billion (see Note
6). If a notice of default is received, SCE could cure the default only by paying $531 million in overdue
principal to holders of commercial paper and $400 million to the holders of the 5-7/8% and 6-1/2% senior
unsecured notes which were issued prior to the energy crisis. Making such payment would further impact SCE's
liquidity. If a notice of default were received and not cured, and the trustee or noteholders were to declare an
acceleration of the outstanding principal amount of the senior unsecured notes, SCE would not have the cash to
pay the obligation and could be forced to declare bankruptcy. As a result of the default of the two series of
senior unsecured notes, SCE's other senior unsecured notes and subordinated debentures have been classified as
due within one year in the accompanying financial statements. Since June 30, 2001, SCE has deferred the interest
payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the
securities. All interest in arrears must be paid in full at the end of the deferral period.
Page 25
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Short-Term Debt
Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash
requirements, including power purchase payments. Commercial paper intended to finance nuclear fuel scheduled to
be used more than one year after the balance sheet date is classified as long-term debt in connection with
refinancing terms under five-year term lines of credit with commercial banks.
Short-term debt consisted of:
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------
Commercial paper $ 541 $ 700 $ 764
Bank loans 1,650 835 410
Floating rate notes -- -- 175
Other 6 -- --
Amount reclassified as long-term debt (66) (79) (64)
Unamortized discount -- (5) (9)
-------------------------------------------------------------------------------------------------------------
Total $ 2,131 $ 1,451 $ 1,276
-------------------------------------------------------------------------------------------------------------
Weighted-average interest rate 6.2% 6.9% 6.7%
At September 30, 2001, SCE had lines of credit (including bilateral credit agreements) totaling $1.65 billion.
As of January 2001, SCE had borrowed the entire $1.65 billion in funds available under its credit lines. The
proceeds were used in part to repurchase $550 million of pollution control bonds; the balance was retained as a
liquidity reserve. When available, the lines can be drawn at negotiated or bank index rates.
SCE's $200 million, 364-day credit facility and $400 million in bilateral credit agreements expire on March 29,
2002. SCE's $1.05 billion, five-year credit facility expires in May 2002. The forbearance agreements on the
$1.65 billion in credit facilities expire on March 29, 2002.
SCE has conserved cash by deferring payment of $531 million of matured commercial paper as of October 31, 2001.
Note 7. Preferred Stock
Authorized shares of preferred and preference stock are: $25 cumulative preferred - 24 million; $100 cumulative
preferred - 12 million; and preference - 50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund provisions. When preferred shares are
redeemed, the premiums paid are charged to common equity.
Preferred stock redemption requirements for the five twelve-month periods following September 30, 2001, are: 2002
- $105 million; 2003 - $9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.
Page 26
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
September 30, December 31, September 30,
Dollars in millions, except per share amounts 2001 2000 2000
-----------------------------------------------------------------------------------------------------------------------
September 30, 2001
----------------------------------
Shares Redemption
Outstanding Price
--------------- ---------------
Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000 $ 25.50 $ 25 $ 25 $ 25
4.24 1,200,000 25.80 30 30 30
4.32 1,653,429 28.75 41 41 41
4.78 1,296,769 25.80 33 33 33
-----------------------------------------------------------------------------------------------------------------------
Total $ 129 $ 129 $ 129
-----------------------------------------------------------------------------------------------------------------------
Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000 $ 100.00 $ 75 $ 75 $ 75
6.45 1,000,000 100.00 100 100 100
7.23 807,000 100.00 81 81 81
Preferred stock to be redeemed within one year (105) -- --
-----------------------------------------------------------------------------------------------------------------------
Total $ 151 $ 256 $ 256
-----------------------------------------------------------------------------------------------------------------------
There were no preferred stock issuances or redemptions for the three, nine and twelve months ended September 30,
2001, and 2000.
In 2001, SCE's Board has not declared the regular quarterly dividends for any of SCE's cumulative preferred
stock. As of October 31, 2001, SCE's preferred stock dividends in arrears were $17 million. As long as these
dividends remain unpaid, SCE cannot declare or pay future cash dividends on any series of preferred stock or on
its common stock, and SCE cannot repurchase any shares of its common stock. As a result of the $2.5 billion
charge to earnings during fourth quarter 2000, SCE's retained earnings are now in a deficit position and
therefore, under California law, SCE will be unable to pay dividends as long as a deficit remains. Dividends are
additionally restricted as detailed in Note 3.
Note 8. Income Taxes
SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined
state franchise tax returns. Under an income tax allocation agreement approved by the CPUC, SCE calculates its
tax liability on a stand-alone basis.
Income tax expense includes the current tax liability from operations and the change in deferred income taxes
during the year. Investment tax credits are amortized over the lives of the related properties.
Page 27
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net accumulated deferred income tax liability were:
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Property-related $ 197 $ 277 $ 193
Unrealized gains and losses 384 420 436
Investment tax credits 75 81 90
Regulatory balancing accounts 1,869 1,763 94
Decommissioning 79 98 103
Accrued charges 443 379 311
Unbilled revenue 181 101 187
Other 137 56 80
-------------------------------------------------------------------------------------------------------------------
Total $ 3,365 $ 3,175 $ 1,494
-------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $ 2,259 $ 2,184 $ 2,345
Capitalized software costs 228 264 251
Regulatory balancing accounts 1,907 1,632 1,179
Unrealized gains and losses 281 317 333
Other 331 242 200
-------------------------------------------------------------------------------------------------------------------
Total $ 5,006 $ 4,639 $ 4,308
-------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net $ 1,641 $ 1,464 $ 2,814
-------------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $ 2,234 $ 2,009 $ 3,360
Included in current assets 593 545 546
The current and deferred components of income tax expense were:
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Current:
Federal $ 322 $ (48) $ 27 $ 235 $ (312) $ 271
State -- (13) -- 56 (56) 66
-------------------------------------------------------------------------------------------------------------------
322 (61) 27 291 (368) 337
-------------------------------------------------------------------------------------------------------------------
Deferred - federal and state:
Accrued charges (16) (17) (50) (66) (117) (103)
Contributions in aid of construction (6) (5) (9) (6) (14) (11)
Property related 60 (46) 178 (139) 15 (185)
Investment and energy tax credits - net (2) (10) (5) (31) (15) (43)
Operating loss carryforwards 102 -- (10) -- (24) --
Regulatory assets (52) 11 (133) 25 93 9
Regulatory balancing accounts 140 363 151 397 (986) 570
State tax privilege year (27) 4 (18) 7 5 4
Unbilled revenue (79) (70) (90) (65) (4) (63)
Decommissioning fund withdrawals 10 6 21 12 26 15
Other (7) (6) 6 1 9 5
-------------------------------------------------------------------------------------------------------------------
123 230 41 135 (1,012) 198
-------------------------------------------------------------------------------------------------------------------
Total $ 445 $ 169 $ 68 $ 426 $ (1,380) $ 535
-------------------------------------------------------------------------------------------------------------------
Page 28
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The composite federal and state statutory income tax rate was 40.551% for all periods presented.
The federal statutory income tax rate is reconciled to the effective tax rate below:
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Capitalized software (0.2) (0.8) (4.3) (0.8) 0.3 (1.0)
Property-related and other -- 9.4 3.3 9.4 (3.5) 8.6
Investment and energy tax credits (0.2) (3.0) (2.6) (3.5) 0.4 (3.7)
State tax - net of federal deduction 5.8 8.3 9.2 8.0 4.4 8.0
-------------------------------------------------------------------------------------------------------------------
Effective tax rate 40.4% 48.9% 40.6% 48.1% 36.6% 46.9%
-------------------------------------------------------------------------------------------------------------------
Note 9. Employee Compensation and Benefit Plans
Employee Savings Plan
SCE has a 401(k) defined-contribution savings plan designed to supplement employees' retirement income. The plan
received employer contributions of $8 million, $22 million and $29 million for the three, nine and twelve months
ended September 30, 2001, respectively, and $8 million, $23 million and $29 million for the three, nine and
twelve months ended September 30, 2000, respectively.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers employees meeting minimum service
requirements. SCE recognizes pension expense as calculated by the actuarial method used for ratemaking. In
April 1999, SCE adopted a cash balance feature for its pension plan.
Page 29
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
9 Months Ended Year Ended 9 Months Ended
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 2,200 $ 2,075 $ 2,075
Service cost 51 63 48
Interest cost 114 155 117
Actuarial loss -- 90 --
Benefits paid (151) (183) (142)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 2,214 $ 2,200 $ 2,098
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 3,067 $ 3,078 $ 3,078
Actual return on plan assets (374) 143 204
Employer contributions -- 29 29
Benefits paid (151) (183) (142)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 2,542 $ 3,067 $ 3,169
-------------------------------------------------------------------------------------------------------------------
Funded status $ 328 $ 867 $ 1,071
Unrecognized net loss (gain) (158) (745) (1,012)
Unrecognized transition obligation 19 22 25
Unrecognized prior service cost 106 118 120
-------------------------------------------------------------------------------------------------------------------
Recorded asset $ 295 $ 262 $ 204
-------------------------------------------------------------------------------------------------------------------
Discount rate 7.25% 7.25% 7.75%
Rate of compensation increase 5.00% 5.00% 5.00%
Expected return on plan assets 8.50% 8.50% 7.50%
The components of pension expense were:
3 Months Ended 9 Months Ended 12 Months Ended
In millions September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 17 $ 16 $ 51 $ 48 $ 66 $ 64
Interest cost 38 39 114 117 152 149
Expected return on plan assets (63) (57) (189) (171) (284) (215)
Net amortization and deferral (3) (8) (9) (24) (25) (19)
-------------------------------------------------------------------------------------------------------------------
Pension expense (benefit) under
accounting standards (11) (10) (33) (30) (91) (21)
Regulatory adjustment - deferred 11 10 33 30 91 32
-------------------------------------------------------------------------------------------------------------------
Net pension expense recognized $ -- $ -- $ -- $ -- $ -- $ 11
-------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health
and dental care, life insurance and other benefits.
Page 30
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
9 Months Ended Year Ended 9 Months Ended
September 30, December 31, September 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 1,762 $ 1,462 $ 1,462
Service cost 33 39 27
Interest cost 99 121 87
Actuarial loss -- 202 --
Benefits paid (51) (62) (45)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 1,843 $ 1,762 $ 1,531
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 1,200 1,283 $ 1,283
Actual return on plan assets 78 (40) 69
Employer contributions 15 19 63
Benefits paid (51) (62) (45)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 1,242 $ 1,200 $ 1,370
-------------------------------------------------------------------------------------------------------------------
Funded status $ (601) $ (562) $ (161)
Unrecognized net loss (gain) 141 141 (204)
Unrecognized transition obligation 305 323 328
-------------------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (155) $ (98) $ (37)
-------------------------------------------------------------------------------------------------------------------
Discount rate 7.5% 7.5% 8.0%
Expected return on plan assets 8.2% 8.2% 7.5%
Expense components were:
3 Months Ended 9 Months Ended 12 Months Ended
In millions September 30, September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 11 $ 9 $ 33 $ 27 $ 45 $ 40
Interest cost 33 29 99 87 133 118
Expected return on plan assets (26) (23) (78) (69) (115) (91)
Net amortization and deferral 6 6 18 18 27 24
-------------------------------------------------------------------------------------------------------------------
Total expense $ 24 $ 21 $ 72 $ 63 $ 90 $ 91
-------------------------------------------------------------------------------------------------------------------
The assumed rate of future increases in the per-capita cost of health care benefits is 11.0% for 2001, gradually
decreasing to 5.0% for 2008 and beyond. Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of September 30, 2001, by $290 million and annual aggregate service and
interest costs by $31 million. Decreasing the health care cost trend rate by one percentage point would decrease
the accumulated obligation as of September 30, 2001, by $250 million and annual aggregate service and interest
costs by $25 million.
