SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2001 June (Form 10-Q)
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2001
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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 ___
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Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:
Class Outstanding at August 9, 2001
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Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 1
Consolidated Statements of Income (Loss) - Three, Six and
Twelve Months Ended June 30, 2001, and 2000 2
Consolidated Statements of Comprehensive Income (Loss) -
Three, Six and Twelve Months Ended June 30, 2001, and 2000 2
Consolidated Balance Sheets - June 30, 2001,
December 31, 2000, and June 30, 2000 3
Consolidated Statements of Cash Flows -
Three, Six and Twelve Months Ended
June 30, 2001, and 2000 5
Consolidated Statements of Common Shareholder's
Equity - Three, Six and Twelve Months Ended
June 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 41
Part II. Other Information:
Item 1. Legal Proceedings 64
Item 4. Submission of Matters to a Vote of Security Holders 66
Item 6. Exhibits and Reports on Form 8-K 67
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 June 30, 2001, December 31, 2000, and June 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-, six- and twelve-month periods ended June 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 June 30, 2001, December 31, 2000, and June 30, 2000, and the
results of their operations and their cash flows for each of the three-, six- and twelve-month periods ended
June 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 current energy crisis in California has
resulted in SCE incurring a loss from operations for the six and twelve months ended June 30, 2001, due to the
uncertainty associated with its ability to collect certain costs through the regulatory process and has resulted
in legal, regulatory and legislative 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
August 8, 2001
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
In millions
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
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2001 2000 2001 2000 2001 2000
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Operating revenue $1,592 $1,853 $3,104 $3,683 $7,292 $7,820
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Fuel 51 22 98 81 213 201
Purchased power 807 687 2,531 1,187 6,029 3,120
Provisions for regulatory adjustment clauses - net (90) (97) (119) 6 2,176 (397)
Other operation and maintenance 431 456 860 866 1,768 1,749
Depreciation, decommissioning and amortization 166 371 318 747 1,044 1,531
Property and other taxes 29 29 58 68 115 122
Net gain on sale of utility plant (6) -- (9) (6) (27) (7)
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Total operating expenses 1,388 1,468 3,737 2,949 11,318 6,319
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Operating income (loss) 204 385 (633) 734 (4,026) 1,501
Interest and dividend income 25 24 51 44 179 82
Other nonoperating income 14 53 22 73 67 151
Interest expense - net of amounts capitalized (153) (128) (360) (256) (676) (498)
Other nonoperating deductions (23) (36) (16) (58) (66) (122)
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Income (loss) before taxes 67 298 (936) 537 (4,522) 1,114
Income taxes 33 137 (377) 257 (1,655) 520
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Net income (loss) 34 161 (559) 280 (2,867) 594
Dividends on preferred stock 6 5 11 10 22 24
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Net Income (loss) available for common stock $ 28 $ 156 $ (570) $ 270 $ (2,889) $ 570
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
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2001 2000 2001 2000 2001 2000
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Net income (loss) $ 34 $ 161 $ (559) $ 280 $ (2,867) $ 594
Other comprehensive income, net of tax:
Unrealized gain (loss) on securities - net -- 2 -- 5 (2) 40
Cumulative effect of change in
accounting for derivatives -- -- 397 -- 397 --
Unrealized loss on cash flow hedges 1 -- (422) -- (422) --
Reclassification adjustment for gains
included in net income (loss) -- (25) -- (25) -- (38)
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Comprehensive income (loss) $ 35 $ 138 $ (584) $ 260 $ (2,894) $ 596
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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
June 30, December 31, June 30,
2001 2000 2000
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ASSETS
Cash and equivalents $ 2,043 $ 583 $ 106
Receivables, less allowances of $26, $23 and $22
for uncollectible accounts at respective dates 956 919 641
Accrued unbilled revenue 477 377 490
Fuel inventory 12 12 35
Materials and supplies, at average cost 137 132 130
Accumulated deferred income taxes - net 579 545 525
Prepayments and other current assets 112 124 51
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Total current assets 4,316 2,692 1,978
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Nonutility property - less accumulated provision for
depreciation of $13, $11 and $8 at respective dates 125 102 105
Nuclear decommissioning trusts 2,406 2,505 2,546
Other investments 105 90 188
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Total investments and other assets 2,636 2,697 2,839
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Utility plant, at original cost:
Transmission and distribution 13,332 13,129 12,697
Generation 1,722 1,745 1,743
Accumulated provision for depreciation and decommissioning (7,914) (7,834) (7,702)
Construction work in progress 623 636 684
Nuclear fuel, at amortized cost 141 143 111
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Total utility plant 7,904 7,819 7,533
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Regulatory assets - net 2,741 2,390 5,522
Other deferred charges 505 368 373
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Total deferred charges 3,246 2,758 5,895
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Total assets $ 18,102 $ 15,966 $ 18,245
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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
June 30, December 31, June 30,
2001 2000 2000
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LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ 2,121 $ 1,451 $ 855
Long-term debt classified as due within one year 2,797 646 648
Preferred stock to be redeemed within one year 105 -- --
Accounts payable 3,199 1,055 558
Accrued taxes 270 536 608
Regulatory liabilities - net 197 195 495
Other current liabilities 1,746 1,502 1,652
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Total current liabilities 10,435 5,385 4,816
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Long-term debt 3,231 5,631 4,850
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Accumulated deferred income taxes - net 2,062 2,009 3,150
Accumulated deferred investment tax credits 157 164 184
Customer advances and other deferred credits 825 755 788
Power-purchase contracts 411 467 506
Accumulated provision for pensions and benefits 416 296 271
Other long-term liabilities 98 94 101
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Total deferred credits and other liabilities 3,969 3,785 5,000
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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 334 334 334
Accumulated other comprehensive income (loss) (24) -- 2
Retained earnings (deficit) (2,291) (1,722) 690
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Total common shareholder's equity 187 780 3,194
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Total liabilities and shareholder's equity $ 18,102 $ 15,966 $ 18,245
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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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
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2001 2000 2001 2000 2001 2000
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Cash flows from operating activities:
Net income (loss) $ 34 $ 161 $ (559) $ 280 $ (2,867) $ 594
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 166 371 318 747 1,044 1,531
Other amortization 19 25 36 50 83 102
Deferred income taxes and investment tax credits 144 (69) (159) (108) (979) 3
Regulatory assets - long-term - net (114) (452) (236) (543) 2,066 (1,433)
Net gain on sale of marketable securities -- (41) -- (41) -- (64)
Other assets (10) (50) (102) (74) 17 (112)
Other liabilities 9 38 76 32 32 (36)
Changes in working capital:
Receivables and accrued unbilled revenue (149) (140) (132) (117) (298) (68)
Regulatory liabilities - short-term - net (49) 276 7 396 (292) 750
Fuel inventory, materials and supplies 1 (1) (5) 7 17 3
Prepayments and other current assets (15) 5 13 61 (62) (33)
Accrued interest and taxes (184) 23 (212) 113 (277) (117)
Accounts payable and other current liabilities 333 231 2,320 156 2,752 507
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Net cash provided by operating activities 185 377 1,365 959 1,236 1,627
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Cash flows from financing activities:
Long-term debt issued -- -- -- 247 1,512 383
Long-term debt repaid -- (1) -- (325) (200) (470)
Bonds repurchased and funds held in trust 27 -- (130) -- (569) --
Rate reduction notes repaid (50) (52) (112) (113) (246) (240)
Nuclear fuel financing - net (1) (7) (10) (22) 21 (50)
Short-term debt financing - net 1 6 670 59 1,266 448
Dividends paid -- (100) (1) (200) (196) (597)
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Net cash provided (used) by financing activities (23) (154) 417 (354) 1,588 (526)
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Cash flows from investing activities:
Additions to property and plant (174) (269) (353) (522) (926) (1,032)
Funding of nuclear decommissioning trusts 21 (36) 20 (59) 10 (109)
Proceeds from sales of marketable securities -- 41 -- 41 -- 64
Sales of investments in other assets 7 16 11 15 29 10
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Net cash used by investing activities (146) (248) (322) (525) (887) (1,067)
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Net increase (decrease) in cash and equivalents 16 (25) 1,460 80 1,937 34
Cash and equivalents, beginning of period 2,027 131 583 26 106 72
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Cash and equivalents, end of period $ 2,043 $ 106 $ 2,043 $ 106 $ 2,043 $ 106
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Cash payments for interest and taxes:
Interest - net of amounts capitalized $ 134 $ 71 $ 203 $ 145 $ 361 $ 315
Taxes -- 203 -- 203 103 636
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 March 31, 2000 $ 2,168 $ 335 $ 24 $ 626 $ 3,153
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Net income 161 161
Unrealized gain on securities 3 3
Tax effect (1) (1)
Reclassified adjustment for gain
included in net income (41) (41)
Tax effect 17 17
Dividends declared on common stock (91) (91)
Dividends declared on preferred stock (5) (5)
Capital stock expense and other (1) (1) (2)
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Balance at June 30, 2000 $ 2,168 $ 334 $ 2 $ 690 $ 3,194
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Balance at March 31, 2001 $ 2,168 $ 334 $ (25) $ (2,320) $ 157
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Net income 34 34
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 June 30, 2001 $ 2,168 $ 334 $ (24) $ (2,291) $ 187
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Balance at December 31, 1999 $ 2,168 $ 335 $ 22 $ 608 $ 3,133
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Net income 280 280
Unrealized gain on securities 8 8
Tax effect (3) (3)
Reclassified adjustment for gains
included in net income (41) (41)
Tax effect 16 16
Dividends declared on common stock (187) (187)
Dividends declared on preferred stock (10) (10)
Stock option appreciation (1) (1)
Capital stock expense and other (1) (1)
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Balance at June 30, 2000 $ 2,168 $ 334 $ 2 $ 690 $ 3,194
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Balance at December 31, 2000 $ 2,168 $ 334 -- $ (1,722) $ 780
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Net income (loss) (559) (559)
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (422) (422)
Dividends declared on preferred stock (11) (11)
Capital stock expense and other 1 1 2
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Balance at June 30, 2001 $ 2,168 $ 334 $ (24) $ (2,291) $ 187
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF 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, 1999 $ 2,168 $ 334 $ -- $ 694 $ 3,196
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Net income 594 594
Unrealized gain on securities 64 64
Tax effect (24) (24)
Reclassified adjustment for gain
included in net income (64) (64)
Tax effect 26 26
Dividends declared on common stock (572) (572)
Dividends declared on preferred stock (24) (24)
Stock option appreciation (2) (2)
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Balance at June 30, 2000 $ 2,168 $ 334 $ 2 $ 690 $ 3,194
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Net income (loss) (2,867) (2,867)
Unrealized gain on securities (3) (3)
Tax effect 1 1
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (422) (422)
Dividends declared on common stock (92) (92)
Dividends declared on preferred stock (22) (22)
Stock option appreciation 1 1
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Balance at June 30, 2001 $ 2,168 $ 334 $ (24) $ (2,291) $ 187
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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 1996, state lawmakers and the California Public Utilities Commission
(CPUC) initiated the 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. The
electric utility industry restructuring plan also 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 first quarter 2001) are 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
generators and other sellers have escalated far beyond what SCE can currently charge its customers, causing a
severe liquidity crisis for SCE. Due to the liquidity crisis, the State of California has been making emergency
power purchases for SCE's customers since January 18, 2001. See Notes 2 and 3 for a further discussion.
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 June 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 rate freeze period, the difference between certain generation-related revenue and generation-related
costs is being accumulated in the transition cost balancing account (TCBA). The gains resulting from the sale of
12 of SCE's generating plants during 1998 have been credited to the TCBA.
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In June 2000, SCE credited the TCBA for the estimated excess of the market value over book value of its
hydroelectric generation assets and simultaneously recorded the same amount in the generation asset balancing
account (GABA), in accordance with a CPUC decision. This balance was to remain in GABA until final market
valuation of the hydroelectric generation assets. If there were a difference in the final market valuation, it
would have been credited to or recovered from customers through the TCBA mechanism. Due to the various
unresolved regulatory and legislative issues (as discussed in Note 3), the GABA transaction was reclassified back
into the TCBA as of December 31, 2000.
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 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 recalculated to be a
$2.9 billion undercollection.
Due to the various unresolved regulatory and legislative issues (as discussed in Note 3), the TCBA
undercollection was charged to earnings as of December 31, 2000.
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. Until legislative and regulatory actions are taken,
SCE is unable to conclude that its generation-related regulatory assets are probable of recovery through the
rate-making process. Therefore, in accordance
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
with accounting rules, SCE recorded a $2.5 billion after-tax charge to earnings as of December 31, 2000,
to write off the TCBA and other regulatory assets (see below).
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. Unless a rate-making mechanism is in place that
would make recovery of SCE's TCBA-related regulatory assets probable, future net undercollections in the TCBA
will be charged to earnings in the period incurred. If and when regulatory and legislative actions are taken
that make recovery probable, the regulatory assets would be restored to the balance sheet, with a corresponding
increase to earnings.
