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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 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
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 800)
Rosemead, California
(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 May 10, 2001
----------------------------------------------------------- ---------------------------------------------------
Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 1
Consolidated Statements of Income (Loss) - Three and
Twelve Months Ended March 31, 2001, and 2000 2
Consolidated Statements of Comprehensive Income (Loss) -
Three and Twelve Months Ended March 31, 2001, and 2000 2
Consolidated Balance Sheets - March 31, 2001,
December 31, 2000, and March 31, 2000 3
Consolidated Statements of Cash Flows -
Three and Twelve Months Ended
March 31, 2001, and 2000 5
Consolidated Statements of Common Shareholder's
Equity - Three and Twelve Months Ended
March 31, 2001, and 2000 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 40
Part II. Other Information:
Item 1. Legal Proceedings 63
Item 6. Exhibits and Reports on Form 8-K 65
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 March 31, 2001, December 31, 2000, and March 31, 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- and twelve-month periods ended March 31, 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 March 31, 2001, December 31, 2000, and March 31, 2000, and
the results of their operations and their cash flows for each of the three- and twelve-month periods ended March
31, 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 three and twelve months ended March 31, 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
May 11, 2001
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
In millions
3 Months Ended 12 Months Ended
March 31, March 31,
----------------------------------------------------------- ----------------------------- -------------------------
2001 2000 2001 2000
----------------------------------------------------------- ----------------------------- -------------------------
Operating revenue $ 1,512 $ 1,830 $ 7,552 $ 7,693
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Fuel 47 55 187 221
Purchased power 1,724 504 5,907 2,956
Provisions for regulatory adjustment clauses - net (29) 103 2,169 (380)
Other operation and maintenance 429 409 1,792 1,847
Depreciation, decommissioning and amortization 152 376 1,249 1,537
Income taxes (419) 123 (1,549) 491
Property and other taxes 29 40 115 123
Net gain on sale of utility plant (3) (6) (22) (7)
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Total operating expenses 1,930 1,604 9,848 6,788
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Operating income (loss) (418) 226 (2,296) 905
Interest and dividend income 25 20 178 75
Other nonoperating income 9 20 106 141
Interest expense - net of amounts capitalized (207) (127) (652) (489)
Other nonoperating deductions 8 (23) (79) (108)
Tax benefit (expense) on other income and deductions (9) 3 3 21
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Net income (loss) (592) 119 (2,740) 545
Dividends on preferred stock 6 6 21 25
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Net income (loss) available for common stock $ (598) $ 113 $ (2,761) $ 520
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
3 Months Ended 12 Months Ended
March 31, March 31,
----------------------------------------------------------- ----------------------------- -------------------------
2001 2000 2001 2000
----------------------------------------------------------- ----------------------------- -------------------------
Net income (loss) $ (592) $ 119 $ (2,740) $ 545
Other comprehensive income, net of tax:
Unrealized gain on securities - net -- 3 -- 37
Cumulative effect of change in accounting for derivatives 397 -- 397 --
Unrealized loss on cash flow hedges (422) -- (422) --
Reclassification adjustment for gains included in net income -- -- (24) (28)
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Comprehensive income (loss) $ (617) $ 122 $ (2,789) $ 554
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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
March 31, December 31, March 31,
2001 2000 2000
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ASSETS
Utility plant, at original cost:
Transmission and distribution $ 13,247 $ 13,129 $ 12,558
Generation 1,749 1,745 1,736
Accumulated provision for depreciation and decommissioning (7,794) (7,834) (7,705)
Construction work in progress 635 636 665
Nuclear fuel, at amortized cost 134 143 117
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Total utility plant 7,971 7,819 7,371
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Nonutility property - less accumulated provision for
depreciation of $12, $11 and $8 at respective dates 107 102 100
Nuclear decommissioning trusts 2,372 2,505 2,581
Other investments 84 90 160
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Total investments and other assets 2,563 2,697 2,841
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Cash and equivalents 2,027 583 131
Receivables, less allowances of $23, $23 and $24
for uncollectible accounts at respective dates 891 919 613
Accrued unbilled revenue 393 377 378
Fuel inventory 14 12 40
Materials and supplies, at average cost 136 132 125
Accumulated deferred income taxes - net 525 545 125
Prepayments and other current assets 97 124 56
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Total current assets 4,083 2,692 1,468