Stock Option Plans
In 1998, Edison International shareholders approved the Edison International Equity Compensation Plan, replacing
the Long-Term Incentive Compensation Program (prior program), which had been adopted by shareholders in 1992.
Under the prior program, options on 1.4 million shares of Edison International common stock remain outstanding to
officers and senior managers of SCE. The 1998 plan authorizes a limited annual award of Edison International
common shares and options on shares. The annual
Page 31
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
authorization is cumulative, allowing subsequent issuance of previously unutilized awards. In May 2000, Edison
International adopted an additional plan, the 2000 Equity Plan, which did not require shareholder approval.
Under the 1998 and 2000 plans, options on 8.2 million shares of Edison International common stock are currently
outstanding to officers and senior managers of SCE.
Each option may be exercised to purchase one share of Edison International common stock, and is exercisable at a
price equivalent to the fair market value of the underlying stock at the date of grant. Options generally expire
10 years after the date of grant, and vest over a period of up to five years. Stock option awards made in lieu
of grants for 2001 and 2002 (Special Option Grants) may not be exercised before five years have passed unless the
stock appreciates to $25 (based on the average of 20 consecutive trading day closing prices).
A portion of the 2000 executive long-term incentives was awarded in the form of performance shares. The
performance shares were restructured as retention incentives in December 2000, which will pay as a combination of
Edison International common stock and cash if the executive remains employed at the end of the performance
period. Additional performance shares were awarded in January 2001. The 2001 performance shares vest December
31, 2003, and payment will be made in January 2004, half in shares of Edison International common stock and half
in cash. The cash amount is the product of the number of shares to be paid in cash, times the average of the
high and low common stock price on the last market day of the year. Retention Incentive Deferred Stock Units
were awarded on March 12, 2001. These vest no later than March 12, 2003, and are paid out on that date in shares
of Edison International common stock, unless before that date the stock price averages at least $20 for 20
consecutive trading days. In that case the units will vest and pay out on the later of March 12, 2002, or the
day following the period in which the $20 average price was achieved.
Edison International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend
equivalents on stock options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared
on Edison International common stock, and are subject to reduction unless certain performance criteria are met.
Only a portion of the 1999 Edison International stock option awards included a dividend equivalent feature. The
2000 stock option awards did not include dividend equivalents. Future stock option awards are not expected to
include dividend equivalents.
Options issued after 1997 generally vest in 25% annual installments over a four-year period, although vesting for
the Special Option Grants does not begin until May 2002. Stock options issued prior to 1998 had a three-year
vesting period with one-third of the total award vesting after each of the first three years of the award term.
If an option holder retires, dies or is permanently and totally disabled (qualifying event) during the vesting
period, the unvested options will vest on a pro rata basis. If an option holder is terminated under a company
severance plan, the unvested options will vest on a pro rata basis with an additional year of service credit.
Unvested options of any person who has served in the past on the SCE Management Committee (which was dissolved in
1993) will vest and be exercised upon a qualifying event. If a qualifying event occurs, the vested options may
continue to be exercised within their original terms by the recipient or beneficiary. If an option holder is
terminated other than by a qualifying event, options which had vested as of the prior anniversary date of the
grant are forfeited unless exercised within 180 days of the date of termination; except that if the termination
is covered by a company severance plan, the terminated employee will receive one additional year of vesting
credit and must exercise vested options within 12 months. All unvested options are forfeited on the date of
termination.
Page 32
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The performance share values are accrued ratably over a three-year performance period. SCE measures compensation
expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under
the stock-compensation programs was $2 million, $2 million and $3 million for the three, nine and twelve months
ended September 30, 2001, respectively, and $1 million, $2 million and $5 million for the three, nine and twelve
months ended September 30, 2000, respectively.
Stock-based compensation expense under the fair value method of accounting would have resulted in pro forma net
income (loss) available for common stock of $649 million, $75 million and $(2.417) billion for the three, nine
and twelve months ended September 30, 2001, respectively, and $171 million, $439 million and $580 million for the
three, nine and twelve months ended September 30, 2000, respectively.
The fair value for each option granted, providing the basis for the above pro forma disclosures, was determined
on the date of grant using the Black-Scholes option-pricing model. The following assumptions were used in
determining fair value through the model:
September 30, September 30,
2001 2000
----------------------------------------------------------------------------------------------------------
Expected life 7 years - 10 years 7 years - 10 years
Risk-free interest rate 4.7% - 6.1% 4.7% - 6.0%
Expected volatility 18% - 50% 17% - 38%
----------------------------------------------------------------------------------------------------------
The application of fair-value accounting to calculate the pro forma disclosures above is not an indication of
future income statement effects. The pro forma disclosures do not reflect the effect of fair-value accounting on
stock-based compensation awards granted prior to 1995.
Note 10. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems for which each participant provides
its own financing. SCE's share of expenses for each project is included in the consolidated statements of income.
The investment in each project as of September 30, 2001, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 41 $ 12 $ 1 60%
Pacific Intertie 230 83 8 50%
Generating stations:
Four Corners Units 4 and 5 (coal) 463 361 4 48%
Mohave (coal) 331 245 2 56%
Palo Verde (nuclear)(1) 1,630 1,585 18 16%
San Onofre (nuclear)(1) 4,278 4,152 23 75%
-------------------------------------------------------------------------------------------------------------------
Total $ 6,973 $ 6,438 $ 56
-------------------------------------------------------------------------------------------------------------------
(1) Regulatory assets, which were written off as a charge to earnings as of December 31, 2000, as discussed
in Notes 1 and 3.
Page 33
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Commitments
Leases
SCE has operating leases, primarily for vehicles with varying terms, provisions and expiration dates.
Estimated remaining commitments for noncancelable leases at September 30, 2001, were:
Year ended December 31, In millions
-------------------------------------------------------------------------------------------------
2001 $ 4
2002 14
2003 12
2004 11
2005 8
Thereafter 19
-------------------------------------------------------------------------------------------------
Total $ 68
-------------------------------------------------------------------------------------------------
Nuclear Decommissioning
Decommissioning is estimated to cost $2.2 billion in current-year dollars, based on site-specific studies
performed in 1998 for San Onofre and Palo Verde. Changes in the estimated costs, timing of decommissioning, or
the assumptions underlying these estimates could cause material revisions to the estimated total cost to
decommission in the near term. SCE estimates that it will spend approximately $8.6 billion through 2060 to
decommission its nuclear facilities. This estimate is based on SCE's current dollar decommissioning costs,
escalated at rates ranging from 0.3% to 10.0% (depending on the cost element) annually. SCE expects these costs
to be funded from independent decommissioning trusts, which receive contributions of approximately $25 million
per year. SCE estimates annual after-tax earnings on the decommissioning funds of 3.9% to 4.9%.
SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the Nuclear
Regulatory Commission. The operating licenses expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028
for the Palo Verde units. SCE could decommission San Onofre Units 2 and 3 as early as 2013. Palo Verde is
planned to be decommissioned at the end of its operating licenses. Decommissioning costs, which are recovered
through nonbypassable customer rates over the term of each nuclear facility's operating license, are recorded as
a component of depreciation expense.
Decommissioning of San Onofre Unit 1 (shut down in 1992 per CPUC agreement) started in 1999 and will continue
through 2008. All of SCE's San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning
trust funds.
Decommissioning expense was $17 million, $44 million and $22 million for the three, nine and twelve months ended
September 30, 2001, respectively, and $67 million, $128 million and $148 million for the three, nine and twelve
months ended September 30, 2000. The accumulated provision for decommissioning, excluding San Onofre Unit 1, was
$1.4 billion at September 30, 2001, at December 31, 2000, and at September 30, 2000. The estimated costs to
decommission San Onofre Unit 1 (approximately $317 million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts, which, together with accumulated
earnings, will be utilized solely for decommissioning.
Page 34
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Trust investments (cost basis) include:
Maturity September 30, December 31, September 30,
In millions Dates 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Municipal bonds 2002 - 2029 $ 510 $ 548 $ 629
Stocks -- 598 531 519
U.S. government issues 2004 - 2029 344 421 413
Short-term and other 2001 265 220 213
-------------------------------------------------------------------------------------------------------------------
Total $ 1,717 $ 1,720 $ 1,774
-------------------------------------------------------------------------------------------------------------------
Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated
provision for decommissioning. Net earnings were less than $1 million for the three months ended September 30,
2001; the fund incurred losses of $16 million and $56 million for the nine and twelve months ended September 30,
2001, respectively, and earnings were $47 million, $78 million and $87 million for the three, nine and twelve
months ended September 30, 2000, respectively. Proceeds from sales of securities (which are reinvested) were
$470 million, $1.8 billion and $2.9 billion for the three, nine and twelve months ended September 30, 2001,
respectively, and $1.0 billion, $3.5 billion and $4.3 billion for the three, nine and twelve months ended
September 30, 2000, respectively. Approximately 91% of the trust fund contributions were tax-deductible.
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. Certain SCE
gas and coal fuel contracts require payment of certain fixed charges whether or not gas or coal is delivered.
SCE has power-purchase contracts with certain qualifying facilities (cogenerators and small power producers) and
other utilities. These contracts provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There are no requirements to make
debt-service payments. In an effort to replace higher-cost contract payments with lower-cost replacement power,
SCE has entered into agreements to end its contract obligations with certain qualifying facilities. The buyout
agreements are reported as power-purchase contracts on the balance sheets.
SCE has unconditional purchase obligations for part of a power plant's generating output, as well as firm
transmission service from another utility. Minimum payments are based, in part, on the debt-service requirements
of the provider, whether or not the plant or transmission line is operable. SCE's minimum commitment under both
contracts is approximately $159 million through 2017. The purchased-power contract is expected to provide
approximately 5% of current or estimated future operating capacity, and is reported as power purchase contracts
(approximately $31 million). The transmission service contract requires a minimum payment of approximately
$6 million a year.
Certain minimum commitments for the years 2001 through 2005 are estimated below:
In millions 2001 2002 2003 2004 2005
------------------------------------------------------------------------------------------------------------
Fuel supply contracts $142 $109 $109 $106 $111
Purchased-power capacity payments 596 629 629 627 624
------------------------------------------------------------------------------------------------------------
Page 35
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. 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.
Energy Crisis Issues
In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International. As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections. The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001. A consolidated class
action complaint was filed on August 3, 2001. On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim. The motion is scheduled for hearing on December 3, 2001. SCE believes
that its current and past accounting for the TRA undercollections and related items is appropriate and in
accordance with accounting principles generally accepted in the United States.
Lawsuits have been filed against SCE by various QFs, including geothermal, wind and cogeneration suppliers. The
lawsuits are seeking payments of at least $833 million for energy and capacity supplied to SCE under QF
contracts, and in some cases for additional damages as well. Many of these QF lawsuits also seek an order
allowing the suppliers to stop providing power to SCE so that they may sell the power to other purchasers. The
state court cases have been coordinated before a single trial judge. SCE has reached agreements with QFs
representing about 97% of the QF renewable and cogeneration capacity provided to SCE. The agreements provide for
stays of litigation, payments to the QFs upon occurrence of specified conditions, modifications in some cases to
the contract prices going forward, releases and dismissals of the litigation upon payment by SCE. In light of
the litigation settlement with the CPUC, SCE is seeking to negotiate amendments to the agreements with QFs.
SCE cannot predict the outcome of any of these matters.
Environmental Protection
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 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 deferred credits) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 42 identified sites is $114 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
Page 36
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $269 million. The upper limit of this
range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible
outcomes. SCE has sold all of its gas-fueled generation plants and has retained some liability associated with
the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $45 million of its
recorded liability, through an incentive mechanism. 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 the costs incurred at its remaining sites to be recovered through customer rates. SCE has
recorded a regulatory asset of $60 million for its estimated minimum environmental-cleanup costs expected to be
recovered through customer rates.