Regulatory assets and liabilities included in the consolidated balance sheets are:
June 30, December 31, June 30,
In millions 2001 2000 2000
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Generation-related:
Unamortized nuclear investment - net $ -- $ -- $ 978
Flow-through taxes -- -- 170
Unamortized loss on sale of plant -- -- 91
Purchased-power settlements -- -- 474
Regulatory balancing accounts and other -- -- 465
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Subtotal -- -- 2,178
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Rate reduction notes - transition cost deferral 1,265 1,090 887
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Transition revenue account -- -- 644
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Other:
Flow-through taxes 1,043 874 1,065
Unamortized loss on reacquired debt 262 273 283
Environmental remediation 60 52 55
Regulatory balancing accounts and other (86) (94) (85)
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Subtotal 1,279 1,105 1,318
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Total $ 2,544 $ 2,195 $ 5,027
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The regulatory asset related to the rate reduction notes will be recovered over the terms of the rate reduction
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; however, on December 31, 2000,
the balance was written off since SCE was unable to conclude that the asset was probable of recovery (see Note
3).
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
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
incremental capital expenditures, are 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 will 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 expenditures, are subject to balancing account treatment
through December 31, 2001. The San Onofre and Palo Verde rate recovery plans and the Palo Verde balancing account
are part of the TCBA.
The nuclear rate-making plans and the TCBA mechanism will 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), SCE is no longer able to conclude
that the unamortized nuclear investment is probable of recovery through the rate-making process. As a result,
the balance was written off as a charge to earnings as of December 31, 2000.
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. On May 4, 2001, SCE requested that the post-2003 and
post-2001 benefit sharing provisions of the current San Onofre and Palo Verde ratemaking mechanisms be eliminated
contingent upon implementation of the Memorandum of Understanding (MOU, discussed in Note 3). On June 14, 2001,
the CPUC granted SCE's request to eliminate the San Onofre post-2003 benefit sharing mechanism based on
compliance with recently enacted state law and not contingent upon implementation of the MOU. The CPUC has not
yet ruled on SCE's similar request regarding Palo Verde. Palo Verde's existing nuclear unit incentive procedure
will continue through 2001 for purposes of calculating a reward for performance of any unit above an 80% capacity
factor for a fuel cycle. On May 4, 2001, SCE requested that the CPUC extend the incentive procedure through
2002. The CPUC has yet to rule on this request.
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.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All investments are classified as available-for-sale.
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 be 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, $4 million and $9 million for the three, six and twelve months ended June 30,
2001, respectively, and $3 million, $7 million and $14 million for the three, six and twelve months ended
June 30, 2000, respectively. AFUDC - debt was $2 million, $5 million and $9 million for the three, six and twelve
months ended June 30, 2001, respectively, and $3 million, $6 million and $12 million for the three, six and
twelve months ended June 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
3.7% for each of the three, six and twelve months ended June 30, 2001, and 3.3%, 3.5% and 3.7% for the three, six
and twelve months ended June 30, 2000, respectively.
SCE's net investment in generation-related utility plant was approximately $1.0 billion at June 30, 2001, at
December 31, 2000, and at June 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 $185 million, $350 million and $585 million for the three, six
and twelve months ended June 30, 2001, respectively, and $75 million, $121
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million and $259 million for the three, six and twelve months ended June 30, 2000, respectively. As a result
of SCE's liquidity crisis, SCE has deferred payments for power purchases from some of 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 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). Purchases and generation sales amounts for the quarter ended June 30,
2001, reflect billing adjustments. Purchased power detail is provided below:
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------
PX/ISO:
Purchases $ (446) $ 1,529 $ 635 $ 2,041 $ 7,041 $ 3,664
Generation sales (382) 1,277 323 1,717 4,725 2,794
--------------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net (64) 252 312 324 2,316 870
Purchased power - bilateral contracts 37 -- 89 -- 89 --
Purchased power - interutility/QF contracts 834 435 2,130 863 3,624 2,250
--------------------------------------------------------------------------------------------------------------
Total $ 807 $ 687 $ 2,531 $ 1,187 $ 6,029 $ 3,120
--------------------------------------------------------------------------------------------------------------
Other Nonoperating Income and Deductions
Other nonoperating income and deductions was comprised of:
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Gain on sale of marketable securities $-- $ 41 $-- $ 41 $-- $ 64
AFUDC 4 6 9 13 18 26
Key person life insurance income 4 3 4 3 6 15
Other 6 3 9 16 43 46
--------------------------------------------------------------------------------------------------------------
Total other nonoperating income $ 14 $ 53 $ 22 $ 73 $ 67 $ 151
--------------------------------------------------------------------------------------------------------------
Provisions for regulatory issues and
refunds $ 9 $ 35 $ (7) $ 54 $ 17 $ 103
Other 14 1 23 4 49 19
--------------------------------------------------------------------------------------------------------------
Total other nonoperating deductions $ 23 $ 36 $ 16 $ 58 $ 66 $ 122
--------------------------------------------------------------------------------------------------------------
New Accounting Standards
In July and August 2001, the Financial Accounting Standards Board issued three new accounting standards:
"Business Combinations" "Goodwill and Other Intangibles" and "Accounting for Asset Retirement Obligations."
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 standard, 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.
The increasing 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 continued regulatory uncertainty regarding SCE's
ability to recover its current and future power procurement costs, have 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
temporarily suspended payments of certain obligations for principal and interest on outstanding debt and for
purchased power. As of July 31, 2001, SCE had $3.3 billion in obligations that were unpaid and overdue
including: (1) $878 million to the PX or the ISO; (2) $1.2 billion to QFs; (3) $230 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. As applicable, unpaid obligations will continue to accrue
interest. At July 31, 2001, SCE had estimated cash reserves of approximately $1.7 billion (after deducting $419
million of designated funds), which is approximately $1.6 billion less than its outstanding unpaid obligations
and preferred stock dividends in arrears (see below). If SCE is found responsible for purchases of power by the
CDWR or the ISO for sale to SCE's customers on or after January 18, 2001, SCE's unpaid obligations as of July 31,
2001, could increase by as much as $1.9 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 the series, entitling those noteholders to exercise their remedies (see Note 5).
Page 14
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE is 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. If the MOU is implemented (as further discussed in Note 3), it is
expected to allow SCE to recover its undercollected costs and to help restore SCE's creditworthiness, which would
allow SCE to pay all of its past due obligations.
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.
Based on these decisions, and the uncertainty about the amount of revenue the CDWR will require to pay its bond
and energy procurement costs, and how much of the revenue requirement will be allocated to SCE, SCE estimates
that future cash may not be sufficient to cover retained generation, purchased-power and transition costs. In
comments filed with the CPUC in March and April 2001, SCE provided a forecast showing that the net effects of the
rate increase, the payment ordered to be made to the CDWR, and the QF decision could result in a shortfall to the
CPA calculation during 2001. To implement the MOU, it will be necessary for the CPUC to modify or rescind these
decisions.
In light of SCE's liquidity crisis, its Board of Directors did not declare quarterly common stock dividends to
SCE's parent, Edison International, in December 2000, March 2001 or June 2001. 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 $11 million as of July 31, 2001. As a result of the $2.5 billion charge to earnings as
of December 31, 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, unless SCE meets certain conditions under which
dividends can be paid from sources other than retained earnings. SCE does not meet these conditions. As long as
accumulated dividends in arrears on SCE's preferred stock remain unpaid, SCE cannot pay any dividends on its
common stock.
In addition to the above, SCE has implemented cost-cutting measures which, together with previously announced
actions, such as freezing new hires, postponing certain capital expenditures and ceasing new charitable
contributions, are aimed at reducing general operating costs. SCE's current cost-cutting measures are intended
to allow it to continue to operate while efforts to reach a regulatory solution, involving both state and federal
authorities, are underway. Additional actions by SCE may be necessary if the energy and liquidity crisis is not
resolved in the near future.
For a more detailed discussion of the matters discussed above, see Notes 3 through 7.
SCE's future liquidity depends, in large part, on whether action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow deficit created by the current rate
structure and the volatility in the price of wholesale electricity and natural gas. Without a change in
circumstances, resolution of SCE's liquidity crisis and its ability to continue to operate outside of bankruptcy
is uncertain. SCE's independent public accountant's opinion on the accompanying financial statements includes an
explanatory paragraph which states that the issues resulting from the California energy crisis raise substantial
doubt about SCE's ability to continue as a going concern.
Page 15
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Regulatory Matters
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 SCE's nuclear
plants. Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract. Most of the remaining transition costs may be recovered through the end of the transition period (not
later than March 31, 2002). Although the MOU provides for, among other things, SCE to be entitled to sufficient
revenue to cover its costs associated with retained generation and existing power contracts since January 2001,
the implementation of the MOU requires the CPUC to modify various decisions. Until the regulatory and
legislative actions that make such recovery probable are taken, SCE is 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 net regulatory assets related to certain generating assets are probable of recovery through the
rate-making process. As a result, these balances were written off as a charge to earnings as of December 31,
2000.
During the rate freeze period, there are three sources of revenue available to SCE for transition cost recovery:
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 sale or valuation of generation assets in excess of book values (state legislation enacted in
January 2001 prohibits the sale of SCE's remaining generation assets until 2006) and from the sale of
SCE-controlled generation into the ISO and PX markets is no longer available to SCE. Net proceeds of the 1998
plant sales were used to reduce transition costs, which otherwise were expected to be collected through the TCBA
mechanism.
Net market revenue from sales of power and capacity from SCE-controlled generation sources was also applied to
transition cost recovery. Increases in market prices for electricity affected SCE in two fundamental ways prior
to the CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue decreased because there was less
or no residual revenue from frozen rates due to higher cost PX and ISO power purchases. Second, transition costs
decreased because there was increased net market revenue due to sales from SCE-controlled generation sources to
the PX at higher prices (accumulated as an overcollection in the coal and hydroelectric balancing accounts).
Although the second effect mitigated the first to some extent, the overall impact on transition cost recovery was
negative because SCE purchased more power than it sold to the PX. In addition, higher market prices for
electricity adversely affected SCE's ability to recover non-transition costs during the rate freeze period.
CTC revenue is determined residually (i.e., CTC revenue is 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 applies to all customers who are using or begin using utility services on or after the CPUC's 1995
restructuring decision date. Residual CTC revenue is calculated through the TRA mechanism. Under CPUC decisions
in existence prior to March 27, 2001, positive residual CTC revenue (TRA overcollections) was transferred to the
TCBA monthly; TRA undercollections were to remain in the TRA until they were offset by overcollections, or the
rate freeze ended, whichever came first. Between May 2000 and June 2001, market prices for electricity were
extremely high and there was insufficient revenue from customers under the frozen rates to cover all costs of
providing service during that period, and therefore there was no positive residual CTC revenue transferred into
the TCBA. In accordance with the March 27,
Page 16
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2001, rate stabilization decision, both positive and negative residual CTC revenue is transferred to the TCBA
on a monthly basis, retroactive to January 1, 1998.
Recalculating the TCBA balance based on the March 2001 decision resulted in positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover SCE's transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000. Between May 2000 and January 18, 2001 (when the CDWR began making power purchases
for SCE's customers), SCE's costs to provide power exceeded revenue from frozen rates. Even though SCE is no
longer supplying its customers with all of their electricity needs, SCE's total transition costs have continued
to exceed revenue from frozen rates. As a result, the cumulative positive residual CTC revenue flowing into the
TCBA mechanism has been reduced from $4.7 billion to $2.7 billion as of June 30, 2001. The cumulative TCBA
undercollection (as recalculated) was $2.9 billion as of December 31, 2000, and $4.2 billion as of June 30,
2001. A summary of the components of this cumulative undercollection as of June 30, 2001, is as follows:
In millions
---------------------------------------------------------------------------------------------------
Transition costs recorded in the TCBA:
QF and interutility costs $ 5,590
Amortization of nuclear-related regulatory assets 3,561
Depreciation of plant assets 656
Other transition costs 760
---------------------------------------------------------------------------------------------------
Total costs 10,567
Revenue available to recover transition costs (6,331)
---------------------------------------------------------------------------------------------------
TCBA undercollections $ 4,236
---------------------------------------------------------------------------------------------------
Unless the regulatory and legislative actions that make such recovery probable are taken, SCE is unable to
conclude that the recalculated TCBA net undercollection is 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 December 31,
2000, and an additional $1.4 billion in TCBA undercollections was charged to earnings for the six months ended
June 30, 2001. In its interim rate stabilization decision of March 27, 2001, the CPUC denied SCE's motion to end
the rate freeze, and stated that it will not end until recovery of all specified transition costs (including TCBA
undercollections as recalculated) or March 31, 2002.
Rate Stabilization Proceedings
In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the
current rate freeze ends 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. SCE's plan included a trigger mechanism allowing for rate
increases of 5% every six months if SCE's TRA undercollection balance exceeds $1 billion.
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 covers, 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. On April 3, 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
Page 17
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. The MOU calls for the CPUC to adopt a decision clarifying that the first priority
condition in SCE's 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 provide assurance that the CPUC will adopt such a decision, or predict what effects this
investigation or any subsequent actions by the CPUC may have on SCE.