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 now be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation expenditures in each
of the next several years are expected to range from $10 million to $25 million. Recorded expenditures for the
twelve months ended September 30, 2001, were $20 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 and, based upon the CPUC's regulatory treatment of environmental-cleanup
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.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of San
Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance
is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor
licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed
the primary insurance at that plant site. Federal regulations require this secondary level of financial
protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective
June 1994. The maximum deferred premium for each nuclear incident is $88 million per reactor, but not more than
$10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE
could be required to pay a maximum of $176 million per nuclear incident. However, it would have to pay no more
than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are
needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability
limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims.
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.
Page 37
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Primarily, 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 $18 million per year. This
amount is expected to increase to $35 million on November 15, 2001. Insurance premiums are charged to operating
expense.
Spent Nuclear Fuel
Under federal law, the DOE is responsible for the selection and development of a facility for disposal of spent
nuclear fuel and high-level radioactive waste. Such a facility was to be in operation by January 31, 1998.
However, the DOE did not meet its obligation. It is not certain when the DOE will begin accepting spent nuclear
fuel from San Onofre or from other nuclear power plants.
SCE, as operating agent, has primary responsibility for the interim storage of its spent nuclear fuel at San
Onofre. Current capability to store spent fuel is estimated to be adequate through 2005. SCE is conducting
engineering studies and evaluating the cost of constructing an interim fuel storage facility for Units 2 and 3.
The development and construction of an interim fuel storage facility for Unit 1 is in progress as part of the
decommissioning project. Costs for the interim fuel storage facility for Unit 1 are fully funded from the
decommissioning trust.
Extended delays by the DOE could lead to consideration of costly alternatives involving siting and environmental
issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through
April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to
one mill per kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003 for Unit 2, and until 2004 for
Units 1 and 3. Arizona Public Service Company, operating agent for Palo Verde, expects that an interim fuel
storage facility currently under construction will be completed in 2002.
Page 38
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
California's investor-owned electric utilities, including Southern California Edison Company (SCE), have been
facing a crisis resulting from deregulation of the generation side of the electric industry through legislation
enacted by the California Legislature and decisions issued by the California Public Utilities Commission (CPUC).
Under the legislation and CPUC decisions, prices for wholesale purchases of electricity from power suppliers are
set by markets while the retail prices paid by utility customers for electricity delivered to them remain frozen
at June 1996 levels except for the 10% residential rate reduction starting in 1998 and the 4(cent)-per-kWh surcharge
effective in 2001. See further discussion of the CPUC rate increases in Rate Stabilization Proceedings.
Beginning in May 2000, SCE's costs to obtain power (at wholesale electricity prices) for resale to its customers
substantially exceeded revenue from frozen rates. The shortfall was accumulated in the transition revenue
account (TRA), a CPUC-authorized regulatory asset, prior to the retroactive transfer of the TRA balance to the
transition cost balancing account (TCBA), as discussed below. SCE has borrowed significant amounts of money to
finance its electricity purchases, creating a severe liquidity crisis at SCE.
On October 5, 2001, a federal district court in California entered a stipulated judgment approving an October 2,
2001, agreement between the CPUC and SCE to settle a lawsuit. SCE expects that the settlement agreement and the
CPUC actions contemplated in the agreement should enable SCE to recover its previously undercollected power
procurement costs and repay its outstanding overdue obligations. According to the terms of the settlement
agreement, in the fourth quarter of 2001, it is expected that SCE will establish (retroactive to August 31, 2001)
a $3.6 billion account for these previously incurred procurement costs which will be called the
procurement-related obligations account (PROACT). During a period beginning on September 1, 2001, and ending on
the earlier of the date that SCE has recovered all of its procurement-related obligations recorded in the PROACT
or December 31, 2005, SCE will apply to the PROACT the difference between SCE's revenue from retail electric
rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric
rates. The settlement also calls for the end of the TCBA mechanism as of August 31, 2001, and continuation of
the rate freeze (including surcharges) until the earlier of December 31, 2003, or the date that SCE recovers the
account balance. If SCE has not recovered the entire balance by the end of 2003, the remaining balance will be
amortized in retail rates for up to an additional two years. For further details on the settlement with the
CPUC, see CPUC Litigation Settlement Agreement. On October 26, 2001, a California consumer group asked a federal
court of appeals for a stay of judgment pending appeal of the federal district court's judgment approving the
settlement. The group alleged that it was denied due process and that the CPUC had no authority to agree with
SCE to violate the statutory rate freeze. On October 30, 2001, the court of appeals granted a temporary stay,
and instructed the consumer group to return to district court to argue the merits of the stay. On November 9,
2001, the district court denied the consumer group's request for a stay. The consumer group indicated that it
intends to ask the court of appeals for a stay of judgment pending appeal. If the stay of judgment pending
appeal is granted, or the settlement is successfully challenged on appeal, the ability of SCE and the CPUC to
implement the settlement agreement would be affected adversely, which in turn would have an adverse effect on
SCE's ability to restore its financial condition, repay its creditors and avoid an involuntary bankruptcy petition.
Accounting principles generally accepted in the United States permit SCE to defer costs and record regulatory
assets if those costs are determined to be probable of recovery in future rates. When SCE determines that
regulatory assets, such as the TRA and the TCBA, are no longer probable of recovery through future rates, they
are written off. The TCBA is a regulatory balancing account that tracks the recovery of generation-related
transition costs, including stranded investments. SCE assessed the probability of recovery of the undercollected
costs that were previously recorded in the TCBA in light of the CPUC's March 27, 2001, and April 3, 2001,
decisions, including the retroactive transfer of balances from SCE's TRA to its TCBA and related changes that are
discussed in more detail in Rate Stabilization Proceedings. These decisions and other regulatory and legislative
actions did not meet SCE's prior expectation that the CPUC would provide adequate cost recovery mechanisms. As a
result, SCE's financial results for the year ended December 31, 2000, included an after-tax charge of
approximately
Page 39
$2.5 billion ($4.2 billion on a pre-tax basis), reflecting a write-off of the TCBA and net regulatory assets to
be recovered through the TCBA mechanism, as of December 31, 2000. Transition costs in excess of transition
revenue were also incurred during the first six months of 2001, resulting in a charge against earnings in the
amount of $724 million (after tax) through June 30, 2001. This resulted in further material declines in reported
common shareholder's equity, particularly in light of the CPUC's failure to provide SCE with sufficient rate
increases to cover its ongoing costs and obligations during that period.
The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the
significantly negative effect on the financial condition of SCE of undercollections recorded in the TRA and TCBA,
the current status of the undercollections, the impact of the CPUC's March 27, 2001, decisions and related
matters, and the expected resolution of the current crisis through implementation of the CPUC litigation
settlement agreement.
Results of Operations
Earnings
SCE earned $651 million and $81 million, respectively, for the three and nine months ended September 30, 2001,
and incurred a loss of $2.4 billion for the twelve months ended September 30, 2001. SCE's third quarter earnings
included recovery of $518 million (after tax) of previously undercollected transition costs during the third
quarter of 2001 due to CPUC-approved surcharges that were billed beginning in June 2001. The year-to-date
earnings and twelve-months-ended loss reflect $724 million (after tax) of transition costs in excess of
transition revenue during the first six months of 2001, partially offset by the $518 million overcollection
during the third quarter of 2001. For financial reporting purposes, these undercollected or overcollected costs
are no longer accumulated in the TCBA. The twelve-months-ended loss also included a write-off of the TCBA and
other generation-related regulatory assets and liabilities in the amount of $2.5 billion (after tax) as of
December 31, 2000.
Accounting principles generally accepted in the United States require SCE at each financial statement date to
assess the probability of recovering its regulatory assets through a regulatory process. Based on the rules
arising from the CPUC's March 27, 2001, rate stabilization decision, the $4.5 billion TRA undercollection as of
December 31, 2000, and the coal and hydroelectric balancing account overcollections were reclassified, and the
TCBA balance was recalculated to be a $2.9 billion undercollection (see further discussion of the CPUC rate
increase in the Rate Stabilization Proceeding section and the components of the TCBA undercollection in the
Status of Transition and Power-Procurement Cost Recovery section of Regulatory Environment). As a result, SCE
was unable to conclude that, under applicable accounting principles, the $2.9 billion TCBA undercollection (as
recalculated above) and $1.3 billion (book value) of other net regulatory assets that were to be recovered
through the TCBA mechanism by the end of the rate freeze, were probable of recovery through the rate-making
process as of December 31, 2000. As a result, SCE's December 31, 2000, income statement included a $4.0 billion
charge to provisions for regulatory adjustment clauses and a $1.5 billion net reduction in income tax expense, to
reflect the $2.5 billion (after tax) write-off.
As stated above, SCE earned $651 million and $81 million, and recorded a loss of $2.4 billion, respectively, for
the three, nine and twelve months ended September 30, 2001, compared with earnings of $172 million, $441 million
and $582 million, respectively, for the same periods in 2000. Excluding the $518 million (after tax) recovery of
previously undercollected transition costs, SCE's third quarter 2001 earnings were $133 million, down $39 million
from the prior-year period. The quarterly decrease was mainly due to higher interest expense resulting from
SCE's deteriorated financial condition and lower kWh sales. Excluding the $205 million (after tax) of net
undercollected transition costs expensed in 2001, SCE would have earned $286 million for the year-to-date period
ended September 30, 2001. The $155 million decrease for the nine-month period ended September 30, 2001, from the
same period in 2000, was mostly due to lower earnings related to the February 2001 fire and resulting outage at
San Onofre, higher interest expense and lower kWh sales, partially offset by lower operating and maintenance
costs. Excluding the $205 million (after tax) of net undercollected transition costs expended in 2001 and the
Page 40
$2.5 billion (after tax) December 31, 2000, write-off, SCE would have earned $317 million for the twelve months
ended September 30, 2001. Excluding the $15 million one-time tax benefit SCE recorded in fourth quarter 1999 due
to an Internal Revenue Service ruling, SCE's earnings for the twelve months ended September 30, 2000, were $567
million. The $250 million decrease (excluding the items mentioned above) for the twelve months ended September
30, 2001, from the prior-year period, was mainly the result of the outage at San Onofre Unit 3, higher interest
expense and lower kWh sales, partially offset by lower operating and maintenance costs.
Operating Revenue
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider (thus becoming direct access customers) or continue to have SCE purchase power on their
behalf. Most direct access customers were billed by SCE, but given a credit for the generation portion of their
bills. On September 20, 2001, the CPUC suspended the ability of retail customers to select alternative providers
of electricity until the California Department of Water Resources (CDWR) stops buying power for retail customers.
During 2000, as a result of the power shortage in California, SCE's customers on interruptible rate programs
(which provide for a lower generation rate with a provision that service can be interrupted if needed, with
penalties for noncompliance) were asked to curtail their electricity usage at various times. As a result of
noncompliance with SCE's requests, those customers were assessed significant penalties. On January 26, 2001, the
CPUC waived the penalties assessed to noncompliant customers after October 1, 2000, until the interruptible
programs can be reevaluated.
Operating revenue increased for the three months ended September 30, 2001, and decreased for the nine and twelve
months ended September 30, 2001, compared to the same periods in 2000. Because SCE no longer supplies its
customers with all of their electricity needs (since mid-January 2001), operating revenue was reduced by $664
million, $1.4 billion and $1.4 billion, respectively, for the three, nine and twelve months ended September 30,
2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by the CDWR or
through the Independent System Operator (ISO) on behalf of SCE's customers (beginning January 18, 2001) are being
remitted to the CDWR and are not considered revenue to SCE. See CDWR Power Purchases discussion. The quarterly
operating revenue increase was primarily due to the effects of the 4(cent)-per-kWh (1(cent)in January and 3(cent)in June)
surcharge effective in 2001, as well as the credit given to direct access customers during third quarter 2000.