On March 27, 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 on January 4, 2001, is now permanent. 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 on June 3, 2001. The CPUC also
ordered that the 3(cent)surcharge be added to the rate paid to the CDWR.
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. SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior residual CTC revenue recorded in the TCBA, thus
only affecting the amount of transition cost recovery achieved to date. 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
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. If the
CPUC does not modify this decision in a manner acceptable to SCE, SCE intends to challenge this decision through
all appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 2001 order, it has allocated the
revenue from the increase entirely to future purchased-power costs without addressing SCE's past undercollections
for the costs of purchased power. The CPUC's decisions do not assure that SCE will be able to meet its ongoing
obligations or repay past due obligations. By ordering immediate payments to the CDWR and QFs, the CPUC impacted
SCE's future cash flow and liquidity problems. Additionally, the CPUC stated that Assembly Bill 1 (First
Extraordinary Session, AB 1X) continues the utilities' obligations to serve their customers, and stated that it
cannot assume that the CDWR will purchase all the electricity needed above what the utilities either generate or
have under contract (the net short position) and cannot order the CDWR to do so. This could result in additional
purchased power costs with no allowed means of recovery. To take action that will restore SCE's
creditworthiness, it will be necessary for the CPUC to modify or rescind these decisions. SCE cannot provide any
assurance that the CPUC will do so.
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. On December 15, 2000, the FERC
Page 18
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
released a final order containing remedies and other actions in response to the problems in the California
electricity market. The order, among other things, eliminated the requirement for California utilities to
buy and sell power exclusively through the ISO and PX; created a benchmark price for wholesale bilateral power
contracts; created penalties for under-scheduling power loads; provided for an independent governing board
for the ISO; and established a breakpoint of $150/MWh so that bids below $150 may clear at a single market-clearing
price at or below $150/MWh and bids above $150 will be paid as bid. On December 18, 2000, SCE filed with the
FERC an emergency request for rehearing of the December 15 order. On January 12, 2001, the FERC issued an
order granting rehearing for the purpose of further consideration. The PX did not immediately implement the
$150/MWh breakpoint and on February 26, 2001, made a compliance filing with the FERC, which requested the
FERC's guidance on an acceptable recalculation methodology.
In December 2000, 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. On January 5, 2001, the court denied
SCE's petition. SCE's petition for rehearing remains pending. SCE is considering the possibility of judicial
appeals and other actions.
In December 2000, the ISO announced that generators of electricity were refusing to sell into the California
market due to concerns about the financial stability of SCE and Pacific Gas and Electric Company (PG&E). In
response to this announcement, on December 14, 2000, the United States Secretary of Energy issued an order
requiring power companies to make arrangements to generate and deliver electricity as requested by the ISO after
the ISO certifies that it has been unable to acquire adequate supplies of electricity in the market. After being
renewed multiple times, the order expired on February 6, 2001. However, on February 7, 2001, a federal court
judge issued a temporary restraining order requiring power suppliers to sell to the California grid. On
March 21, 2001, a federal court judge ordered one of the power suppliers to continue to sell power to the
California grid. The three other power suppliers have signed an agreement with the judge voluntarily agreeing to
continue to sell power to the grid while awaiting a review of the issue by the FERC. On April 6, 2001, the
United States Court of Appeals issued a stay order, suspending the lower Court's March 21 order until a final
appeals ruling can be issued.
In December 2000, the FERC established a penalty applicable to scheduling coordinators that do not schedule
sufficient resources to supply 95% of their respective loads. SCE has sought a suspension of the so-called
"underscheduling penalty." SCE has also sought a rehearing of a FERC order, issued in May 2001, which rejected
the ISO's proposal for suspension of the underscheduling penalty. In the May 2001 order, the FERC also indicated
that it will make a determination regarding the suspension of the underscheduling penalty in a future order on a
complaint filed by SCE and PG&E that asked the FERC to eliminate the penalty. As of July 2001, the statewide
accumulated penalties were estimated by the ISO to be approximately $1 billion. 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, 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. The new approach replaces the $150/MWh
breakpoint discussed above.
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 to the ISO and PX spot markets during the period
from October 2, 2000, through June 20, 2001, and adopted a refund methodology based
Page 19
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
on daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter.
A prehearing conference is scheduled for August 13, 2001.
Memorandum of Understanding with the CDWR
On April 9, 2001, SCE signed an MOU with the CDWR regarding the California energy crisis and its effects on SCE.
The Governor of California and his representatives participated in the negotiation of the MOU, and the Governor
endorsed implementation of all the elements of the MOU. The MOU sets forth a comprehensive plan calling for
state legislation and regulatory action and definitive agreements to resolve important aspects of the energy
crisis, and which, if implemented, is expected to help restore SCE's creditworthiness and liquidity. Key
elements of the MOU include:
o SCE will sell its transmission assets to the CDWR, or another authorized state agency, at a price equal to
2.3 times their aggregate book value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, SCE's hydroelectric assets and other rights may be sold to the
state in their place. SCE will use the proceeds of the sale in excess of book value to reduce its
undercollected costs and retire outstanding debt incurred in financing those costs. SCE will agree to
operate and maintain the transmission assets for at least three years, for a fee to be negotiated.
o Two dedicated rate components will be established to assist SCE in recovering the net undercollected amount
of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the undercollected amount over the
expected gain on sale of SCE's transmission assets, as well as certain other costs. Such securitization
will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of
other conditions of the MOU. The second dedicated rate component would not be securitized and would not
appear in rates unless the transmission sale failed to close within a two-year period. The second component
is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be
recovered through the gain on the transmission sale.
o SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through
2010. SCE will be entitled to collect revenue sufficient to cover its costs from January 1, 2001,
associated with the retained generation assets and existing power contracts. The MOU calls for the CPUC to
adopt cost recovery mechanisms consistent with SCE obtaining and maintaining an investment grade credit
rating.
o The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers
within SCE's service territory through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are referred to as SCE's net short
position.) SCE will resume procurement of its net short position after 2002. The MOU calls for the CPUC to
adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility.
o SCE's authorized return on equity will not be reduced below its current level of 11.6% before December 31,
2010. Through the same date, a rate-making capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth in current authorizations. These
measures are intended to enable SCE to achieve and maintain an investment-grade credit rating.
o Edison International and SCE will commit to make capital investments in the utility of at least $3 billion
through 2006, or a lesser amount approved by the CPUC. The equity component of the investments
Page 20
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
will be funded from SCE's retained earnings or, if necessary, from equity investments by Edison International.
o Edison Mission Energy (an affiliate of Edison International) will execute a contract with the CDWR for the
provision of power from a designated project to the state at cost-based rates for 10 years. The Sunrise
power project, which meets this obligation, began commercial operation on June 27, 2001.
o SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with
SCE's Big Creek and Eastern Sierra hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the state, but ultimately may be assigned to nonprofit entities or certain governmental
agencies. SCE will be permitted to continue utility uses of the subject lands.
o After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its
federal district court lawsuit against the CPUC seeking recovery of past undercollected costs. The
settlement or dismissal will include related claims against the state or any of its agencies, or against the
federal government.
The sale of SCE's transmission system and other elements of the MOU must be approved by the FERC. SCE and the
CDWR committed in the MOU to proceed in good faith to sponsor and support the required state legislation and to
negotiate in good faith the necessary definitive agreements. The MOU may be terminated by either SCE or the CDWR
if required legislation is not adopted and definitive agreements are not executed by August 15, 2001, or if
certain other adverse changes occur. Since the required legislation will not be enacted, necessary regulatory
actions will not be taken, and definitive agreements will not be executed before the applicable deadlines, the
MOU will be terminable unless the parties choose to extend the deadlines.
Since the execution of the MOU, SCE has made several filings with the CPUC addressing elements of the MOU.
Although the CPUC did not adopt the implementing decisions contemplated by the MOU within the projected timeframe
set out in the MOU, the CPUC continues to process SCE's filings. However, SCE cannot assure that the necessary
implementing decisions will be passed, nor whether any decisions ultimately adopted will be acceptable to SCE.
Legislation to address the MOU and issues relating to SCE's creditworthiness has been introduced in both the
California State Senate and Assembly as part of the 2001-02 Second Extraordinary Session.
Senate Bill 78XX was introduced in May 2001. As introduced, the bill would have implemented the MOU in its
entirety. However, Senate Bill 78XX was significantly amended in July. As amended, Senate Bill 78XX would allow
SCE to securitize a significant portion of the past procurement undercollections, but would not allow SCE to
recover from ratepayers unpaid PX and ISO costs aggregating approximately $1 billion, or interest accruing on the
past procurement undercollections after January 31, 2001 (estimated to be approximately $400 million by year end
2001). The bill would provide the State of California with a five-year option to purchase SCE's transmission
system at book value, and contains provisions for conservation easements similar to the MOU. SCE opposed Senate
Bill 78XX on the grounds that SCE did not believe that the bill would provide the elements necessary to return
SCE to investment grade credit status and it believed that other provisions of the bill were also objectionable.
Senate Bill 78XX was approved by the Senate on July 20, 2001, and was referred to the State Assembly. The
leadership of the Assembly has indicated its intent to amend the bill. If amended by the Assembly, the amended
bill would return to the State Senate for a concurrence vote (the Senate must accept the bill as passed by the
Assembly or the bill is rejected). The bill would reach the Governor's desk only if agreed to by the Senate. In
the alternative, the Senate and Assembly could agree to refer the bill to a Conference Committee.
Page 21
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Assembly introduced two bills, Assembly Bill 82XX and Assembly Bill 50XX. Assembly Bill 50XX would have
allowed for recovery of all but $300 million of SCE's past procurement-related debt with no sale of SCE's
transmission assets or grant of conservation easements. SCE supported this bill as most likely to return SCE to
investment grade credit status. However, Assembly Bill 50XX was not approved by the Assembly Appropriations
Committee. Assembly Bill 82XX was approved by both the Assembly Policy and Appropriations Committees, and is
currently on the floor of the Assembly. That bill would allow SCE to securitize all of its net past procurement
undercollection except for $500 million, and would authorize the sale of SCE's transmission assets. In
committee, SCE was supportive of Assembly Bill 82XX, but advocated amendments.
The Legislature is in recess until August 20, 2001. During the summer interim recess, a working group of certain
Assembly members has been formed to identify additional amendments to Assembly Bill 82XX and/or to propose
amendments to Senate Bill 78XX. SCE continues to work with the authors of all the bills. However, SCE cannot
assure that legislation will be passed, nor whether any such legislation will ultimately be acceptable to SCE or
would be signed by the Governor.
Utility Retained Generation
In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
ratemaking for utility retained generation through the end of 2002. The 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. SCE proposed a
fifth balancing account to track generation-related undercollections incurred before January 31, 2001. Hearings
were held in July 2001. A final decision is expected later in 2001.
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. On February 1, 2001, 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 revenue bonds to finance electricity purchases. On May 10, 2001,
the Governor signed a bill authorizing the CDWR to issue up to $13.4 billion in bonds. The law became effective
on August 8, 2001. AB 1X directed the CPUC to determine the amount of the CPA as a residual amount of SCE's
generation-related revenue, after deducting the cost of SCE-owned generation, QF contracts, existing bilateral
contracts and ancillary services. AB 1X also directed the CPUC to determine the amount of the CPA that is
allocable to the power sold by the CDWR, which will be payable to the CDWR when received by SCE. On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's purchases are not subject to prudency
review by the CPUC, and that the CPUC must approve and impose, either as a part of existing rates or as
additional rates, rates sufficient to enable the CDWR to recover its revenue requirements.
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
Page 22
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 July 23, 2001, the CDWR submitted a proposed $13.1 billion revenue requirement to the CPUC (revised to $12.6
billion on August 7, 2001) to pay its bonds' costs and energy procurement costs for 2001 and 2002. In comments
filed with the CPUC on August 3, 2001, SCE indicated that based on the CDWR methodology, SCE's share of the $13.1
billion revenue requirement would be approximately $5.8 billion, which would require SCE to increase its current
payment to the CDWR from 10.277(cent)per kWh to 15.9(cent)per kWh. SCE requested that the CPUC refrain from adopting a
final revenue requirement until all parties receive information that is essential to understanding how the
revenue requirement was calculated and its relationship to the utilities' revenue requirement. SCE also
requested that the CPUC adopt fundamental principles, such as cost of service, to guide its view of the CDWR
revenue requirement. The CPUC will allow parties to file supplemental comments on the CDWR's revised revenue
requirement on August 14, 2001. To take actions that will make SCE creditworthy, the CPUC will need to provide
reasonable assurance that SCE will be able to recover its ongoing costs, including the costs associated with
CDWR's revenue requirement.
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 has
stated that it is only purchasing 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, takes 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 CDWR or the ISO for sale to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs (and pre-tax loss) for the six months ended June 30, 2001, could increase by as much as
$1.9 billion (which includes bills received for January through May 2001, and an estimate of June 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 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. On April 6, 2001,
the FERC issued an order confirming its February 14, 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. 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, the day after the Governor signed the order authorizing the CDWR to begin
purchasing power for utility customers. SCE cannot predict the outcome of any of these proceedings or issues.
The MOU states that the CDWR will assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the extent those needs are not met by
generation sources owned by or under contract to SCE (SCE's net short position). Under the MOU, SCE will resume
buying power for its net short position after 2002. The MOU calls for the CPUC to adopt cost-recovery mechanisms
to make it financially practicable for SCE to reassume this responsibility.
Hydroelectric Market Value Filing
In 1999, SCE filed an application with the CPUC establishing a market value for its hydroelectric
generation-related assets at approximately $1.0 billion (almost twice the assets' book value) and proposing to
retain and operate the hydroelectric assets under a performance-based, revenue-sharing mechanism. If approved by
the CPUC, SCE would be allowed to recover an authorized, inflation-indexed
Page 23
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
operations and maintenance allowance, as well as a reasonable return on capital investment. A revenue-sharing
arrangement would be activated if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue to ratepayers or recover 90%
of any shortfall from ratepayers. If the MOU is implemented, SCE's hydroelectric assets will be retained through
2010 under cost-based rates, or they may be sold to the state if a sale of SCE's transmission assets is not
completed under certain circumstances.
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 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 June 30, 2001,
SCE's bilateral forward contracts had a nominal value of $419 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 June 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 will be 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
Page 24
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. If the MOU is implemented, SCE will relinquish all claims against
the state for seizing these contracts. If the MOU is not implemented, SCE believes that it should be compensated for the
reasonable value of these contracts under law, and would pursue the matter. SCE's June 30, 2001, balance sheet
does not include these contracts. As of June 30, 2001, SCE did not have any derivatives as defined by the new
accounting standard that were not considered normal purchases or sales.
Fair values of financial instruments were:
June 30, December 31, June 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------
Cost Fair Cost Fair Cost Fair
Instrument Basis Value Basis Value Basis Value
-------------------------------------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $ 1,699 $ 2,406 $ 1,720 $ 2,505 $ 1,710 $ 2,546
Gas call options -- -- -- -- 22 99
Financial liabilities:
DOE decommissioning and
decontamination fees 36 24 36 31 40 33
Interest rate swap -- -- -- 21 -- 12
Short-term debt 2,121 1,983 1,451 1,339 855 855
Long-term debt 3,231 3,093 5,631 5,178 4,850 4,712
Long-term debt classified as
due within one year 2,797 2,205 646 632 648 650
Preferred stock subject to
mandatory redemption 151 38 256 157 256 256
Preferred stock to be redeemed
within one year 105 26 -- -- -- --
-------------------------------------------------------------------------------------------------------------
Financial assets are carried at their fair value 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 June 30, 2001, December 31, 2000, and June 30,
2000.
Gross unrealized holding gains on debt and equity investments were:
June 30, December 31, June 30,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $ 163 $ 193 $ 230
Stocks 358 384 420
U.S. government issues 111 136 132
Short-term and other 75 72 54
---------------------------------------------------------------------------------------------------------------
Total $ 707 $ 785 $ 836
---------------------------------------------------------------------------------------------------------------
There were no unrealized holding losses for the periods presented.
Page 25
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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' 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, $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 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 26
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt consisted of:
June 30, December 31, June 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%) 1,612 1,724 1,857
Pollution control bonds:
2008 - 2040 (5.125% to 7.2% and variable) 1,217 1,216 1,196
Bonds repurchased (550) (420) --
Funds held by trustees (20) (20) (2)
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 70 79 49
Long-term debt classified as due within one year (2,797) (646) (648)
Unamortized debt discount - net (26) (27) (27)
-------------------------------------------------------------------------------------------------------------------
Total $ 3,231 $ 5,631 $ 4,850
-------------------------------------------------------------------------------------------------------------------
Long-term debt maturities and sinking-fund requirements for the five twelve-month periods following June 30,
2001, are: 2002 - $947 million; 2003 - $572 million; 2004 - $1.2 billion; 2005 - $372 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 temporarily suspended payments of certain
obligations. As of July 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 the 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. 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.
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.
Page 27
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Short-term debt consisted of:
June 30, December 31, June 30,
In millions 2001 2000 2000
----------------------------------------------------------------------------------------------------------
Commercial paper $ 541 $ 700 $ 734
Bank loans 1,650 835 --
Floating rate notes -- -- 175
Amount reclassified as long-term debt (70) (79) (49)
Unamortized discount -- (5) (5)
----------------------------------------------------------------------------------------------------------
Total $ 2,121 $ 1,451 $ 855
----------------------------------------------------------------------------------------------------------
Weighted-average interest rate 6.4% 6.9% 6.6%
At June 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 expires on September 15, 2001. SCE's $400 million in bilateral
credit agreements expire in late September 2001. The remainder expire in May 2002.
SCE has conserved cash by deferring payment of $531 million of matured commercial paper as of July 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 June 30, 2001, are: 2002 -
$105 million; 2003 - $9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.
Page 28
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
June 30, December 31, June 30,
Dollars in millions, except per share amounts 2001 2000 2000
-----------------------------------------------------------------------------------------------------------------------
June 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, six and twelve months ended June 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 July 31, 2001, SCE's preferred stock dividends in arrears were $11 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.
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 29
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net accumulated deferred income tax liability were:
June 30, December 31, June 30,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Property-related $ 220 $ 277 $ 188
Unrealized gains or losses 363 420 470
Investment tax credits 77 81 98
Regulatory balancing accounts 2,216 1,763 69
Decommissioning 88 98 131
Accrued charges 427 379 294
Unbilled revenue 102 101 116
Other 150 56 81
---------------------------------------------------------------------------------------------------------------
Total $ 3,643 $ 3,175 $ 1,447
---------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $ 2,241 $ 2,184 $ 2,490
Capitalized software costs 222 264 241
Regulatory balancing accounts 2,115 1,632 518
Unrealized gains and losses 261 317 367
Other 287 242 456
---------------------------------------------------------------------------------------------------------------
Total $ 5,126 $ 4,639 $ 4,072
---------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net $ 1,483 $ 1,464 $ 2,625
---------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $ 2,062 $ 2,009 $ 3,150
Included in current assets 579 545 525
The current and deferred components of income tax expense were:
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Current:
Federal $ (122) $ 151 $ (294) $ 283 $ (682) $ 518
State -- 39 -- 69 (69) 130
-------------------------------------------------------------------------------------------------------------------
(122) 190 (294) 352 (751) 648
-------------------------------------------------------------------------------------------------------------------
Deferred - federal and state:
Accrued charges (26) (40) (34) (49) (119) (139)
Contributions in aid of construction (9) (6) (3) (1) (12) (11)
Property related 56 (45) 118 (92) (91) (190)
Investment and energy tax credits - net 2 (11) (2) (21) (23) (44)
Operating loss carryforwards (61) -- (111) -- (126) --
Regulatory assets (28) 13 (81) 14 156 9
Regulatory balancing accounts 203 44 10 34 (764) 269
State tax privilege year 19 (13) 9 3 36 (17)
Unbilled revenue (10) (3) (11) 5 4 (14)
Decommissioning fund withdrawals 7 4 11 6 23 10
Other 2 4 11 6 12 (1)
-------------------------------------------------------------------------------------------------------------------
155 (53) (83) (95) (904) (128)
-------------------------------------------------------------------------------------------------------------------
Total $ 33 $ 137 $ (377) $ 257 $ (1,655) $ 520
-------------------------------------------------------------------------------------------------------------------
The composite federal and state statutory income tax rate was 40.551% for all periods presented.
Page 30
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The federal statutory income tax rate is reconciled to the effective tax rate below:
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Capitalized software (3.7) (0.9) 0.5 (0.9) 0.2 (2.1)
Property-related and other 7.2 6.7 (0.4) 9.7 (3.6) 9.1
Investment and energy tax credits 3.3 (3.5) 0.2 (3.9) 0.5 (3.7)
State tax - net of federal deduction 7.8 8.6 5.1 7.8 4.5 8.2
-------------------------------------------------------------------------------------------------------------------
Effective tax rate 49.6% 45.9% 40.4% 47.7% 36.6% 46.5%
-------------------------------------------------------------------------------------------------------------------
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 $7 million, $14 million and $29 million for the three, six and twelve months
ended June 30, 2001, respectively, and $6 million, $15 million and $27 million for the three, six and twelve
months ended June 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 31
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
6 Months Ended Year Ended 6 Months Ended
June 30, December 31, June 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 2,200 $ 2,075 $ 2,075
Service cost 34 63 32
Interest cost 76 155 78
Actuarial loss -- 90 --
Benefits paid (109) (183) (89)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 2,201 $ 2,200 $ 2,096
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 3,067 $ 3,078 $ 3,078
Actual return on plan assets (100) 143 226
Employer contributions -- 29 29
Benefits paid (109) (183) (89)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 2,858 $ 3,067 $ 3,244
-------------------------------------------------------------------------------------------------------------------
Funded status $ 657 $ 867 $ 1,148
Unrecognized net loss (gain) (503) (745) (1,104)
Unrecognized transition obligation 20 22 26
Unrecognized prior service cost 110 118 124
-------------------------------------------------------------------------------------------------------------------
Recorded asset $ 284 $ 262 $ 194
-------------------------------------------------------------------------------------------------------------------
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 6 Months Ended 12 Months Ended
In millions June 30, June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 17 $ 16 $ 34 $ 32 $ 65 $ 64
Interest cost 38 39 76 78 153 148
Expected return on plan assets (63) (57) (126) (114) (278) (206)
Net amortization and deferral (3) (8) (6) (16) (30) (9)
-------------------------------------------------------------------------------------------------------------------
Pension expense (benefit) under
accounting standards (11) (10) (22) (20) (90) (3)
Regulatory adjustment - deferred 11 10 22 20 90 27
-------------------------------------------------------------------------------------------------------------------
Net pension expense recognized $ -- $ -- $ -- $ -- $ -- $ 24
-------------------------------------------------------------------------------------------------------------------
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 32
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
6 Months Ended Year Ended 6 Months Ended
June 30, December 31, June 30,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 1,762 $ 1,462 $ 1,462
Service cost 22 39 18
Interest cost 66 121 58
Actuarial loss -- 202 --
Benefits paid (34) (62) (30)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 1,816 $ 1,762 $ 1,508
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 1,200 $ 1,283 $ 1,283
Actual return on plan assets 52 (40) 46
Employer contributions 10 19 42
Benefits paid (34) (62) (30)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 1,228 $ 1,200 $ 1,341
-------------------------------------------------------------------------------------------------------------------
Funded status $ (588) $ (562) $ (167)
Unrecognized net loss (gain) 141 141 (205)
Unrecognized transition obligation 311 323 335
-------------------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (136) $ (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 6 Months Ended 12 Months Ended
In millions June 30, June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 11 $ 9 $ 22 $ 18 $ 43 $ 42
Interest cost 33 29 66 58 129 115
Expected return on plan assets (26) (23) (52) (46) (112) (87)
Net amortization and deferral 6 6 12 12 27 25
-------------------------------------------------------------------------------------------------------------------
Total expense $ 24 $ 21 $ 48 $ 42 $ 87 $ 95
-------------------------------------------------------------------------------------------------------------------
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 June 30, 2001, by $286 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 June 30, 2001, by $246 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 33
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.
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 the Edison International Executive Severance Plan, the terminated executive must exercise vested
options within 12 months. All unvested options are forfeited on the date of termination.