The direct access credits decreased during the third quarter of 2001 due to a fewer number of direct access
customers in 2001, as well as a lower basis used in calculating the amount of the credit. The lower basis in
2001 relates to SCE's frozen rates, as opposed to the California Power Exchange (PX) market price, which was the
basis in 2000. These increases were partially offset by an 8% decrease in retail sales volume. The year-to-date
and twelve-months-ended decreases in operating revenue were the result of a decrease in retail sales volume
primarily attributable to conservation efforts, as well as a decrease in revenue related to operation and
maintenance services. SCE is no longer providing these services to the independent power companies who now own
the generating stations SCE sold in 1998. The effect of the reduced credits given to direct access customers
partially offsets the decreases discussed above for the year-to-date and twelve-months-ended periods.
More than 94% of operating revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale
rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warmer weather during the summer months, operating revenue during the third quarter of each year is
significantly higher than other quarters.
Operating Expenses
Fuel expense increased for the nine months ended September 30, 2001, compared with the same period in 2000,
primarily due to a fuel-related refund resulting from a settlement with another utility recorded in the second
quarter of 2000.
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Purchased-power expense decreased for the three months ended September 30, 2001, and increased for the nine and
twelve months ended September 30, 2001, compared to the same periods in 2000. The quarterly decrease was
primarily due to the absence of purchases from the PX and ISO in 2001, as well as a reduction in qualifying
facilities (QF) power costs. In December 2000, the FERC eliminated the requirement that SCE buy and sell all
power through the PX and ISO. Due to SCE's noncompliance with the PX's tariff requirement for posting collateral
for all transactions in the day-ahead and day-of markets as a result of the downgrade in its credit rating, the
PX suspended SCE's market trading privileges effective mid-January 2001. See further discussion of SCE's
liquidity crisis in Financial Condition. These quarterly decreases were partially offset by an increase related
to interutility contracts. The year-to-date and twelve-months-ended increases were the result of increased
purchased-power expenses related to QFs, bilateral contracts and interutility contracts, partially offset by the
absence of PX/ISO purchased-power expense in 2001. See Purchased Power table in Note 1 to the Consolidated
Financial Statements. See further discussion in CDWR Power Purchases.
Prior to April 1998, federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs
at CPUC-mandated prices even though energy and capacity prices under many of these contracts are generally higher
than other sources. These contracts expire on various dates through 2025. Purchased-power expense related to
QFs decreased for the three months ended September 30, 2001, and increased for the nine and twelve months ended
September 30, 2001, compared to the year-earlier periods. The decrease is primarily due to lower priced natural
gas, which impacts the short-run avoided cost factor of the QF contracts. The increases were primarily due to
the short-run avoided cost factor of the QF contracts causing a significant increase in the payments to QFs. The
twelve-months-ended increase was partially offset by a fourth quarter 2000 contract adjustment, as well as the
terms in some of the QF contracts reverting to lower prices. The increases related to bilateral contracts were
the result of SCE not having these contracts in 2000. The quarterly decrease in purchased-power expense related
to interutility contracts, as well as the year-to-date and twelve-months-ended increases related to interutility
contracts were volume-driven.
PX/ISO purchased-power expense increased significantly between May 2000 and mid-January 2001, due to increased
demand for electricity in California, dramatic price increases for natural gas (a key input of electricity
production), and structural problems within the PX and ISO.
Provisions for regulatory adjustment clauses increased for the three, nine and twelve months ended September 30,
2001, compared to the year-earlier periods. The increases resulted from SCE no longer accumulating
undercollected transition costs in the TCBA for financial reporting purposes. The twelve-months-ended increase
also reflects a $4.0 billion charge to the provisions related to the write-off of regulatory assets and
liabilities as of December 31, 2000, as well as adjustments to reflect potential regulatory refunds related to
the outcome of the CPUC's reevaluation of the operation of the interruptible rate programs. See further
discussion of the write-off in the Earnings section. The increases were partially offset by undercollections
related to the administration of energy conservation programs and other public benefits programs in 2001 and
undercollections related to the coal generation and hydroelectric balancing accounts in 2001.
Depreciation, decommissioning and amortization expense decreased for the three, nine and twelve months ended
September 30, 2001, compared to the prior-year periods, primarily due to a decrease in SCE's nuclear investment
amortization expense. SCE's unamortized nuclear investment regulatory asset was included in the December 31,
2000, write-off.
Other Income and Deductions
Interest and dividend income decreased for the three and nine months ended September 30, 2001, and increased for
the twelve months ended September 30, 2001, compared to the year-earlier periods. The decreases were primarily
due to lower balancing account undercollections during the third quarter of 2001.
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The increase was primarily due to an overall higher cash balance as SCE conserves cash due to its liquidity
crisis.
Other nonoperating income decreased for the nine and twelve months ended September 30, 2001. The year-to-date
decrease was primarily due to the gains on sales of equity investments during second quarter 2000 and the result
of CPUC-approved shareholder incentives related to QF contract restructurings in first quarter 2000. The
twelve-months-ended decrease was mainly the result of lower earnings from energy conservation programs, lower
earnings from life insurance investments for executives and lower gains on the sales of equity investments.
Interest expense - net of amounts capitalized increased for the three, nine and twelve months ended September 30,
2001, compared to the year-earlier periods. The increases were primarily due to additional long-term debt and
higher short-term debt balances. Higher interest expense resulting from balancing account overcollections also
contributed to the twelve-months-ended increase.
Other nonoperating deductions decreased for the three, nine and twelve months ended September 30, 2001, compared
to the same periods in 2000. The decreases were primarily due to lower accruals for regulatory matters in 2001.
Income Taxes
Income taxes increased for the three months ended September 30, 2001, and decreased for the nine and twelve
months ended September 30, 2001, compared to the year-earlier periods. The quarterly increase was mainly due to
the recovery of previously undercollected transition costs. The year-to-date and twelve-months-ended decreases
reflect a $203 million income tax benefit arising from transition costs in excess of transition revenue during
the nine months of 2001. The twelve-months-ended-decrease also reflects the $1.5 billion income tax benefit
related to the $2.5 billion (after tax) write-off as of December 31, 2000, of regulatory assets and liabilities.
Absent the tax benefits discussed above, the decreases in income tax expense were the result of lower pre-tax
income.
Financial Condition
SCE's liquidity has been primarily affected by power purchases, debt maturities, access to capital markets,
dividend payments and capital expenditures. Capital resources include cash from operations and external
financings. As a result of SCE's financial condition (further discussed in Liquidity Crisis), at September 30,
2001, the fair market value of $531 million of its short-term debt was approximately 80% of its carrying value.
Liquidity Crisis
Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001. This resulted in
undercollections in the TRA and TCBA. Undercollections, coupled with SCE's anticipated near-term capital
requirements (detailed in the Cash Flows from Investing Activities section of Financial Condition) and the
adverse reaction of the credit markets to regulatory uncertainty regarding SCE's ability to recover its power
procurement costs, materially and adversely affected SCE's liquidity. As a result of its liquidity crisis, SCE
has taken and is taking steps to conserve cash so that it can continue to provide service to its customers. As a
part of this process, beginning in January 2001, SCE suspended payments of certain obligations for principal and
interest on outstanding debt and for purchased power. As of October 31, 2001, SCE had $3.3 billion in
obligations that were unpaid and overdue including: (1) $940 million to the PX or ISO; (2) $1.2 billion to QFs;
(3) $231 million in PX energy credits for energy service providers; (4) $531 million of matured commercial paper;
and (5) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the
energy crisis. As applicable, unpaid obligations will continue to accrue interest.
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SCE's failure to pay when due the principal amount of the 5-7/8% and 6-1/2% senior unsecured notes constituted a
default on each series, entitling those noteholders to exercise their remedies. Such failure and the failure to
pay commercial paper when due could also constitute an event of default on all the other series of senior
unsecured notes (totaling $2.2 billion of outstanding principal) if the trustee or holders of 25% in principal
amount of the notes give a notice demanding that the default be cured, and SCE does not cure the default within
30 days. Such failures are also an event of default under SCE's credit facilities and bilateral credit
agreements, entitling those lenders to exercise their remedies including potential acceleration of the
outstanding borrowings of $1.65 billion. If a notice of default is received, SCE could cure the default only by
paying $931 million in overdue principal to holders of commercial paper and the 5-7/8% and 6-1/2% senior
unsecured notes. Making such payment would further impact SCE's liquidity and could result in a termination of
the forbearance agreements with bank lenders discussed below. If a notice of default were received and not
cured, and the trustee or noteholders were to declare an acceleration of the outstanding principal amount of the
senior unsecured notes, SCE would not have the cash to pay the obligation and could be forced to declare
bankruptcy. As a result of the default on the two series of senior unsecured notes, SCE's other senior unsecured
notes and subordinated debentures ($1.85 billion) have been classified as due within one year in the accompanying
financial statements. If SCE is found responsible for purchases of power by the ISO for delivery to SCE's
customers on or after January 18, 2001, SCE's unpaid obligations as of October 31, 2001, could increase by as
much as $1.6 billion. This amount could increase or decrease depending on CPUC or FERC decisions regarding
payments and refunds. See additional discussion in CDWR Power Purchases. These stated amounts representing past
or future obligations for purchased power, PX energy credits and certain other items include amounts that are in
dispute, and the publishing of these amounts is not an admission by SCE of liability for any disputed amounts.
Subject to certain conditions, the bank lenders under SCE's credit facilities totaling $1.65 billion agreed to
forbear until March 29, 2002, from exercising remedies, including acceleration of borrowed amounts, against SCE
with respect to the event of default arising from the failure to pay the 5-7/8% and 6-1/2% senior unsecured notes
and commercial paper when due. Under the forbearance agreements, the maturity date of the $200 million
short-term bank credit facility and the $400 million in bilateral credit agreements has been extended until
March 29, 2002. The maturity date of the $1.05 billion, five-year bank credit facility is May 22, 2002. At
October 31, 2001, SCE had estimated cash reserves of approximately $2.7 billion (after deducting $530 million of
designated funds), which was approximately $650 million less than its outstanding unpaid obligations (discussed
above) not including its credit facilities that are subject to forbearance agreements, and overdue amounts of
preferred stock dividends (see below). As of March 31, 2001, SCE resumed payment of interest on its debt
obligations. However, since June 30, 2001, SCE has deferred the interest payments on its quarterly income debt
securities (subordinated debentures), as allowed by the terms of the securities. All interest in arrears must be
paid in full at the end of the deferral period. The settlement agreement with the CPUC, if implemented, is
expected to allow SCE to obtain financing which, combined with an increase in cash reserves, would give SCE
sufficient funds to pay all of its past due obligations by the end of first quarter 2002.
On March 27, 2001, the CPUC issued decisions ordering SCE and other investor-owned utilities to pay QFs for power
deliveries on a going forward basis, commencing with April 2001 deliveries, and on the California Procurement
Adjustment (CPA) calculation including the approval of a 3(cent)-per-kWh rate increase. One of the CPUC decisions
also modified the formula used in calculating payments to QFs by substituting natural gas index prices based on
deliveries at the Oregon border rather than the index prices at the Arizona border. The changes apply to all
QFs, where appropriate, regardless of whether they use natural gas or other resources such as solar or wind.
In light of SCE's liquidity crisis, its Board of Directors has not declared quarterly common stock dividends to
SCE's parent, Edison International, since September 2000. Also, SCE's Board has not declared the regular
quarterly dividends for any of SCE's cumulative preferred stock in 2001. As of October 31, 2001, SCE's preferred
stock dividends in arrears were $17 million. Dividends are additionally restricted as detailed in the CPUC
Litigation Settlement discussion.