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 zero, zero and $2 million
Page 34
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three, six and twelve months ended June 30, 2001, respectively, and $1 million, $2 million and $5 million
for the three, six and twelve months ended June 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 $25 million, $(574) million and $(2.896) billion for the three, six
and twelve months ended June 30, 2001, respectively, and $156 million, $270 million and $569 million for the
three, six and twelve months ended June 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:
June 30, June 30,
2001 2000
----------------------------------------------------------------------------------------------------------
Expected life 7 years - 10 years 7 years - 10 years
Risk-free interest rate 4.7% - 6.1% 4.7% - 6.1%
Expected volatility 17% - 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 June 30, 2001, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 40 $ 11 $ 1 60%
Pacific Intertie 230 82 8 50%
Generating stations:
Four Corners Units 4 and 5 (coal) 463 358 4 48%
Mohave (coal) 331 244 2 56%
Palo Verde (nuclear)(1) 1,628 1,522 16 16%
San Onofre (nuclear)(1) 4,272 4,024 26 75%
-------------------------------------------------------------------------------------------------------------------
Total $ 6,964 $ 6,241 $ 57
-------------------------------------------------------------------------------------------------------------------
(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 35
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 June 30, 2001, were:
Year ended December 31, In millions
-------------------------------------------------------------------------------------------------
2001 $ 8
2002 13
2003 12
2004 10
2005 8
Thereafter 17
-------------------------------------------------------------------------------------------------
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. These costs are expected
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 $16 million, $27 million and $72 million for the three, six and twelve months ended
June 30, 2001, respectively, and $38 million, $61 million and $115 million for the three, six and twelve months
ended June 30, 2000. The accumulated provision for decommissioning, excluding San Onofre Unit 1, was
$1.4 billion at June 30, 2001, at December 31, 2000, and at June 30, 2000. The estimated costs to decommission
San Onofre Unit 1 (approximately $328 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 36
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Trust investments (cost basis) include:
Maturity June 30, December 31, June 30,
In millions Dates 2001 2000 2000
----------------------------------------------------------------------------------------------------------------
Municipal bonds 2001 - 2029 $ 499 $ 548 $ 668
Stocks -- 605 531 473
U.S. government issues 2002 - 2029 372 421 401
Short-term and other 2001 223 220 168
----------------------------------------------------------------------------------------------------------------
Total $ 1,699 $ 1,720 $ 1,710
----------------------------------------------------------------------------------------------------------------
Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated
provision for decommissioning. Net earnings (loss) were $(3) million, $(16) million and $(9) million for the
three, six and twelve months ended June 30, 2001, respectively, and $22 million, $31 million and $65 million for
the three, six and twelve months ended June 30, 2000, respectively. Proceeds from sales of securities (which are
reinvested) were $532 million, $1.3 billion and $3.4 billion for the three, six and twelve months ended June 30,
2001, respectively, and $807 million, $2.5 billion and $4.1 billion for the three, six and twelve months ended
June 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 $ 143 $ 108 $ 108 $ 97 $ 97
Purchased-power capacity payments 636 629 629 626 624
------------------------------------------------------------------------------------------------------------
Page 37
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. SCE and Edison International have until September 17, 2001, to
respond to the consolidated complaint. 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 largely been coordinated before a single trial judge. SCE has reached agreements with QFs
representing about 95% of the QF renewable and cogeneration energy 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.
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 other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 44 identified sites is $116 million. The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable
data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably
Page 38
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
possible that cleanup costs could exceed its recorded liability by up to $272 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 $46 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. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has
recorded a regulatory asset of $75 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 $20 million. Recorded expenditures for the
twelve months ended June 30, 2001, were $19 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. 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
Page 39
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
programs, SCE could be assessed retrospective premium adjustments of up to $19 million per year. 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, is constructing an interim fuel
storage facility that is expected to be completed in 2002.
Page 40
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), are currently
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 1(cent)-per-kWh and 3(cent)-per-kWh surcharges effective first quarter 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 financial drain on SCE.
On April 9, 2001, SCE and the California Department of Water Resources (CDWR) executed a memorandum of
understanding (MOU) which sets forth a comprehensive plan calling for legislation, regulatory action and
definitive agreements to resolve important aspects of the energy crisis, and which is expected to help restore
SCE's creditworthiness and liquidity. The Governor of California and his representatives participated in the
negotiation of the MOU, and the Governor endorsed implementation of all the elements of the MOU. SCE and the
CDWR committed in the MOU to proceed in good faith to sponsor and support the required legislation and to
negotiate in good faith the necessary definitive agreements. The legislation required to implement the MOU is in
doubt and a number of alternative measures have been proposed in the legislature. See further discussion in
Memorandum of Understanding with the CDWR.
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 determined that
regulatory assets, such as the TRA and the TCBA, were no longer probable of recovery through future rates, they
were 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.
Until legislative and regulatory actions are taken, SCE is unable to conclude that its undercollected costs that
are recovered through the TCBA mechanism are probable of recovery in future rates. As a result, SCE's financial
results for the year ended December 31, 2000, included an after-tax charge of approximately $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. In addition, SCE currently does not have regulatory
authority to recover any purchased-power costs it incurs during 2001 in excess of revenue from retail rates.
Transition costs in excess of transition revenue are charged against earnings in 2001 absent a regulatory or
legislative solution, such as implementation of the actions called for in the MOU that make recovery of such
costs probable. Unrecovered transition costs charged to earnings were $724 million (after tax) for the six
months ended 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. The December 31, 2000, write-off also caused SCE to be unable to meet an earnings test
that must be met before SCE can issue additional first mortgage bonds. If a rate mechanism provided by
legislation or regulatory authority is established that makes recovery from regulated rates probable as to all or
a portion of the amounts that were previously charged against earnings, accounting standards provide that a
regulatory asset would be reinstated with a corresponding increase in earnings.
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The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the
devastating 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 possible resolution of the current crisis through implementation of the MOU or other corrective action.
Results of Operations
Earnings
SCE earned $28 million for the three months ended June 30, 2001, and recorded a loss of $570 million, and $2.9
billion, respectively, for the six and twelve months ended June 30, 2001. SCE's second quarter earnings included
$63 million (after tax) of transition costs in excess of transition revenue during the second quarter of 2001.
The year-to-date and twelve-months-ended losses reflect $724 million (after tax) of transition costs in excess of
transition revenue during the first six months of 2001. For financial reporting purposes, these undercollected
costs are no longer accumulated in the TCBA for financial reporting purposes and instead are expensed as
incurred. 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 new 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). The implementation
of the MOU (see further discussion in Memorandum of Understanding with the CDWR) requires various regulatory and
legislative actions to be taken in the future. Until those actions or other corrective actions in other
proceedings are taken, which would include modifying or reversing recent CPUC decisions that impair recovery of
SCE's power procurement and transition costs, SCE is 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.
If and when regulatory and legislative actions are taken that make such recovery probable, the regulatory assets
written off as of December 31, 2000, and the undercollected costs incurred in 2001, would be restored to the
balance sheet, with a corresponding increase to earnings of approximately $3.2 billion (after tax).
As stated above, SCE earned $28 million and recorded losses of $570 million and $2.9 billion, respectively, for
the three, six and twelve months ended June 30, 2001, compared with earnings of $156 million, $270 million and
$570 million, respectively, for the same periods in 2000. Excluding the undercollected transition costs that are
no longer accumulated in balancing accounts for financial reporting purposes and instead are expensed as incurred
($63 million after tax), SCE's second quarter 2001 earnings were $91 million, down $65 million from the
prior-year period. The quarterly decrease was mainly due to lower earnings resulting from the February 2001 fire
and resulting outage at the San Onofre Nuclear Generating Station (see further discussion of the fire in the San
Onofre Nuclear Generating Station section) and higher interest expense resulting from SCE's deteriorated
financial condition. Excluding the $724 million (after tax) of undercollected transition costs expensed in the
first six months of
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2001, SCE would have earned $154 million for the year-to-date period ended June 30, 2001. The $116 million decrease
for the six-month period ended June 30, 2001, from the same period in 2000, was mostly the result of lower earnings
resulting from the February 2001 fire and resulting outage at San Onofre and higher interest expense. Excluding the
$724 million (after tax) of undercollected transition costs expended in 2001 and the $2.5 billion (after tax)
December 31, 2000, write-off, SCE would have earned $356 million for the twelve months ended June 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 June 30, 2000, were $556 million. The $200 million decrease for the twelve
months ended June 30, 2001, from the prior-year period, was mainly the result of the outage at San Onofre Unit 3 and
higher interest expense, partially offset by lower operating and maintenance costs.
Unless a rate-making mechanism is implemented in accordance with the MOU described above or other necessary
rate-making action is taken, future net undercollections of transition costs will be charged to earnings as the
losses are incurred. SCE anticipates that the losses resulting from these undercollections will continue unless
a rate-making mechanism is established.
Operating Revenue
SCE's customers are 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
are billed by SCE, but given a credit for the generation portion of their bills. Under Assembly Bill 1 (First
Extraordinary Session, AB 1X), enacted on February 1, 2001, the CPUC was directed (on a schedule it determines)
to suspend the ability of retail customers to select alternative providers of electricity until the CDWR stops
buying power for retail customers. The CPUC has not yet acted on this directive.
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 a reevaluation of the
operation of the interruptible programs can be completed.
Operating revenue decreased for the three, six and twelve months ended June 30, 2001, compared to the same
periods in 2000, primarily because SCE no longer supplies its customers with all of their electricity needs
(since mid-January 2001). Operating revenue was reduced by $461 million, $718 million and $718 million,
respectively, for the three, six and twelve months ended June 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 and year-to-date decreases were also the
result of a 6% decrease in retail sales volume, primarily the result of conservation efforts. The effects of the
1(cent)-per-kWh and 3(cent)-per-kWh surcharges, as well as the credit given to customers who chose direct access
during second quarter 2000 partially offset the quarterly decreases discussed above. The direct access credits
decreased during the second 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. The
year-to-date and twelve-months-ended decreases were also due to decreases 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. Also contributing to the twelve-months-ended decrease in operating
revenue was the credit given to customers who chose direct access , partially offset by an increase related to
interruptible penalty revenue and the effects of the 1(cent)-per-kWh and 3(cent)-per-kWh surcharges effective
first quarter 2001.
More than 93% 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).
page 43
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 both the three and six months ended June 30, 2001, compared with the same periods in
2000, primarily due to a fuel-related refund resulting from a settlement with another utility that SCE recorded
in the second quarter of 2000.
Purchased-power expense increased significantly for the three, six and twelve months ended June 30, 2001,
compared to the same periods in 2000. The increases were the result of increased purchased-power expense related
to qualifying facilities (QFs), bilateral contracts and interutility contracts. The quarterly increase was
partially offset by the absence of purchases from the PX and ISO in 2001. In December 2000, the FERC eliminated
the requirement that SCE buy and sell its purchased and generated 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.
The year-to-date and twelve-months-ended increases were also the result of increased PX/ISO purchased-power
expense. See Purchased Power table in Note 1 to the Consolidated Financial Statements. See further discussion
in CDWR Power Purchases.
Prior to April 1998, SCE was required under federal law and CPUC orders 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. Purchased-power expense related to QFs increased for the three, six and
twelve months ended June 30, 2001, compared to the year-earlier periods. The increases were primarily due to the
short-run avoided cost factor (which is based on the price of natural gas) 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
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. For the twelve months ended June 30, 2001, the
increased volume of higher-priced PX purchases was minimally offset by increases in PX sales revenue and ISO net
revenue, as well as the use of risk management instruments (gas call options and PX block forward contracts).
The gas call options (which were sold in October 2000) and the PX block forward contracts mitigated SCE's
transition cost recovery exposure to increases in energy prices. For the twelve months ended June 30, 2001,
compared to the same period in 2000, purchased-power expense was reduced by $55 million and $432 million,
respectively, due to SCE's use of gas call options and PX block forward contracts.
Provisions for regulatory adjustment clauses decreased for the six months ended June 30, 2001, compared to the
year-earlier period. The decrease primarily resulted from SCE no longer accumulating undercollected transition
costs in the TCBA for financial reporting purposes, as well as undercollections related to the administration of
energy conservation programs and other public benefit programs in 2001. For the six months ended June 30, 2000,
SCE recorded overcollections related to the generation-related balancing accounts. Provisions for regulatory
adjustment clauses increased for the twelve months ended June 30, 2001, compared to the same period in 2000,
mainly due to a $4.0 billion charge to the provisions related to the write-off of regulatory assets and
liabilities as of December 31, 2000. See further discussion of the write-off in the Earnings section. In
addition, the provisions also increased due to adjustments to reflect potential regulatory refunds related to the
outcome of the CPUC's reevaluation of the operation of
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the interruptible rate programs but decreased due to undercollections related to the administration of energy
conservation programs and other public benefit programs. SCE's use of gas call options increased the provisions
by $134 million and $79 million, respectively, for the twelve months ended June 30, 2001, and June 30, 2000.
Depreciation, decommissioning and amortization expense decreased for the three, six and twelve months ended
June 30, 2001, compared to the prior-year periods, primarily due to a decrease in SCE's amortization expense.
Since SCE's December 31, 2000, write-off included the unamortized nuclear investment regulatory asset, SCE has
not recorded any amortization expense related to this asset during the first six months of 2001.
Other Income and Deductions
Interest and dividend income increased for the twelve months ended June 30, 2001, compared to the year-earlier
period, primarily due to an overall higher cash balance as SCE conserves cash due to its liquidity crisis.
Other nonoperating income decreased for the three, six and twelve months ended June 30, 2001. The quarterly and
year-to-date decreases were primarily due to the gains on sales of equity investments during second quarter
2000. The year-to-date decrease was also 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, six and twelve months ended June 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 at SCE also
contributed to the twelve-months-ended increase.
Other nonoperating deductions decreased for the three, six and twelve months ended June 30, 2001, compared to the
same periods in 2000, due to lower accruals for regulatory matters.
Income Taxes
Income taxes decreased for the three, six and twelve months ended June 30, 2001, compared to the year-earlier
periods. The quarterly decrease reflects a $51 million income tax benefit arising from the transition costs in
excess of transition revenue. The year-to-date and twelve-months-ended decreases reflect a $548 million income
tax benefit arising from transition costs in excess of transition revenue during first six 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 is 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 deteriorating financial condition (further discussed in Liquidity Crisis), at June 30, 2001, the
fair market value of $531 million of its short-term debt was approximately 70% of its carrying value.
Liquidity Crisis
Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001. This resulted in
increasing undercollections in the TRA and TCBA. The increasing undercollections, coupled
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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 continued regulatory uncertainty regarding
SCE's ability to recover its current and future power procurement costs, have 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
temporarily suspended payments of certain obligations for principal and interest on outstanding debt and for
purchased power. As of July 31, 2001, SCE had $3.3 billion in obligations that were unpaid and overdue
including: (1) $878 million to the PX or ISO; (2) $1.2 billion to QFs; (3) $230 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. As applicable, unpaid obligations will continue to accrue interest.
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 the 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. 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 CDWR or the ISO for sale to
SCE's customers on or after January 18, 2001, SCE's unpaid obligations as of July 31, 2001, could increase by as
much as $1.9 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 agreed to forbear 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. The $200
million short-term bank credit facility's maturity date has been extended to September 15, 2001, under a
forbearance agreement that has been extended three times and currently expires on the same day. SCE has $400
million in bilateral credit agreements that expire in late September 2001. SCE has not entered into forbearance
agreements with the lenders under the bilateral credit agreements. At July 31, 2001, SCE had estimated cash
reserves of approximately $1.7 billion (after deducting $419 million of designated funds), which was
approximately $1.6 billion less than its outstanding unpaid obligations (discussed above) and overdue amounts of
preferred stock dividends (see below). As of March 31, 2001, SCE resumed payment of interest on its debt
obligations. If the MOU is implemented, it is expected to allow SCE to recover its undercollected costs and to
help restore SCE's creditworthiness, which would allow SCE to pay all of its past due obligations.
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
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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.
Based on these decisions, the uncertainty about the amount of revenue the CDWR will require to pay its bond and
energy procurement costs, and how much of this revenue requirement will be allocated to SCE (see CDWR Power
Purchases), SCE estimates that future cash may not be sufficient to cover retained generation, purchased-power
and transition costs. In comments filed with the CPUC in March and April 2001, SCE provided a forecast showing
that the net effects of the rate increase, the payment ordered to be made to the CDWR, and the QF decision could
result in a shortfall to the CPA calculation during 2001. To implement the MOU, it will be necessary for the
CPUC to modify or rescind these decisions.
In light of SCE's liquidity crisis, its Board of Directors did not declare quarterly common stock dividends to
SCE's parent, Edison International, in December 2000, March 2001 or June 2001. Also, SCE's Board has not declared
the regular quarterly dividends for any of SCE's cumulative preferred stock in 2001. As of July 31, 2001, SCE's
preferred stock dividends in arrears were $11 million. As a result of SCE's $2.5 billion charge to earnings as
of December 31, 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, unless SCE meets certain conditions under which
dividends can be paid from sources other than retained earnings. SCE does not meet these conditions. As long as
accumulated dividends on SCE's preferred stock remain unpaid, SCE cannot pay any dividends on its common stock.
SCE has implemented cost-cutting measures which, together with previously announced actions, such as freezing new
hires, postponing certain capital expenditures and ceasing new charitable contributions, are aimed at reducing
general operating costs. SCE's current cost-cutting measures are intended to allow it to continue to operate
while efforts to reach a regulatory solution, involving both state and federal authorities, are underway.
Additional actions by SCE may be necessary if the energy and liquidity crisis is not resolved in the near
future. 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 an agreement to resolve SCE's crisis, see Memorandum of Understanding
with the CDWR.
SCE's future liquidity depends, in large part, on whether action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow deficit created by the current rate
structure and the volatility in the price of wholesale electricity and natural gas. Without a change in
circumstances, resolution of SCE's liquidity crisis and its ability to continue to operate outside of bankruptcy
is uncertain. SCE's independent accountant's opinion on the accompanying financial statements includes an
explanatory paragraph which states that the issues from the California energy crisis raise substantial doubt
about SCE's ability to continue as a going concern.
Cash Flows from Operating Activities
Despite SCE's net income of $34 million and losses of $559 million and $2.9 billion, respectively, for the three,
six and twelve months ended June 30, 2001, net cash provided by operating activities was $185 million, $1.4
billion and $1.2 billion, primarily due to SCE temporarily suspending payments for interest on outstanding debt
and for purchased power beginning in January 2001. For the second quarter of 2001, cash provided by operations
was negatively affected by SCE resuming the interest payments on its debt obligations and payments to the QFs on
a going-forward basis.
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). For the twelve months
ended June 30, 2001, the cash flow coverage of dividends was 6.3 times compared to 2.7 times for the same period
in 2000. The increase in 2001 reflects SCE's inability to pay dividends, as well as an increase in cash flows
from operating activities, which reflects SCE's conservation of cash.
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SCE's estimates of cash available for operations in 2001 assume, among other things, satisfactory reimbursement
of costs incurred during California's energy crisis, the receipt of adequate and timely rate relief, and the
realization of its assumptions regarding cost increases, including the cost of capital.
Cash Flows from Financing Activities
At June 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 an executed forbearance agreement, SCE's $200 million, 364-day credit facility is due to expire on
September 15, 2001. SCE's $400 million bilateral credit agreements expire in late September 2001. The remainder
expire in May 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, 2001, 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
current liquidity and credit problems, SCE is 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 sell its commercial paper and other short-term
financial instruments.
In January 2001, Fitch IBCA, Standard & Poor's and Moody's Investors Service lowered their credit ratings of SCE
to substantially below investment grade.
Subject to the outcome of regulatory, legislative and judicial proceedings, including steps to implement the MOU,
SCE intends to pay all of its obligations.
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.
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Long-term debt maturities and sinking fund requirements for the five twelve month periods following June 30,
2001, are: 2002 - $947 million; 2003 - $572 million; 2004 - $1.2 billion; 2005 - $372 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 June 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.
SCE's projected construction expenditures for 2001 are $676 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 have 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, but
Page 49
these caps are set at high levels and are not entirely effective (see further discussion in Wholesale Electricity
Markets).
SCE attempted to hedge a portion of its exposure to increases in power prices. However, the CPUC has approved a
very limited amount of hedging. In November 2000, SCE began purchases of energy through bilateral forward
contracts. At June 30, 2001, the nominal value of SCE's bilateral forward contracts was $419 million. See
further discussion of bilateral forward contracts in Note 4 to the Consolidated Financial Statements.
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 temporarily 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. If the MOU is implemented, SCE will relinquish all claims against the state for
seizing these contracts. If the MOU is not implemented, SCE believes that it should be compensated for the
reasonable value of these contracts under law, and would pursue the matter. SCE's June 30, 2001, balance sheet
no longer includes 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.
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 1996, 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 surcharges effective first
quarter 2001) are 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 have escalated far beyond what SCE can currently charge its
customers. See further discussion in Wholesale Electricity Markets.
Generation and Power Procurement
During the rate freeze, revenue from generation-related operations has been determined through the market and
transition cost recovery mechanisms, which included the nuclear rate-making agreements. The portion of revenue
related to coal generation plant costs (Mohave Generating Station and Four Corners Generating Station) that was
made uneconomic by electric industry restructuring was eligible for recovery through the transition cost recovery
mechanisms. After April 1, 1998, coal generation operating costs have been recovered through the market. The
excess of power sales revenue from the coal generating plants over the plants' operating costs has been
accumulated in a coal generation balancing
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account. SCE's costs associated with its hydroelectric plants have been recovered through a performance-based
mechanism. The mechanism set the hydroelectric revenue requirement and established a formula for extending it
through the duration of the electric industry restructuring transition period, or until market valuation of the
hydroelectric facilities, whichever occurred first. The mechanism provided that power sales revenue from
hydroelectric facilities in excess of the hydroelectric revenue requirement is accumulated in a hydroelectric
balancing account. In accordance with a CPUC decision issued in 1997, the credit balances in the coal and
hydroelectric balancing accounts were transferred to the TCBA at the end of 1998 and 1999. However, due to the
CPUC's March 27, 2001, rate stabilization decision, the credit balances in these balancing accounts were transferred
to the TRA on a monthly basis, retroactive to January 1, 1998. In addition, the TRA balance, whether over- or
undercollected, was transferred to the TCBA on a monthly basis, retroactive to January 1, 1998. Due to a December
2000 FERC order, SCE is no longer required to buy and sell power exclusively through the ISO and PX. In mid-January
2001, the PX suspended SCE's trading privileges for failure to post collateral due to SCE's rating agency downgrades.
As a result, power from SCE's coal and hydroelectric plants is no longer being sold through the market and these two
balancing accounts have become inactive. As a key element of the MOU, SCE would continue to own its generation assets,
which would be subject to cost-based ratemaking, through 2010. The MOU calls for the CPUC to adopt cost recovery
mechanisms consistent with SCE obtaining and maintaining an investment grade credit rating.
SCE has 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 are earning an annual rate of return on investment
of 7.35%. In addition, 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 commenced in April 1996, and ends at the earlier of December 2001 or the date when
the statutory rate freeze ends for the accelerated recovery portion, and 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, are subject to balancing account treatment.
The Palo Verde plan commenced in January 1997 and ends in December 2001. On May 4, 2001, SCE requested the CPUC
to extend the Palo Verde plan through December 2002. The CPUC has not yet ruled on this request. The benefits
of operation of the San Onofre units and the Palo Verde units are required to be shared equally with ratepayers
beginning in 2004 and 2002, respectively. On May 4, 2001, SCE requested that the post-2003 and post-2001 benefit
sharing provisions of the current San Onofre and Palo Verde rate-making mechanisms be eliminated contingent upon
implementation of the MOU. 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 and not contingent upon
implementation of the MOU. The CPUC has not yet ruled on SCE's similar request regarding Palo Verde. 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 will continue for rate-making purposes at least through the end of the
rate freeze period. However, due to the various unresolved regulatory and legislative issues (as discussed in
Status of Transition and Power-Procurement Cost Recovery), SCE is no longer able to conclude that the unamortized
nuclear investment regulatory assets (as discussed in Accounting for Generation-Related Assets and Power
Procurement Costs) are probable of recovery through the rate-making process. As a result, these balances were
written off as a charge to earnings as of December 31, 2000 (see further discussion in Earnings).
In 1999, SCE filed an application with the CPUC establishing a market value for its hydroelectric
generation-related assets at approximately $1.0 billion (almost twice the assets' book value) and proposing to
retain and operate the hydroelectric assets under a performance-based, revenue-sharing mechanism. If approved by
the CPUC, SCE would be allowed to recover an authorized, inflation-indexed operations and maintenance allowance,
as well as a reasonable return on capital investment. A revenue-sharing arrangement would be activated if
revenue from the sale of hydroelectricity exceeds or falls short of the authorized revenue requirement. SCE
would then refund 90% of the excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers. If
the MOU is implemented, SCE's hydroelectric assets will be retained through 2010 under cost-based rates, or they
may be sold to the state if a sale of SCE's
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transmission assets is not completed under certain circumstances. In June 2000, SCE credited the TCBA with the
estimated excess of market value over book value of its hydroelectric generation assets and simultaneously
recorded the same amount in the generation asset balancing account (GABA), in accordance with a CPUC decision.
This balance was to remain in GABA until final market valuation of the hydroelectric assets. If there were a
difference in the final market value, it would have been credited to or recovered from customers through the
TCBA. Due to the various unresolved regulatory and legislative issues (as discussed in Status of Transition
and Power-Procurement Cost Recovery), the GABA transaction was reclassified back to the TCBA, and as discussed
in the Earnings section, the TCBA balance (as recalculated based on a March 27, 2001, CPUC interim decision
discussed in Rate Stabilization Proceedings) was written off as of December 31, 2000.
During 2000, SCE entered into agreements to sell its interest in the Mohave, Palo Verde and Four Corners
generation stations. The sales were pending various regulatory approvals. Due to the shortage of electricity in
California and the increasing wholesale costs, state legislation was enacted in January 2001 barring the sale of
utility generation stations until 2006. Under the MOU, SCE would continue to retain its generation assets
through 2010.
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. On February 1, 2001, 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 revenue bonds to finance electricity purchases. On May 10, 2001, the Governor
signed a bill authorizing the CDWR to issue up to $13.4 billion in bonds. The law became effective August 8,
2001. AB 1X directed the CPUC to determine the amount of the CPA as a residual amount of SCE's
generation-related revenue, after deducting the cost of SCE-owned generation, QF contracts, existing bilateral
contracts and ancillary services. AB 1X also directed the CPUC to determine the amount of the CPA that is
allocable to the power sold by the CDWR, which will be payable to the CDWR when received by SCE. On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's purchases are not subject to prudency
review by the CPUC, and that the CPUC must approve and impose, either as a part of existing rates or as
additional rates, rates sufficient to enable the CDWR to recover its revenue requirements.