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SCE has implemented other cost-cutting measures such as freezing new hires and postponing certain capital
expenditures. SCE's current cost-cutting measures are intended to allow it to continue to operate while efforts
to restore its creditworthiness (such as that contemplated in the CPUC litigation settlement agreement) are
underway. See further discussion in Status of Transition and Power-Procurement Cost Recovery.
For additional discussion on the impact of California's energy crisis on SCE's liquidity, see Cash Flows from
Financing Activities. For a discussion on the settlement agreement with the CPUC to resolve SCE's crisis, see
CPUC Litigation Settlement Agreement.
The 2001 rate surcharges have allowed SCE's cash reserves (excluding designated funds) to grow by $1.0 billion
for the three-month period from July 31, 2001, to October 31, 2001. Unless the federal court of appeals issues a
stay of judgment pending appeal or the settlement is successfully challenged on appeal, SCE's litigation
settlement agreement with the CPUC is expected to allow SCE to obtain financing which, combined with SCE's
expected additional increases in cash reserves, should allow SCE to pay all of its past due obligations by the
end of first quarter 2002. Until these obligations are paid, resolution of SCE's liquidity crisis and its
ability to continue to operate outside of bankruptcy is uncertain. SCE's independent accountants' opinion on the
accompanying financial statements includes an explanatory paragraph which states that the issues associated with
the California energy crisis continue to raise substantial doubt about SCE's ability to continue as a going
concern.
Cash Flows from Operating Activities
Despite SCE's net income of $657 million and $98 million and a loss of $2.4 billion, respectively, for the three,
nine and twelve months ended September 30, 2001, net cash provided by operating activities was $1.0 billion, $2.3
billion and $2.2 billion, primarily due to SCE suspending payments for interest on outstanding debt, purchased
power beginning in January 2001 and other obligations. Cash provided by operating activities also reflects the
CPUC-approved surcharges (1(cent)per kWh in January and 3(cent)per kWh in June) that were billed in 2001.
Beginning with the first quarter 2001 calculation, the cash flow coverage of dividends is no longer meaningful
due to SCE's inability to pay dividends (discussed above in the Liquidity Crisis section).
Cash Flows from Financing Activities
At September 30, 2001, SCE had drawn on its entire credit lines of $1.65 billion. These unsecured lines of
credit have various expiration dates and, when available, can be drawn down at negotiated or bank index rates.
Under terms of executed forbearance agreements, the maturity date of SCE's $200 million, 364-day credit facility
and its $400 million bilateral credit agreements has been extended until March 29, 2002. Although SCE's
remaining $1.05 billion, five-year bank credit facility expires on May 22, 2002, it is also subject to a
forbearance agreement which expires on March 29, 2002.
Short-term debt is used to finance balancing account undercollections, fuel inventories and general cash
requirements, including purchased-power payments. Long-term debt is used mainly to finance capital
expenditures. External financings are influenced by market conditions and other factors. Because of the $2.5
billion charge to earnings as of December 31, 2000, SCE does not currently meet the interest coverage ratios that
are required for SCE to issue additional first mortgage bonds or preferred stock. In addition, because of its
liquidity and credit problems, SCE has been unable to obtain financing of any kind.
As a result of investors' concerns regarding the California energy crisis and its impact on SCE's liquidity and
overall financial condition, SCE had to repurchase $550 million of pollution-control bonds that could not be
remarketed in accordance with their terms. These bonds may be remarketed in the future if SCE's credit status
improves sufficiently. In addition, SCE has been unable to sell its commercial paper and other short-term
financial instruments.
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In January 2001, Fitch IBCA, Standard & Poor's and Moody's Investors Service lowered their credit ratings of SCE
to substantially below investment grade.
California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally,
the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International.
In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special
purpose entity. These notes were issued to finance the 10% rate reduction mandated by state law. The proceeds
of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as
transition property. Transition property is a current property right created by the restructuring legislation
and a financing order of the CPUC and consists generally of the right to be paid a specified amount from
nonbypassable rates charged to residential and small commercial customers. The rate reduction notes are being
repaid over 10 years through these nonbypassable residential and small commercial customer rates, which
constitute the transition property purchased by SCE Funding LLC. The remaining series of outstanding rate
reduction notes have scheduled maturities beginning in 2002 and ending in 2007, with interest rates ranging from
6.22% to 6.42%. The notes are secured by the transition property and are not secured by, or payable from, assets
of SCE or Edison International. SCE used the proceeds from the sale of the transition property to retire debt
and equity securities. Although, as required by accounting principles generally accepted in the United States,
SCE Funding LLC is consolidated with SCE and the rate reduction notes are shown as long-term debt in the
consolidated financial statements, SCE Funding LLC is legally separate from SCE. The assets of SCE Funding LLC
are not available to creditors of SCE or Edison International and the transition property is legally not an asset
of SCE or Edison International. Due to its credit rating downgrade in late 2000, in January 2001, SCE began
remitting its customer collections related to the rate-reduction notes on a daily basis.
Long-term debt maturities and sinking fund requirements for the five twelve month periods following September 30,
2001, are: 2002 - $947 million; 2003 - $572 million; 2004 - $1.4 billion; 2005 - $247 million; and 2006 -
$447 million. These projections assume no acceleration of payments arising from default. See further discussion
in Liquidity Crisis.
Preferred stock redemption requirements for the five twelve month periods following September 30, 2001, are:
2002 - $105 million; 2003 - $9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and plant and funding of nuclear
decommissioning trusts. Decommissioning costs are recovered in utility rates. These costs are expected to be
funded from independent decommissioning trusts that receive SCE contributions of approximately $25 million per
year. In 1995, the CPUC determined the restrictions related to the investments of these trusts. They are: not
more than 50% of the fair market value of the qualified trusts may be invested in equity securities; not more
than 20% of the fair market value of the trusts may be invested in international equity securities; up to 100% of
the fair market values of the trusts may be invested in investment grade fixed-income securities including, but
not limited to, government, agency, municipal, corporate, mortgage-backed, asset-backed, non-dollar, and cash
equivalent securities; and derivatives of all descriptions are prohibited. Contributions to the decommissioning
trusts are reviewed every three years by the CPUC. The contributions are determined from an analysis of
estimated decommissioning costs, the current value of trust assets and long-term forecasts of cost escalation and
after-tax return on trust investments. Favorable or unfavorable investment performance in a period will not
change the amount of contributions for that period. However, trust performance for the three years leading up to
a CPUC review proceeding will provide input into future contributions. SCE's costs to decommission San Onofre
Unit 1 are paid from the nuclear decommissioning trust funds. These withdrawals from the decommissioning trusts
are netted with the contributions to the trust funds in the Statements of Cash Flows.
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SCE's projected construction expenditures for 2001 are $687 million. This projection reflects SCE's cost-cutting
measures discussed above in the Liquidity Crisis section.
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in both energy prices and interest rates.
Additionally, natural gas is a key input for the prices that all QFs (including non-gas QFs) may charge to SCE.
SCE is exposed to changes in the spot market price for natural gas. SCE's risk management policy allows the use
of derivative financial instruments to manage its financial exposures, but prohibits the use of these instruments
for speculative or trading purposes.
SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as to finance capital expenditures. The nature
and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors. As a result of California's energy crisis, SCE has been
exposed to significantly higher interest rates, which has intensified its liquidity crisis (further discussed in
the Liquidity Crisis section of Financial Condition).
SCE does not believe that its short-term debt is subject to interest rate risk. However, SCE does believe that
the fair market value of its fixed-rate long-term debt is subject to interest rate risk.
Since April 1998, the price SCE paid to acquire power on behalf of customers was allowed to float, in accordance
with the 1996 electric utility restructuring law. Until May 2000, retail rates were sufficient to cover the cost
of power and other SCE costs. However, between May 2000 and June 2001, market power prices escalated, creating a
substantial gap between costs and retail rates. In response to the dramatically higher prices, the ISO and the
FERC have placed certain caps on the price of power (see further discussion in Wholesale Electricity Markets).
During the period when market power prices were escalating, SCE attempted to hedge a portion of its exposure to
increases in power prices. However, the CPUC approved a very limited amount of hedging during the period. In
November 2000, SCE began purchases of energy through bilateral forward contracts. At September 30, 2001, the
nominal value of SCE's bilateral forward contracts was $291 million. See further discussion of bilateral forward
contracts in Note 4 to the Consolidated Financial Statements. Under the terms of the CPUC settlement agreement,
SCE purchased $209 million in hedging instruments in October and November 2001 to hedge a majority of its gas
price exposure for 2002 and 2003.
In accordance with a new accounting standard for derivatives, on January 1, 2001, SCE recorded its block forward
contracts at fair value on the balance sheet. Because SCE has suspended payments for purchased power since
January 16, 2001, the PX sought to liquidate SCE's remaining block forward contracts. Before the PX could do so,
on February 2, 2001, the state seized the contracts, which at that time had an unrealized gain of approximately
$500 million. On September 20, 2001, a federal appeals court ruled that the governor of California acted
illegally when he seized the power contracts held by SCE. In conjunction with its settlement agreement with the
CPUC (discussed in CPUC Litigation Settlement Agreement), SCE has agreed to release any claim for compensation
against the state for these contracts. Due to its speculative grade credit ratings, SCE has been unable to
purchase additional bilateral forward contracts, and some of the existing contracts were terminated by the
counterparties.
In January 2001, the CDWR began purchasing power for delivery to utility customers. On March 27, 2001, the CPUC
issued a decision directing SCE, among other things, to immediately pay amounts owed to the CDWR for certain past
purchases of power for SCE's customers. See additional discussion of regulatory proceedings related to CDWR
activities in the Generation and Power Procurement section of Regulatory Environment.
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Regulatory Environment
SCE operates in a highly regulated environment and has an exclusive franchise within its service territory. SCE
has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to
provide just and reasonable rates. In the mid-1990s, state lawmakers and the CPUC initiated the electric
industry restructuring process. SCE was directed by the CPUC to divest the bulk of its generation portfolio.
Today, independent power companies own the divested generating plants. The electric industry restructuring plan
also instituted a multi-year freeze on the rates that SCE could charge its customers and transition cost recovery
mechanisms (as described in Status of Transition and Power-Procurement Cost Recovery) designed to allow SCE to
recover its stranded costs associated with generation-related assets. California's electric industry
restructuring statute included provisions to finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which allowed SCE to reduce rates by at least 10% to
these customers, effective January 1, 1998. These frozen rates (except for the surcharge effective in 2001) were
to remain in effect until the earlier of March 31, 2002, or the date when the CPUC-authorized costs for
utility-owned generation assets and obligations are recovered. However, between May 2000 and June 2001, the
prices charged by sellers of power escalated far beyond what SCE could charge its customers. As a result, SCE
has incurred $2.7 billion (after tax), or $4.6 billion on a pre-tax basis, in write-offs and net undercollected
transition costs during the past 12 months (see Earnings). As indicated below, implementation of the PROACT
mechanism and CPUC approval of SCE's Utility-Retained Generation (URG) application is expected to allow SCE to
recover substantially all of the $4.6 billion.
Generation and Power Procurement
During the rate freeze, recovery of generation-related transition costs has been tracked through the TCBA
mechanism. Revenue from generation-related operations was determined through the market and transition cost
recovery mechanisms, which included the nuclear rate-making agreements. During fourth quarter 2001, it is
expected that the TCBA will become inactive retroactive to September 1, 2001, and a $3.6 billion PROACT
regulatory asset will be created in accordance with the October 2001 settlement agreement with the CPUC. In
accordance with a state law passed in January 2001, SCE will continue to own its remaining generation assets,
which would be subject to cost-based ratemaking, through 2006 (see further discussion in URG Proceeding).