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 July 23, 2001, the CDWR submitted a proposed $13.1 billion revenue requirement to the CPUC (revised to $12.6
billion on August 7, 2001) to pay its bonds' costs and energy procurement costs for 2001 and 2002. In comments
filed with the CPUC on August 3, 2001, SCE indicated that based on the CDWR methodology, SCE's share of the $13.1
billion revenue requirement would be approximately $5.8 billion, which would require SCE to increase its current
payment to the CDWR from 10.277(cent)per kWh to 15.9(cent)per kWh. SCE requested that the CPUC refrain from adopting a
final revenue requirement until all parties receive information that is essential to understanding how the
revenue requirement was calculated and its
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relationship to the utilities' revenue requirement. SCE also requested that the CPUC adopt fundamental principles,
such as cost of service, to guide its view of the CDWR revenue requirement. The CPUC will allow parties to file
supplemental comments on the CDWR's revised revenue requirement on August 14, 2001. To take actions that will make
SCE creditworthy, the CPUC will need to provide reasonable assurance that SCE will be able to recover its ongoing
costs, including the costs associated with the CDWR's proposed revenue requirement.
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 has
stated that it is only purchasing 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, takes 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 CDWR or ISO for sale to SCE's customers on or after January 18, 2001, SCE's
purchased-power costs (and pre-tax loss) for the six months ended June 30, 2001, could increase by as much as
$1.9 billion (which includes bills received for January through May 2001, and an estimate for June 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 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. On April 6, 2001,
the FERC issued an order confirming its February 14, 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.
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, the day after the Governor signed the order authorizing the CDWR to begin purchasing
power for utility customers. SCE cannot predict the outcome of any of these proceedings or issues. The MOU
states that the CDWR will assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the extent those needs are not met by
generation sources owned by or under contract to SCE (SCE's net short position). Under the MOU, SCE will resume
buying power for its net short position after 2002. The MOU calls for the CPUC to adopt cost-recovery mechanisms
to make it financially practicable for SCE to reassume this responsibility.
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. Most of the remaining transition costs may be recovered through the end of the transition period (not
later than March 31, 2002). Although the MOU provides for, among other things, SCE to be entitled to sufficient
revenue to cover its costs associated with retained generation and existing power contracts since January 2001,
the implementation of the MOU requires the CPUC to modify various decisions (discussed in Rate Stabilization
Proceedings). Until regulatory and legislative actions that make such recovery probable are taken, SCE is 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 net regulatory assets related to certain generating assets are
probable of recovery through the rate-making process. As a result, these balances were written off as a charge
to earnings as of December 31, 2000 (see further discussion in Earnings).
During the rate freeze period, there are three sources of revenue available to SCE for transition cost recovery:
revenue from the sale or valuation of generation assets in excess of book values, net market
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revenue from the sale of SCE-controlled generation into the ISO and PX markets and competition transition charge
(CTC) revenue. Revenue from the sale or valuation of generation assets in excess of book values (state legislation
enacted in January 2001 prohibits the sale of SCE's remaining generation assets until 2006) and from the sale of
SCE-controlled generation into the ISO and PX markets (see discussion in Generation and Power Procurement) is no
longer available to SCE. Net proceeds of the 1998 plant sales were used to reduce transition costs, which
otherwise were expected to be collected through the TCBA mechanism.
Net market revenue from sales of power and capacity from SCE-controlled generation sources was also applied to
transition cost recovery. Increases in market prices for electricity affected SCE in two fundamental ways prior
to the CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue decreased because there was less
or no residual revenue from frozen rates due to higher cost PX and ISO power purchases. Second, transition costs
decreased because there was increased net market revenue due to sales from SCE-controlled generation sources to
the PX at higher prices (accumulated as an overcollection in the coal and hydroelectric balancing accounts).
Although the second effect mitigated the first to some extent, the overall impact on transition cost recovery was
negative because SCE purchased more power than it sold to the PX. In addition, higher market prices for
electricity adversely affected SCE's ability to recover non-transition costs during the rate freeze period.
As discussed in the Status of Transition and Power-Procurement Cost Recovery in Note 3 to the Consolidated
Financial Statements, CTC revenue is determined residually, the CTC applies to all customers who are using or
begin using utility services on or after the CPUC's 1995 restructuring decision date, and residual CTC revenue is
calculated through the TRA mechanism. Under CPUC decisions in existence prior to March 27, 2001, positive
residual CTC revenue (TRA overcollections) was transferred to the TCBA monthly; TRA undercollections were to
remain in the TRA until they were offset by overcollections, or the rate freeze ended, whichever came first.
Between May 2000 and June 2001, market prices for electricity have been extremely high and there was insufficient
revenue from customers under the frozen rates to cover all costs of providing service during that period, and
therefore there was no positive residual CTC revenue transferred into the TCBA. In accordance with the March 27,
2001, rate stabilization decision, both positive and negative residual CTC revenue is transferred to the TCBA on
a monthly basis, retroactive to January 1, 1998 (see further discussion in Rate Stabilization Proceedings).
Recalculating the TCBA balance based on the March 2001 decision, resulted in positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover SCE's transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000. Between May 2000 and January 18, 2001 (when the CDWR began making power purchases
for SCE's customers), SCE's costs to provide power exceeded revenue from frozen rates. Even though SCE is no
longer supplying its customers with all of their electricity needs, SCE's total transition costs have continued
to exceed revenue from frozen rates. As a result, the cumulative positive residual CTC revenue flowing into the
TCBA mechanism has been reduced from $4.7 billion to $2.7 billion as of June 30, 2001. The cumulative TCBA
undercollection (as recalculated) was $2.9 billion as of December 31, 2000, and $4.2 billion as of June 30,
2001. A summary of the components of this cumulative undercollection as of June 30, 2001, is as follows:
In millions
-----------------------------------------------------------------------------------------------------
Transition costs recorded in the TCBA:
QF and interutility costs $ 5,590
Amortization of nuclear-related regulatory assets 3,561
Depreciation of plant assets 656
Other transition costs 760
-----------------------------------------------------------------------------------------------------
Total costs 10,567
Revenue available to recover transition costs (6,331)
-----------------------------------------------------------------------------------------------------
TCBA undercollections $ 4,236
-----------------------------------------------------------------------------------------------------
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Unless the regulatory and legislative actions that make such recovery probable are taken, SCE is unable to
conclude that the recalculated TCBA net undercollection is 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 December 31,
2000 (see further discussion in Earnings), and an additional $1.4 billion in TCBA undercollections was charged to
earnings for the six months ended June 30, 2001. In its interim rate stabilization decision of March 27, 2001,
the CPUC denied SCE's motion to end the rate freeze, and stated that it will not end until recovery of all
specified transition costs (including TCBA undercollections as recalculated) or March 31, 2002. For more details
on the matters discussed above, see Rate Stabilization Proceedings.
Litigation
----------
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. The effect of such a ruling would be to overturn the prior decisions of the CPUC restricting recovery
of TRA undercollections. In January 2001, the court denied the CPUC's motion to dismiss the action and also
denied SCE's motion for summary judgment without prejudice. In February 2001, the court denied SCE's motion for
a preliminary injunction ordering the CPUC to institute rates sufficient to enable SCE to recover its past
procurement costs, subject to refund. The court granted, in part, SCE's additional motion to specify certain
material facts without substantial controversy, but denied the remainder of the motion and declined to declare at
that time that SCE is entitled to recover the amount of its undercollected procurement costs. In March 2001, the
court directed the parties to be prepared for trial on July 31, 2001. Per mutual agreement of the parties, a
stay has been issued while SCE is attempting to further the MOU implementation process with the CPUC. As
discussed in the Memorandum of Understanding with the CDWR, if the other elements of the MOU are implemented, SCE
will enter into a settlement of or dismiss its lawsuit against the CPUC seeking recovery of past undercollected
costs. The settlement or dismissal will include related claims against California or any of its agencies, or
against the federal government. SCE cannot predict whether or when a favorable final judgment or other
resolution would be obtained in this legal action if it were to proceed to trial.
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 (discussed below). A
consolidated class action complaint was filed on August 3, 2001. SCE and Edison International have until
September 17, 2001, to respond to the consolidated complaint. SCE believes that its current and past accounting
for the TRA undercollections and related items, as described above, is appropriate and in accordance with
accounting principles generally accepted in the United States.
On March 15, 2001, a purported class action lawsuit was filed in federal district court in Los Angeles against
Edison International and SCE and certain of their officers. The complaint alleges that the 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 the defendants allegedly over-reported income and improperly
accounted for the TRA undercollections. The complaint is supposedly filed on behalf of a class of persons who
purchased all publicly traded securities of Edison International between May 12, 2000, and December 22, 2000. In
accordance with an agreement with Edison International and SCE, the court has allowed the consolidation of this
lawsuit with the October 20, 2000, lawsuit discussed above.
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 more than $833 million for energy and capacity
supplied to SCE under QF contracts, and in some cases additional damages as well.
Page 55
Many of these QF lawsuits also seek an order allowing the suppliers to stop providing power to SCE so that the
may sell the power to other purchasers. The state court cases have largely been coordinated before a single
trial judge. SCE has reached agreements with QFs representing about 95% of the QF renewable and cogeneration
energy 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.
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
current rate freeze ends 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. SCE's plan included a trigger mechanism allowing for rate
increases of 5% every six months if SCE's TRA undercollection balance exceeds $1 billion.
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 covers, 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. On April 3, 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 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. The MOU calls for the CPUC to adopt
a decision clarifying that the first priority condition in SCE's 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 provide assurance that the CPUC will adopt such a decision, or
predict what effects any investigation or any subsequent actions by the CPUC may have on SCE.
On March 27, 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. 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 on June 3, 2001. The CPUC also
ordered that the 3(cent)-surcharge be added to the rate paid to the CDWR (see CDWR Power Purchases).
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). SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes
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as merely reducing the prior residual CTC revenue recorded in the TCBA, thus only affecting the amount of
transition cost recovery achieved to date. 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 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. If the CPUC does not
modify this decision in a manner acceptable to SCE, SCE intends to challenge this decision through all
appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 2001 order, it has allocated the
revenue from the increase entirely to future purchased-power costs without addressing SCE's past undercollections
for the costs of purchased power. The CPUC's decisions do not assure that SCE will be able to meet its ongoing
obligations or repay past due obligations. By ordering immediate payments to the CDWR and QFs, the CPUC impacted
SCE's future cash flow and liquidity problems. Additionally, the CPUC stated that AB 1X continues the utilities'
obligations to serve their customers, and stated that it cannot assume that the CDWR will purchase all the
electricity needed above what the utilities either generate or have under contract (the net short position) and
cannot order the CDWR to do so. This could result in additional purchased power costs with no allowed means of
recovery (see CDWR Power Purchases). To take action that will restore SCE's creditworthiness, it will be
necessary for the CPUC to modify or rescind these decisions. SCE cannot provide any assurance that the CPUC will
do so.
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.
Unless regulatory and legislative actions that make such recovery probable are taken, which would include
modifying or reversing recent CPUC decisions that impair recovery of SCE's power procurement and transition
costs, SCE cannot 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, are
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 earnings as of
December 31, 2000 (see Earnings).
As discussed below, an MOU has been negotiated with representatives of the Governor as a step to resolving the
energy crisis. If regulatory and legislative actions result in a rate-making mechanism that would make recovery
of these regulatory assets probable, the regulatory assets would be restored to the balance sheet, with a
corresponding increase to earnings.
Memorandum of Understanding with the CDWR
-----------------------------------------
On April 9, 2001, SCE signed an MOU with the CDWR regarding the California energy crisis and its effects on SCE.
The Governor of California and his representatives participated in the negotiation of the MOU, and the Governor
endorsed implementation of all the elements of the MOU. The MOU sets forth a comprehensive plan calling for
state legislation and regulatory action and definitive agreements to resolve important aspects of the energy
crisis, and which, if implemented, is expected to help restore SCE's creditworthiness and liquidity. Key
elements of the MOU include:
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o SCE will sell its transmission assets to the CDWR, or another authorized state agency, at a price equal to
2.3 times their aggregate book value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, SCE's hydroelectric assets and other rights may be sold to the
state in their place. SCE will use the proceeds of the sale in excess of book value to reduce its
undercollected costs and retire outstanding debt incurred in financing those costs. SCE will agree to
operate and maintain the transmission assets for at least three years, for a fee to be negotiated.
o Two dedicated rate components will be established to assist SCE in recovering the net undercollected amount
of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the undercollected amount over the
expected gain on sale of SCE's transmission assets, as well as certain other costs. Such securitization
will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of
other conditions of the MOU. The second dedicated rate component would not be securitized and would not
appear in rates unless the transmission sale failed to close within a two-year period. The second component
is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be
recovered through the gain on the transmission sale.
o SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through
2010. SCE will be entitled to collect revenue sufficient to cover its costs from January 1, 2001,
associated with the retained generation assets and existing power contracts. The MOU calls for the CPUC to
adopt cost recovery mechanisms consistent with SCE obtaining and maintaining an investment grade credit
rating.
o The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers
within SCE's service territory through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are referred to as SCE's net short
position.) SCE will resume procurement of its net short position after 2002. The MOU calls for the CPUC to
adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility.
o SCE's authorized return on equity will not be reduced below its current level of 11.6% before December 31,
2010. Through the same date, a rate-making capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth in current authorizations. These
measures are intended to enable SCE to achieve and maintain an investment-grade credit rating.
o Edison International and SCE will commit to make capital investments in the utility of at least $3 billion
through 2006, or a lesser amount approved by the CPUC. The equity component of the investments will be
funded from SCE's retained earnings or, if necessary, from equity investments by Edison International.
o Edison Mission Energy (an affiliate of Edison International) will execute a contract with the CDWR for the
provision of power from a designated project to the state at cost-based rates for 10 years. The Sunrise
power project, which meets this obligation, began commercial operation on June 27, 2001.
o SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with
SCE's Big Creek and Eastern Sierra hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the state, but ultimately may be assigned to nonprofit entities or certain governmental
agencies. SCE will be permitted to continue utility uses of the subject lands.
o After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its
federal district court lawsuit against the CPUC seeking recovery of past undercollected costs. The
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settlement or dismissal will include related claims against the state or any of its agencies, or against the
federal government.