Through December 31, 2000, SCE had been recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return on investment. SCE's nuclear assets were earning an
annual rate of return on investment of 7.35%. However, due to the various unresolved regulatory and legislative
issues (as discussed in Status of Transition and Power-Procurement Cost Recovery), as of December 31, 2000, SCE
was no longer able to conclude that the $610 million balance of unamortized nuclear investment regulatory assets
was probable of recovery through the rate-making process. As a result, this balance was written off as a charge
to earnings at that time (see further discussion in Earnings). SCE requested in its URG application to recover
the unamortized cost of its nuclear investment regulatory asset over a ten-year period, retroactive to January 1,
2001. Should this application be approved, SCE expects to reestablish for financial reporting purposes its
unamortized nuclear investment and related flow-through taxes as regulatory assets, with a corresponding credit
to earnings.
The San Onofre incentive pricing plan authorizes a fixed rate of approximately 4(cent)per kWh generated for operating
costs including incremental capital costs, nuclear fuel and nuclear fuel financing costs. The San Onofre plan
started in April 1996 and ends in December 2003 for the incentive-pricing portion. The Palo Verde Nuclear
Generating Station's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel
financing costs, were subject to balancing account treatment. The Palo Verde plan started in January 1997 and
was to end in December 2001. The benefits of operation of the San Onofre units and the Palo Verde units were
required to be shared equally with ratepayers beginning in 2004 and 2002, respectively. In a June 2001 decision,
the CPUC granted SCE's request to eliminate the San Onofre post-2003 benefit sharing mechanism based on
compliance with a recently enacted state law. In a
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September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde post-2001 benefit sharing
mechanism and continue the current rate treatment for Palo Verde, including the continuation of the existing
nuclear incentive procedure with a 5(cent)per kWh cap on replacement power costs, until resolution of SCE's General
Rate Case or further CPUC action. Beginning January 1, 1998, both the San Onofre and Palo Verde rate-making
plans became part of the TCBA mechanism. These rate-making plans and the TCBA mechanism were to continue for
rate-making purposes at least through the end of the rate freeze period. However, in its URG application, SCE
proposed to move the recovery of nuclear costs to another balancing account mechanism (see discussion in URG
Proceeding).
CPUC Litigation Settlement Agreement
In November 2000, SCE filed a lawsuit against the CPUC in federal court in California, seeking a ruling that SCE
is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with
the FERC. By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought
implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's
related financial and liquidity problems. On October 5, 2001, a federal district court in California entered a
stipulated judgment approving an October 2, 2001, agreement between the CPUC and SCE to settle the pending
lawsuit.
Key elements of the settlement agreement include the following items:
o The CPUC will establish an account called the PROACT, as of September 1, 2001, which will have an
opening balance equal to the amount of SCE's procurement-related liabilities as of August 31, 2001
(approximately $6.4 billion), less SCE's cash and cash equivalents as of that date (approximately
$2.5 billion), and less $300 million.
o During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has
recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will
apply to the PROACT, on a monthly or other basis established by the CPUC, the difference between SCE's
revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC
to recover in retail electric rates. Unrecovered obligations in the PROACT will accrue interest from
September 1, 2001.
o The parties agree that SCE will recover in retail electric rates its procurement-related obligations in
the PROACT, with interest, by December 31, 2005. Subject to certain adjustments, the CPUC will maintain
current rates (including surcharges) in effect until December 31, 2003, or, if earlier, until the date that
SCE recovers the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003,
the unrecovered balance will be amortized for up to an additional two years. The parties currently project
that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will
likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior
to the end of 2003.
o If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
procurement-related obligations, the parties will work together to achieve the securitization. Proceeds of
any securitization will be credited to the PROACT when they are actually received.
o During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed
by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.
o SCE intends to apply for CPUC approval to incur up to $250 million of recoverable costs to acquire financial
instruments and engage in other transactions intended to hedge fuel cost risks associated with SCE's
retained generation assets and power purchase contracts with qualifying facilities and
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other utilities. The CPUC indicated that it will schedule proceedings reasonably promptly and consider
SCE's application on an expedited basis.
o SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations
in the PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-related
obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends,
and the CPUC will not unreasonably withhold its consent.
o To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's
next general rate case, SCE may make capital expenditures above the level contained in current rates, up to
$900 million per year, which will be treated as recoverable costs.
o Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General
to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses
to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of
California or its agencies against the same adverse parties. During the recovery period discussed above,
refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the
PROACT.
The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of
SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.
The settlement agreement states that the CPUC shall adopt such decisions or orders it deems necessary to
implement and carry out the provisions of the agreement, with the understanding that the agreement and stipulated
judgment shall be binding and irrevocable upon the parties. SCE expects that these implementing decisions or
orders will be issued during fourth quarter 2001.
The minimum beginning balance of the PROACT, as verified by the CPUC, is calculated as follows:
In millions
---------------------------------------------------------------------------------------------
PX or ISO $ 924
QFs 1,219
PX energy credits 236
Imbalance energy (CDWR) 383
Ancillary services for resale cities 30
---------------------------------------------------------------------------------------------
Total past due bills 2,792
Credit facilities 1,298
Bilateral credit facilities 415
Defaulted commercial paper 563
Floating rate notes due May 2002 313
Variable rate notes due November 2003 1,043
---------------------------------------------------------------------------------------------
Total procurement-related liabilities 6,424
Less: Cash and cash equivalents on hand (2,547)
Less: Amount stipulated in agreement (300)
---------------------------------------------------------------------------------------------
Net PROACT balance as of August 31, 2001 $ 3,577
---------------------------------------------------------------------------------------------
On October 26, 2001, a California consumer group asked a federal court of appeals for a stay of judgment pending
appeal of the federal district court's judgment approving the settlement. The group alleged that it was denied
due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze. On
October 30, 2001, the court of appeals granted a temporary stay, and instructed the
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consumer group to return to district court to argue the merits of the stay. On November 9, 2001, the district
court denied the consumer group's request for a stay. The consumer group indicated that it intends to ask the
court of appeals for a stay of judgment pending appeal. If the stay of judgment pending appeal is granted, or
the settlement is successfully challenged on appeal, the ability of SCE and the CPUC to implement the settlement
agreement would be affected adversely, which in turn would have an adverse effect on SCE's ability to restore its
financial condition, repay its creditors and avoid an involuntary bankruptcy petition.
CDWR Power Purchases
In accordance with an emergency order signed by the Governor, the CDWR began making emergency power purchases for
SCE's customers on January 18, 2001. Amounts SCE bills to and collects from its customers for electric power
purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not considered
revenue to SCE. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law.
AB 1X authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to
retail customers being served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.
On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity (based on rates in effect on January 5, 2001),
for each kWh the CDWR sells to SCE's customers. The CPUC determined that the generation-related retail rate
should be equal to the total bundled electric rate (including the 1(cent)-per-kWh temporary surcharge adopted by the
CPUC on January 4, 2001) less certain nongeneration-related rates or charges. For the period January 19 through
January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277(cent)per kWh for power delivered to SCE's
customers. The CPUC determined that the applicable rate component is 7.277(cent)per kWh (which increased to 10.277(cent)
per kWh for electricity delivered after March 27, 2001, due to the 3(cent)-surcharge discussed in Rate Stabilization
Proceeding), for electricity delivered by the CDWR to SCE's retail customers after February 1, 2001, until more
specific rates are calculated. The CPUC ordered SCE to pay the CDWR within 45 days after the CDWR supplies power
to retail customers, subject to penalties for each day the payment is late.
On September 4, 2001, the CPUC issued a proposed decision authorizing a CDWR revenue requirement of $12.1 billion
to pay its bonds' costs and energy procurement costs for 2001 and 2002. The proposed decision states that SCE's
allocated share of this revenue requirement (based on a cost-of-service approach) would be approximately $4
billion, and changes SCE's payment from 10.277(cent)per kWh to 10.03(cent)per kWh. A balancing account would be
established to record the difference between the two rates, with the difference to be trued up in a subsequent
CPUC order. In comments filed with the CPUC on September 12, 2001, SCE requested that the CPUC refrain from
adopting a final revenue requirement until hearings are held to determine how the revenue requirement was
calculated and its relationship to SCE's revenue requirement to be determined in the URG proceeding. In a
November 5, 2001, filing with the CPUC, the CDWR reduced its revenue requirement $10.0 billion, due to
conservation efforts, lower natural gas prices and other changes in market conditions. The CPUC has not
determined SCE's share of the $10.0 billion. A final decision on the URG and CDWR matters is not expected until
early 2002.
SCE believes that the intent of AB 1X was for the CDWR to assume full responsibility for purchasing all power
needed to serve the retail customers of electric utilities, in excess of the output of generating plants owned by
the electric utilities and power delivered to the utilities under existing contracts. However, the CDWR stated
that it would only purchase power that it considers to be reasonably priced, leaving the ISO to purchase in the
short-term market the additional power necessary to meet system requirements. The ISO, in turn, took the
position that it will charge SCE for the costs of power it purchases in this manner. If SCE is found responsible
for purchases of power by the ISO for delivery to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs for the nine months ended September 30, 2001, could increase by as much as $1.6 billion
(which includes bills received for January through July 2001, and an estimate for August and September 2001).
This amount could increase or decrease depending on CPUC or FERC decisions regarding payments and refunds. In
its March 27, 2001, interim order, the CPUC
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stated that it cannot assume that the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO and the CDWR (to which SCE is not
a party), and proceedings before the FERC (to which SCE is a party), may result in rulings clarifying the CDWR's
financial responsibility for purchases of power. In April 2001, the FERC issued an order confirming its February
2001 order that the ISO must have a creditworthy buyer for any transactions. SCE has not met the ISO's
creditworthiness requirements since its credit ratings were downgraded in mid-January 2001. As a result, SCE has
protested and returned the bills it received from the ISO. On November 7, 2001, the FERC issued an order
directing the ISO to invoice CDWR (within 15 days of the date of the order) for all transactions it entered into
on behalf of SCE's customers. The ISO was also directed to file a report with the FERC within 15 days from the
date of the order indicating overdue amounts from CDWR and a schedule for payments of those amounts within three
months of the date of the order. In any event, SCE takes the position that it is not responsible for purchases
of power by the CDWR or the ISO on or after January 18, 2001. SCE cannot predict the outcome of any of these
proceedings or issues.
Status of Transition and Power-Procurement Cost Recovery
SCE's transition costs include power purchases from QF contracts (which are the direct result of prior
legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide
service to customers. Other costs include the recovery of income tax benefits previously flowed through to
customers, postretirement benefit transition costs and accelerated recovery of investment in nuclear generating
units. Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract. Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most
of the remaining transition costs to be recovered through the end of the four-year transition period (not later
than March 31, 2002). Because regulatory and legislative actions that make such recovery probable were not taken
in a timely manner during the energy crisis, as of December 31, 2000, SCE was unable to conclude that the net
regulatory assets related to purchased-power settlements, the unamortized loss on SCE's generating plant sales in
1998, and various other generation regulatory assets were probable of recovery through the rate-making process.
As a result, these balances were written off as a charge to earnings at that time (see further discussion in
Earnings).
There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001. Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism. However, state legislation enacted in January 2001 prohibits the sale of SCE's remaining generation
assets until 2006. SCE stopped selling power from its generation into the ISO and PX markets in January 2001,
after SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges (see discussion in
Generation and Power Procurement).