The sale of SCE's transmission system and other elements of the MOU must be approved by the FERC. SCE and the
CDWR committed in the MOU to proceed in good faith to sponsor and support the required state legislation and to
negotiate in good faith the necessary definitive agreements. The MOU may be terminated by either SCE or the CDWR
if required legislation is not adopted and definitive agreements are not executed by August 15, 2001, or if
certain other adverse changes occur. Since the required legislation will not be enacted, necessary regulatory
actions will not be taken, and definitive agreements will not be executed before the applicable deadlines, the
MOU will be terminable unless the parties choose to extend the deadlines.
Since the execution of the MOU, SCE has made several filings with the CPUC addressing elements of the MOU.
Although the CPUC did not adopt the implementing decisions contemplated by the MOU within the projected timeframe
set out in the MOU, the CPUC continues to process SCE's filings. However, SCE cannot assure that the necessary
implementing decisions will be passed, nor whether any decisions ultimately adopted will be acceptable to SCE.
Legislation to address the MOU and issues relating to SCE's creditworthiness has been introduced in both the
California State Senate and Assembly as part of the 2001-02 Second Extraordinary Session.
Senate Bill 78XX was introduced in May 2001. As introduced, the bill would have implemented the MOU in its
entirety. However, Senate Bill 78XX was significantly amended in July. As amended, Senate Bill 78XX would allow
SCE to securitize a significant portion of the past procurement undercollections, but would not allow SCE to
recover from ratepayers unpaid PX and ISO costs aggregating approximately $1 billion, or interest accruing on the
past procurement undercollections after January 31, 2001 (estimated to be approximately $400 million by year end
2001). The bill would provide the State of California with a five-year option to purchase SCE's transmission
system at book value, and contains provisions for conservation easements similar to the MOU. SCE opposed Senate
Bill 78XX on the grounds that SCE did not believe that the bill would provide the elements necessary to return
SCE to investment grade credit status and it believed that other provisions of the bill were also objectionable.
Senate Bill 78XX was approved by the Senate on July 20, 2001, and was referred to the State Assembly. The
leadership of the Assembly has indicated its intent to amend the bill. If amended by the Assembly, the amended
bill would return to the State Senate for a concurrence vote (the Senate must accept the bill as passed by the
Assembly or the bill is rejected). The bill would reach the Governor's desk only if agreed to by the Senate. In
the alternative, the Senate and Assembly could agree to refer the bill to a Conference Committee.
The Assembly introduced two bills, Assembly Bill 82XX and Assembly Bill 50XX. Assembly Bill 50XX would have
allowed for recovery of all but $300 million of SCE's past procurement-related debt with no sale of SCE's
transmission assets or grant of conservation easements. SCE supported this bill as most likely to return SCE to
investment grade credit status. However, Assembly Bill 50XX was not approved by the Assembly Appropriations
Committee. Assembly Bill 82XX was approved by both the Assembly Policy and Appropriations Committees, and is
currently on the floor of the Assembly. That bill would allow SCE to securitize all of its net past procurement
undercollection except for $500 million, and would authorize the sale of SCE's transmission assets. In
committee, SCE was supportive of Assembly Bill 82XX, but advocated amendments.
The Legislature is in recess until August 20, 2001. During the summer interim recess, a working group of certain
Assembly members has been formed to identify additional amendments to Assembly Bill 82XX and/or to propose
amendments to Senate Bill 78XX. SCE continues to work with the authors of all the bills. However, SCE cannot
assure that legislation will be passed, nor whether any such legislation will ultimately be acceptable to SCE or
would be signed by the Governor.
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Utility Retained Generation
---------------------------
In order to implement the CPA and Rate Stabilization decisions, SCE filed a comprehensive proposal for new
ratemaking for utility retained generation through the end of 2002. The 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. SCE proposed a
fifth balancing account to track generation-related undercollections incurred before January 31, 2001. Hearings
were held in July 2001. A final decision is expected later in 2001.
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. On December 15, 2000, the FERC released a final order
containing remedies and other actions in response to the problems in the California electricity market. The
order, among other things, eliminated the requirement for California utilities to buy and sell power exclusively
through the ISO and PX; created a benchmark price for wholesale bilateral power contracts; created penalties for
under-scheduling power loads; provided for an independent governing board for the ISO; and established a
breakpoint of $150/MWh so that bids below $150 may clear at a single market-clearing price at or below $150/MWh
and bids above $150 will be paid as bid. On December 18, 2000, SCE filed with the FERC an emergency request for
rehearing of the December 15 order. On January 12, 2001, the FERC issued an order granting rehearing for the
purpose of further consideration. The PX did not immediately implement the $150/MWh breakpoint and on February
26, 2001, made a compliance filing with the FERC, which requested the FERC's guidance on an acceptable
recalculation methodology.
In December 2000, 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. On January 5, 2001, the court denied
SCE's petition. SCE's petition for rehearing remains pending. SCE is considering the possibility of judicial
appeals and other actions.
In December 2000, the ISO announced that generators of electricity were refusing to sell into the California
market due to concerns about the financial stability of SCE and Pacific Gas and Electric Company (PG&E). In
response to this announcement, the United States Secretary of Energy issued an order requiring power companies to
make arrangements to generate and deliver electricity as requested by the ISO after the ISO certifies that it has
been unable to acquire adequate supplies of electricity in the market. After being renewed multiple times, the
order expired on February 6, 2001. However, on
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February 7, 2001, a federal court judge issued a temporary restraining order requiring power suppliers to sell
to the California grid. On March 21, 2001, a federal court judge ordered one of the power suppliers to continue
to sell power to the California grid. Three other power suppliers have signed an agreement with the judge
voluntarily agreeing to continue to sell power to the grid while awaiting a review of the issue by the FERC.
On April 6, 2001, the United States Court of Appeals issued a stay order, suspending the lower court's March 21
order until a final appeals ruling can be issued.
In December 2000, the FERC established a penalty applicable to scheduling coordinators that do not schedule
sufficient resources to supply 95% of their respective loads. SCE has sought a suspension of the so-called
"underscheduling penalty." SCE has also sought a rehearing of a FERC order, issued in May 2001, which rejected
the ISO's proposal for suspension of the underscheduling penalty. In the May 2001 order, the FERC also indicated
that it will make a determination regarding the suspension of the underscheduling penalty in a future order on a
complaint filed by SCE and PG&E that asked the FERC to eliminate the penalty. As of July 2001, the statewide
accumulated penalties were estimated by the ISO to be approximately $1 billion. 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, 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. The new approach replaces the $150/MWh
breakpoint discussed above.
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 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. A prehearing conference
is scheduled for August 13, 2001.
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 44 identified sites is $116
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 $272 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 $46 million of its
recorded liability, through an incentive mechanism, which is discussed in Note 12. SCE has recorded a regulatory
asset of $75 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 $20 million. Recorded costs for the twelve months ended June 30, 2001,
were $19 million.
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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.
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. On June 1, 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 resulting 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 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
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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 or 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 standard 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 June 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 implementation (or
non-implementation) of the MOU as described above; 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, including the possible filing of an involuntary bankruptcy petition against SCE; 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;
changes in prices of electricity and fuel costs; the actions of securities rating agencies; 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
Geothermal Generators' Litigation
As previously reported in Part 1, Item 3 of SCE's Annual Report on Form 10-K for the fiscal year ended December
31, 2000 (2000 Form 10-K), SCE has been involved in litigation with an independent power producer and six of its
affiliated entities.
Effective February 8, 2000, the parties entered into confidential agreements resolving all claims in the
consolidated action and calling for dismissals with prejudice and releases subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings during the period required to
obtain CPUC approval. On April 26, 2000, SCE filed an application to obtain such approval. The Commission
approved the settlement at its November 21, 2000 meeting, and issued its decision on November 22, 2000. That
decision became final (no longer subject to appeal) on December 22, 2000. On June 13, 2001, the Court dismissed
all claims in the case, with prejudice, based upon the settlement and the CPUC approval of the settlement.
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-Q for
the quarterly period ending June 30, 2001 (First Quarter 10-Q), SCE is actively involved in four lawsuits
claiming personal injuries allegedly resulting from exposure to radiation at San Onofre.
On May 9, 2001, SCE was served with a complaint filed on March 1, 2001, by a former contract worker at San Onofre
and his wife in the U.S. District Court for the Southern District of California. In addition to SCE, plaintiffs
also named as defendants Combustion Engineering and Bechtel Construction Company, the employer of the former San
Onofre worker. The Court approved a stipulation of the parties giving defendants until August 28, 2001, to
respond to the complaint. The parties currently are negotiating an agreement to further stay prosecution of this
case pending the results of the November 17, 1995, case currently before the Ninth Circuit Court of Appeal.
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, 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 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. The Court has ordered
defendants to respond to the consolidated complaint by September 17, 2001.
Qualifying Facilities 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, SCE is involved in a number of legal actions brought by various QFs, alleging SCE failed to
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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 largely been coordinated
before a single trial judge. On July 19, 2001, the judge set briefing and oral argument for August 2001 on the
issue of whether the trial court or the CPUC has jurisdiction over the claims and defenses asserted in the
various actions, and continued the current stay of the actions before him. The judge further ordered that for
any matters over which the trial court has jurisdiction, motions for summary judgment or adjudication shall be
briefed and heard in October 2001.
During June, July and August 2001, SCE reached agreements with generators representing about 95% of the QF
renewable energy and approximately 95% of the QF cogeneration energy 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. Long Beach has posted
a bond and attached one of SCE's bank accounts. SCE filed a petition for review of the right to attach order
issued in the Long Beach case, and the California Court of Appeal has issued a temporary stay order in that case
and set oral argument on SCE's petition for September 25, 2001. Long Beach has sought reconsideration of the
stay order, but the Court of Appeal has not yet responded to this request.
In addition to the cases previously referenced in SCE's 2000 Form 10-K, and in SCE's First Quarter 10-Q, the
following legal proceedings, identified by principal party, filing date, and court jurisdiction, have been filed
against SCE:
Principal Party Date Filed Court Jurisdiction
--------------- ---------- ------------------
Rio Bravo Jasmin May 16, 2001 Los Angeles County Superior Court,
Central District
Calwind Resources, Inc. May 18, 2001 Los Angeles County Superior Court,
Central District
Wheelabrator Norwalk May 18, 2001 Los Angeles County Superior Court,
Energy Co., Inc. South East District
Smurfit Stone Container May 25, 2001 United States District Court,
Central District, Los Angeles Division
Ripon Cogeneration, Inc. June 6, 2001 Los Angeles County Superior Court,
Central District
Midway-Sunset Cogeneration June 7, 2001 Kern County Superior Court
Company
San Gorgonio Westwinds II, LLC June 8, 2001 Riverside County Superior Court
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Colmac Energy, Inc. June 12, 2001 Los Angeles County Superior Court,
Central District
Dutch Energy Corporation July 23, 2001 Los Angeles County Superior Court,
Central District (On August 6, 2001,
plaintiff voluntarily dismissed this
complaint without prejudice.)
PX Performance Bond Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, 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.
Item 4. Submission of Matters to a Vote of Security Holders
At SCE's Annual Meeting of Shareholders on May 14, 2001, shareholders elected twelve nominees to the Board of
Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld
from each Director-nominee were as follows:
Number of Votes
---------------
Name For Withheld
---- --- --------
Warren Christopher 455,444,842 646,462
Stephen E. Frank 455,508,948 582,356
Joan C. Hanley 455,510,040 581,264
Carl F. Huntsinger 455,506,552 584,752
Charles D. Miller 455,499,814 591,490
Luis G. Nogales 455,492,520 598,784
Ronald L. Olson 455,515,770 575,534
James M. Rosser 455,496,486 594,818
Robert H. Smith 455,509,656 581,648
Thomas C. Sutton 455,513,628 577,676
Daniel M. Tellep 455,508,948 582,356
Edward Zapanta 455,508,732 582,572
Page 66
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
February 15, 2001 (File No. 1-2313, filed as Exhibit 3.3 to Form 10-K for the period ended
December 31, 2000)*
23. Consent of Independent Public Accountants
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
March 27, 2001 April 10, 2001 5
June 1, 2001 June 5, 2001 5
------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 67
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
August 14, 2001
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