As discussed in the Status of Transition and Power-Procurement Cost Recovery in Note 3 to the Consolidated
Financial Statements, CTC revenue has been determined residually, the CTC applied to all customers who were using
or began using utility services on or after the CPUC's 1995 restructuring decision date, and residual CTC revenue
was calculated through the TRA mechanism. In accordance with the March 27, 2001, rate stabilization decision,
both positive and negative residual CTC revenue was transferred from the TRA to the TCBA on a monthly basis,
retroactive to January 1, 1998 (see further discussion in Rate Stabilization Proceedings). A previous decision
had called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had
not been any positive residual CTC revenue between May 2000 and June 2001. The cumulative transition cost
undercollection (as recalculated) was $4.0 billion as of September 30, 2001, and $2.9 billion as of December 31,
2000.
Because the regulatory and legislative actions that made such recovery probable were not taken, SCE was unable to
conclude as of December 31, 2000, that the recalculated TCBA net undercollection was probable of recovery through
the rate-making process. As a result, the $2.9 billion TCBA net undercollection was written off as a charge to
earnings as of that date (see further discussion in Earnings),
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and an additional $1.1 billion in TCBA undercollections were charged to earnings during 2001. For more details
on the matters discussed above, see Rate Stabilization Proceedings.
Litigation
In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International. As
amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged
improper accounting for the TRA undercollections. The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001.
This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001. A consolidated class
action complaint was filed on August 3, 2001. On September 17, 2001, SCE and Edison International filed a motion
to dismiss for failure to state a claim. The motion is scheduled for hearing on December 3, 2001. SCE believes
that its current and past accounting for the TRA undercollections and related items is appropriate and in
accordance with accounting principles generally accepted in the United States.
In addition to the lawsuits filed against SCE and discussed above, SCE is involved in a number of state and
federal lawsuits filed by QFs. The lawsuits have been filed by various parties, including geothermal, wind and
cogeneration suppliers. The lawsuits are seeking payments of at least $833 million for energy and capacity
supplied to SCE under QF contracts, and in some cases for additional damages as well. Many of these QF lawsuits
also seek an order allowing the suppliers to stop providing power to SCE so that they may sell the power to other
purchasers. The state court cases have been coordinated before a single trial judge. SCE has reached agreements
with QFs representing about 97% of the QF renewable and cogeneration capacity provided to SCE. The agreements
provide for stays of litigation, payments to the QFs upon occurrence of specified conditions, modifications in
some cases to the contract prices going forward, releases and dismissals of the litigation upon payment by SCE.
In light of the settlement agreement with the CPUC, SCE is seeking to negotiate amendments to the agreements with
QFs.
SCE cannot predict the outcome of any of these matters.
Rate Stabilization Proceedings
In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost
recovery. In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory
rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001.
In January 2001, independent auditors hired by the CPUC issued a report on the financial condition and solvency
of SCE and its affiliates. The report confirmed what SCE had previously disclosed to the CPUC in public filings
about SCE's financial condition. The audit report covered, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds between SCE and Edison International,
and earnings of SCE's California affiliates. In April 2001, the CPUC adopted an order instituting investigation
that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an
investigation into: whether the holding companies violated CPUC requirements to give priority to the capital
needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the requirements to give priority to the
capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility
companies; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules,
conditions, or other changes to the holding company decisions are necessary. SCE believes the holding company
decision refers to equity investment, not working capital for operating costs. The CPUC ordered testimony and
briefing on these matters, which SCE filed in May and June 2001. SCE cannot predict what effects this
investigation or any subsequent actions by the CPUC may have on SCE.
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In March 2001, the CPUC ordered an immediate rate increase in the form of a 3(cent)-per-kWh surcharge applied only to
going-forward electric power procurement costs and affirmed that a 1(cent)interim surcharge granted in January 2001
is permanent. The 3(cent)surcharge is to be added to the rate paid to the CDWR (see CDWR Power Purchases). Although
the 3(cent)-increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the CPUC
established a rate design in early June 2001.
Also, in the March 2001 order, the CPUC granted a petition previously filed by The Utility Reform Network and
directed that the balance in SCE's TRA, whether over or undercollected, be transferred on a monthly basis to the
TCBA, retroactive to January 1, 1998. Previous rules called only for TRA overcollections (residual CTC revenue)
to be transferred to the TCBA. The CPUC also ordered SCE to transfer the coal and hydroelectric balancing
account overcollections to the TRA on a monthly basis before any transfer of residual CTC revenue to the TCBA,
retroactive to January 1, 1998. Previous rules called for overcollections in these two balancing accounts to be
transferred directly to the TCBA on an annual basis (see further discussion of the recalculation of the TCBA in
Status of Transition and Power-Procurement Cost Recovery). Based upon the transfer of balances into the TCBA,
the CPUC denied SCE's December 2000 filing requesting an end to the current rate freeze, and stated that the
four-year rate freeze will not end until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze. The CPUC also said that it would
monitor the balances remaining in the TCBA and consider how to address remaining balances in the ongoing
proceedings. In accordance with the October 2001 settlement with the CPUC, it is expected that the TCBA
mechanism will be discontinued and the PROACT mechanism will be established retroactive to August 31, 2001 (see
further discussion in CPUC Litigation Settlement Agreement).
URG Proceeding
In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
cost-of-service ratemaking for utility retained generation through the end of 2002. The URG proposal calls for
balancing accounts for SCE-owned generation, QF and interutility contracts, procurement costs and ISO charges
based on either actual or CPUC-authorized revenue requirements. Under the proposal, the four new balancing
accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for
non-capital-related costs. In addition, SCE's unamortized nuclear investment would be amortized and recovered in
rates over a 10-year period, effective January 1, 2001. Should this application be approved as filed, SCE
expects to reestablish for financial reporting purposes regulatory assets related to purchased-power settlements,
unamortized nuclear investment and related flow-through taxes, with a corresponding credit to earnings. Hearings
were held in July 2001. A final decision is not expected until early 2002.
Accounting for Generation-Related Assets and Power Procurement Costs
In 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its generation
assets. At that time, SCE did not write off any of its generation-related assets, including related regulatory
assets, because the electric utility industry restructuring plan made probable their recovery through a
nonbypassable charge to distribution customers.
During the second quarter of 1998, in accordance with asset impairment accounting standards, SCE reduced its
remaining nuclear plant investment by $2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount. For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows. This reclassification had no effect on SCE's results
of operations.
As of December 31, 2000, SCE assessed the probability of recovery of its generation-related assets
and power procurement costs in light of the CPUC's March 27, 2001, and April 3, 2001, decisions, and
could not conclude that its $2.9 billion TCBA undercollection (as redefined in the March 27 decisions) and
$1.3 billion (book value) of its net generation-related regulatory assets to be amortized into the TCBA,
were probable of recovery through the rate-making process. As a result, accounting principles
generally accepted in the United States required that the balances in the accounts be written off as a
charge to
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earnings. In addition to the $4.2 billion pre-tax write-off, SCE incurred approximately $400 million in net
undercollected transition costs during 2001 (see Earnings).
In accordance with the CPUC settlement agreement, in fourth quarter 2001, it is expected that the CPUC will issue
implementing decisions or orders allowing SCE to establish a $3.6 billion regulatory asset for previously
incurred energy procurement-related costs, to be called the PROACT, retroactive to August 31, 2001. See further
discussion in CPUC Litigation Settlement Agreement. CPUC approval of the URG application, as filed (see URG
Proceeding), together with implementation of the PROACT mechanism is expected to allow SCE to recover
substantially all of the $4.6 billion in write-offs and undercollected transition costs incurred during the past
12 months.
Distribution
Revenue related to distribution operations is determined through a performance-based rate-making (PBR) mechanism
and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return on investment. The
distribution PBR will extend through December 2001. Key elements of the distribution PBR include: distribution
rates indexed for inflation based on the Consumer Price Index less a productivity factor; adjustments for cost
changes that are not within SCE's control; a cost-of-capital trigger mechanism based on changes in a utility bond
index; standards for customer satisfaction; service reliability and safety; and a net revenue-sharing mechanism
that determines how customers and shareholders will share gains and losses from distribution operations.
Transmission
Transmission revenue is determined through FERC-authorized rates and is subject to refund.
Wholesale Electricity Markets
In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive, immediately impose a cap on the price for energy and ancillary
services, and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds. In December 2000, the FERC took limited action and failed
to impose a price cap. SCE filed an emergency petition in the federal court of appeals challenging the FERC
order and requesting the FERC to immediately establish cost-based wholesale rates. The court denied SCE's
petition in January 2001.
In its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling
coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In May 2001, the
FERC indicated that it will make a determination regarding the suspension of the underscheduling penalty in a
future order in response to a complaint filed by SCE that asked the FERC to eliminate the penalty. As of October
31, 2001, SCE's share of the statewide accumulated penalties were estimated to be as much as $360 million. The
ISO has not billed SCE for any amounts associated with the underscheduling penalty. SCE cannot predict the
outcome of this matter.
On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power). The order
establishes an hourly clearing price based on the costs of the least efficient generating unit during the
period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.
After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices. An administrative law judge will conduct
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evidentiary hearings on this matter. SCE cannot predict the amount of any potential refunds. Under the
settlement of litigation with the CPUC, refunds will be applied to the balance in the PROACT.
Environmental Protection
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.
As further discussed in Note 12 to the Consolidated Financial Statements, SCE records its environmental
liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE's recorded estimated minimum liability to remediate its 42 identified sites is $114
million. SCE believes that, due to uncertainties inherent in the estimation process, it is reasonably possible
that cleanup costs could exceed its recorded liability by up to $269 million. In 1998, SCE sold all of its
gas-fueled power plants but has retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $45 million of its
recorded liability, through an incentive mechanism, which is discussed in Note 12. SCE has recorded a regulatory
asset of $60 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. As a
result, 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 $10 million to $25 million. Recorded costs for the twelve months ended September 30,
2001, were $20 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 and, based upon the CPUC's regulatory treatment of environmental-cleanup
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.
The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide. Power companies
receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to
have excess allowances under Phase II of the Clean Air Act (2000 and later). A study was undertaken to determine
the specific impact of air contaminant emissions from the Mohave Generating Station on visibility in Grand Canyon
National Park. The final report on this study, which was issued in March 1999, found negligible correlation
between measured Mohave station tracer concentrations and visibility impairment. The absence of any obvious
relationship cannot rule out Mohave station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. In June 1999, the Environmental Protection
Agency (EPA) issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at
the Grand Canyon. SCE filed comments on the proposed rulemaking in November 1999. In 1998, several
environmental groups filed suit against the co-owners of the Mohave station regarding alleged violations of
emissions limits. In order to accelerate resolution of key environmental issues regarding the plant, the parties
filed, in concurrence with SCE and the other station owners, a consent decree, which was approved by the court in
December 1999. In a letter to SCE, the EPA has expressed its belief that the controls provided in the consent
decree will likely resolve the potential Clean Air Act visibility concerns. The EPA is considering incorporating
the decree into the visibility provisions of its Federal Implementation Plan for Nevada.
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SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of
the Mohave station is estimated to be approximately $560 million over the next four years. However, SCE has
suspended its efforts to seek approval to install the Mohave controls because it has not obtained reasonable
assurance of an adequate water supply for mining and transporting the coal required for operating Mohave beyond
2005. Accordingly, the above amount is not included in the environmental capital expenditure projections below.
The Navajo Nation and Hopi Tribe have not been willing to agree to continued use of the current source of water
from an aquifer in their joint use area after December 31, 2005. Efforts by the Mohave co-owners to find
alternative sources of water have been unsuccessful, and it is unlikely that water rights can be obtained before
the time when the Mohave co-owners would need to make large financial commitments towards continued operation of
the Mohave station. If adequate water rights are not obtained, it will become necessary to shut down the Mohave
station after December 31, 2005.
SCE's projected environmental capital expenditures are $1.2 billion for the 2001-2005 period, mainly for
undergrounding certain transmission and distribution lines.
San Onofre Nuclear Generating Station
In February 2001, SCE's San Onofre Unit 3 experienced a fire due to an electrical fault in the non-nuclear
portion of the plant. The turbine rotors, bearings and other components of the turbine generator system were
damaged extensively. In June 2001, Unit 3 returned to service. Under the currently effective San Onofre
rate-recovery plan (discussed in the Generation and Power Procurement section of Regulatory Environment), SCE's
lost revenue was approximately $98 million as a result of the fire and related outage.
The San Onofre Units 2 and 3 steam generators' design allows for the removal of up to 10% of the tubes before the
rated capacity of the unit must be reduced. Increased tube degradation was found during routine inspections in
1997. To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service. A decreasing
(favorable) trend in degradation has been observed in more recent inspections.
New Accounting Standards
In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of
long-lived assets. Although the statement supersedes a prior accounting standard related to the impairment of
long-lived assets, it retains the fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived
assets to be disposed of by sale. Under the new accounting standard, asset write-downs from discontinuing a
business segment will be treated the same as other assets held for sale. The new standard also broadens the
financial statement presentation of discontinued operations to include the disposal of an asset group (rather
than a segment of a business). The standard is effective for SCE beginning January 1, 2002, unless early
adoption is implemented.
In July and August 2001, three new accounting standards were issued: Business Combinations; Goodwill and Other
Intangibles; and Accounting for Asset Retirement Obligations.
The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001.
After that, all business combinations will be recorded under the purchase method (record goodwill for excess of
costs over the net assets acquired).
The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective
January 1, 2002. Goodwill initially recognized after June 30, 2001, will not be amortized. Goodwill on the
balance sheet at June 30, 2001, will be amortized until January 1, 2002. Under the new standard, goodwill will
be tested for impairment using a fair-value approach when events or circumstances occur indicating that
impairment might exist. Also, a benchmark assessment for goodwill is required within six months of the date of
adoption of the standard.
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The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred. When the liability is
initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived
asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier application encouraged.
SCE is studying the impact of the new Asset Retirement Obligations and Asset Impairment standards and is unable
to predict at this time the effect on its financial statements. SCE does not anticipate any material impact on
its results of operations or financial position from the other two new accounting standards.
On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. The
new standard requires all derivatives to be recognized on the balance sheet at fair value. Prior to adoption,
hedges were not recorded on the balance sheet. Gains or losses from changes in the fair value of a recognized
asset or liability or a firm commitment are reflected in earnings for the ineffective portion of the hedge. For
a hedge of the cash flows of a forecasted transaction, the effective portion of the gain or loss is initially
recorded as a separate component of shareholder's equity under the caption "accumulated other comprehensive
income," and subsequently reclassified into earnings when the forecasted transaction affects earnings. The
ineffective portion of the gain or loss is reflected in earnings immediately. Under the new standard, SCE's
derivatives qualify for hedge accounting or for the normal purchase and sales exemption from derivatives
accounting rules. On the implementation date, SCE recorded its interest rate swap agreement (terminated January
5, 2001) and its block forward power purchase contracts (seized by the state on February 2, 2001) at fair value
on its balance sheet. As of September 30, 2001, SCE did not have any derivatives as defined by the new
accounting standard. SCE does not anticipate any earnings impact from any future derivatives, since it expects
that any market price changes will be recovered in rates.
Forward-looking Information
In the preceding Management's Discussion and Analysis of Results of Operations and Financial Condition and
elsewhere in this quarterly report, the words estimates, expects, anticipates, believes, and other similar
expressions are intended to identify forward-looking information that involves risks and uncertainties. Actual
results or outcomes could differ materially as a result of such important factors as possible challenges to the
entry of the stipulated judgment or the provisions of the settlement agreement; possible ballot initiatives
attempting to undermine the provisions of the settlement agreement or otherwise adversely affecting SCE; changes
in prices of wholesale electricity and natural gas or SCE's costs, including the prices and costs that were
assumed in negotiating the settlement agreement, which could cause SCE's cost recovery to be less than
anticipated; the actions of securities rating agencies, including the determination of whether or when to make
changes in SCE's credit ratings; the possible inability of SCE to refinance existing obligations and obtain new
financing on reasonable terms as needed; the possibility that SCE's creditors may file an involuntary bankruptcy
petition against SCE or pursue other remedies against SCE or its assets; the outcome of negotiations for
solutions to SCE's liquidity problems; further actions by state and federal regulatory bodies setting rates,
adopting or modifying cost recovery, accounting or rate-setting mechanisms and implementing the restructuring of
the electric utility industry; actions by lenders, investors and creditors in response to SCE's suspension of
payments for debt service and purchased power; the effects, unfavorable interpretations and applications of new
or existing laws and regulations relating to restructuring, taxes and other matters; the effects of increased
competition in energy-related businesses; the availability of credit, including SCE's ability to regain an
investment grade credit rating and re-enter the credit markets; changes in financial market conditions; the
amount of revenue available to both transition and non-transition costs; new or increased environmental
liabilities; the financial viability of new businesses, such as telecommunications; weather conditions; and other
unforeseen events.
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PART II OTHER INFORMATION
Item 1. Legal Proceedings
San Onofre Personal Injury Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, and in Part II, Item 1 of SCE's Form 10-Qs for
the quarterly periods ending March 31, 2001 (First Quarter 10-Q) and June 30, 2001 (Second Quarter 10-Q), SCE is
actively involved in four lawsuits claiming personal injuries allegedly resulting from exposure to radiation at
San Onofre.
In the case filed against SCE on March 1, 2001, the Court has approved a stipulation of the parties staying
prosecution of the case pending the outcome of appellate proceedings in the matter brought against SCE on
November 17, 1995. In that case, on September 27, 2001, the Ninth Circuit issued a new opinion affirming the
District Court's judgment in favor of SCE and the other defendants in the action. On October 9, 2001, plaintiffs
in the November 17, 1995, action filed a petition for rehearing.
Shareholder Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, and in Part II, Item 1 of SCE's First Quarter
10-Q and Second Quarter 10-Q, two purported class actions (referred to as the Stubblefield Action and King
Action) were filed in October 2000 and March 2001, and involve securities fraud claims arising from alleged
improper accounting by Edison International and SCE for undercollections in SCE's Transition Revenue Account
(TRA).
On August 3, 2001, the plaintiffs in the Stubblefield Action and King Action filed a consolidated complaint on
behalf of alleged shareholders of Edison International, naming as defendants SCE, Edison International, and
certain officers of Edison International. The consolidated complaint alleges that defendants engaged in
securities fraud by misrepresenting and/or failing to disclose material facts concerning the financial condition
of Edison International and SCE, including that defendants allegedly over-reported income and improperly
accounted for the TRA undercollections. The complaint purports to be filed on behalf of a class of persons who
purchased Edison International stock between July 21, 2000, and April 17, 2001. Plaintiffs seek damages in an
unstated amount in connection with their purchase of securities during the class period. On September 17, 2001,
the defendants filed a motion to dismiss for failure to state a claim. Plaintiffs filed their opposition on
October 22, 2001. The motion is scheduled for hearing on December 3, 2001.
Qualifying Facilities (QF) Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, and in Part II, Item 1 of SCE's First Quarter
10-Q and Second Quarter 10-Q, SCE is involved in a number of legal actions brought by various QFs, alleging SCE
failed to timely pay for power deliveries made from November 2, 2000, through March 26, 2001. The plaintiffs
include gas-fired QFs, geothermal and wind energy QFs, and owners of cogeneration projects. The lawsuits, in
aggregate, seek payments of more than $833,000,000 for energy and capacity supplied to SCE under QF contracts,
and in some cases additional damages. Many of these QF lawsuits also seek an order allowing the suppliers to
stop providing power to SCE so that they may sell to other purchasers. The California court cases have been
coordinated before a single trial judge. On September 13, 2001, the coordinated trial judge dismissed, with
prejudice, five of the six remaining cases on the basis that the issues in dispute are currently within the
jurisdiction of the CPUC. The sixth case, which was filed in federal court and therefore was not within the
September 13 ruling, was stayed for 90 days by order issued on September 24, 2001, in order to permit the CPUC to
address the issues in dispute. SCE has reached at least tentative settlement with four of the five QFs included
in the September 13 dismissal ruling. SCE had settled with the fifth QF included in the September 13 order as
well but that settlement was contingent upon CPUC approval of the settlement being obtained by a particular date,
a condition which did not materialize. Accordingly, that agreement has lapsed. This
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nonsettling QF, whose claim is for approximately $10,500,000, has filed a notice of appeal from the coordination
trial judge's dismissal of its case. In addition, to protect their rights, two of the other QFs whose cases were
dismissed in the coordinated state court proceeding have also filed appeals; however, the latter QFs and SCE
have, in one of the cases, jointly requested and, in the other case, will jointly request, a stay of the appeals
from the appellate court as required under the parties' settlement agreement.
During June, July and August 2001, SCE reached agreements with generators representing about 97% of the QF
renewable cogeneration capacity provided to SCE. The agreements provide for stays of litigation, payments to the
QFs upon the occurrence of specified conditions, modifications in some cases to the contract prices going
forward, releases and dismissals of the litigation upon payment by SCE.
Rights to attach assets in connection with claims have been granted in four cases (Beowawe Power, L.L.C., Heber
Geothermal Company, City of Long Beach, and IMC Chemicals, Inc.) in the approximate amounts of $20,000,000,
$28,000,000, $9,000,000, and $7,500,000, respectively, contingent on the posting of bonds. The plaintiffs in
three of these cases (Beowawe, Heber and IMC Chemicals) have not posted bonds as of this time and did not attach
any SCE assets. Each of these four cases is now stayed pursuant to an agreement of the type referenced above.
Before entering into a stay agreement pursuant to the parties' settlement, Long Beach had attached one of SCE's
bank accounts. As noted above, the Long Beach case has recently been dismissed without prejudice pursuant to the
dismissal order in the coordination proceeding, but the dismissal remains subject to Long Beach's appeal. In
addition, prior to the dismissal, SCE initiated a writ proceeding before the California Court of Appeal to
challenge the right to attach order in the Long Beach case, and, in connection with that writ proceeding, SCE
obtained a temporary stay of enforcement of the attachment order. That stay and the hearing on the writ petition
were recently continued by the Court of Appeal to January 2002, based on a joint motion of the parties in light
of the order of dismissal. Under the parties' settlement agreement discussed above, the parties shall request
that the proceedings in the Court of Appeal related to Long Beach's attachment (which in addition to SCE's
petition for review includes an ancillary appeal by SCE and a cross appeal by Long Beach) be stayed for a period
concurrent with the standstill period specified in the settlement.
Power Exchange (PX) Performance Bond Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, and in Part II, Item 1 of SCE's Second Quarter
10-Q, SCE was notified that due to failure to comply with its payment obligations to the PX, the PX issued a
demand to American Home Assurance Company (American Home). As required under the indemnity agreement between SCE
and American Home, in February 2001, SCE deposited $20,200,000 in an account in trust to be available to satisfy
any judgment, should there be one, against American Home. On or about September 13, 2001 the PX submitted a
demand for arbitration against American Home, asserting causes of action for breach of contract and bad faith
refusal to pay. On September 25, 2001, American Home demanded that SCE indemnify and defend American Home in
connection with the demand for arbitration, pursuant to the operative documents between the parties. SCE has
assumed the defense of this arbitration.
Page 60
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993
(File No. 1-2313, Form 10-K for the year ended December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated June 23, 1997
(File No. 1-2313, Form 10-Q for the quarter ended September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board of Directors on
October 18, 2001
23. Consent of Independent Public Accountants
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
None
------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 61
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report
to be signed on its behalf by the undersigned thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By /THOMAS M. NOONAN/
THOMAS M. NOONAN
Vice President and Controller
By /KENNETH S. STEWART/
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
November 13, 2001
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