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Regulatory assets - net 2,759 2,390 5,421
Other deferred charges 503 368 594
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Total deferred charges 3,262 2,758 6,015
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Total assets $ 17,879 $ 15,966 $ 17,695
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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
March 31, December 31, March 31,
2001 2000 2000
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CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
Common stock (434,888,104 shares
outstanding at each date) $ 2,168 $ 2,168 $ 2,168
Additional paid-in capital 334 334 335
Accumulated other comprehensive income (loss) (25) -- 24
Retained earnings (deficit) (2,320) (1,722) 626
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157 780 3,153
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Preferred stock:
Not subject to mandatory redemption 129 129 129
Subject to mandatory redemption 256 256 256
Long-term debt 5,405 5,631 5,109
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Total capitalization 5,947 6,796 8,647
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Short-term debt 2,120 1,451 849
Current portion of long-term debt 646 646 448
Accounts payable 2,938 1,055 425
Accrued taxes 440 536 590
Accrued interest 163 96 83
Dividends payable 5 1 99
Regulatory liabilities - net 251 195 221
Deferred unbilled revenue 278 250 265
Other current liabilities 1,232 1,155 1,289
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Total current liabilities 8,073 5,385 4,269
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Accumulated deferred income taxes - net 1,960 2,009 2,880
Accumulated deferred investment tax credits 155 164 195
Customer advances and other deferred credits 834 755 816
Power-purchase contracts 439 467 539
Accumulated provision for pensions and benefits 378 296 246
Other long-term liabilities 93 94 103
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Total deferred credits and other liabilities 3,859 3,785 4,779
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Commitments and contingencies
(Notes 2, 3, 11 and 12)
Total capitalization and liabilities $ 17,879 $ 15,966 $ 17,695
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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 12 Months Ended
March 31, March 31,
----------------------------------------------------------- ----------------------------- ---------------------------
2001 2000 2001 2000
----------------------------------------------------------- ----------------------------- ---------------------------
Cash flows from operating activities:
Net income (loss) $ (592) $ 119 $ (2,740) $ 545
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 152 376 1,249 1,537
Other amortization 18 25 89 100
Deferred income taxes and investment tax credits (303) (39) (1,182) 56
Regulatory balancing accounts - long-term 69 (92) 1,920 (1,116)
Net gain on sale of marketable securities -- -- (41) (48)
Other assets (283) (24) (215) (62)
Other liabilities 66 (6) 59 (40)
Changes in working capital:
Receivables and accrued unbilled revenue 16 23 (289) 57
Regulatory balancing accounts - short-term 56 120 33 480
Fuel inventory, materials and supplies (7) 8 15 7
Prepayments and other current assets 28 56 (41) (1)
Accrued interest and taxes (28) 90 (80) (101)
Accounts payable and other current liabilities 1,987 (75) 2,650 271
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Net cash provided by operating activities 1,179 581 1,427 1,685
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Cash flows from financing activities:
Long-term debt issued -- 248 1,511 739
Long-term debt repaid -- (325) (200) (688)
Bonds repurchased and funds held in trust (156) -- (596) --
Rate reduction notes repaid (63) (61) (248) (236)
Nuclear fuel financing - net (9) (14) 15 (43)
Short-term debt financing - net 669 53 1,271 220
Dividends paid (1) (100) (296) (614)
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Net cash provided (used) by financing activities 440 (199) 1,457 (622)
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Cash flows from investing activities:
Additions to property and plant (178) (253) (1,021) (1,008)
Funding of nuclear decommissioning trusts -- (23) (46) (102)
Proceeds from sales of marketable securities -- -- 41 50
Investments in other assets 3 (1) 38 6
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Net cash used by investing activities (175) (277) (988) (1,054)
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Net increase in cash and equivalents 1,444 105 1,896 9
Cash and equivalents, beginning of period 583 26 131 122
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Cash and equivalents, end of period $ 2,027 $ 131 $ 2,027 $ 131
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Cash payments for interest and taxes:
Interest - net of amounts capitalized $ 69 $ 74 $ 298 $ 293
Taxes -- -- 306 433
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 December 31, 1999 $ 2,168 $ 335 $ 22 $ 608 $ 3,133
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Net income 119 119
Unrealized gain on securities 4 4
Tax effect (2) (2)
Dividends declared on common stock (95) (95)
Dividends declared on preferred stock (5) (5)
Stock option appreciation (1) (1)
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Balance at March 31, 2000 $ 2,168 $ 335 $ 24 $ 626 $ 3,153
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Balance at December 31, 2000 $ 2,168 $ 334 $ -- $ (1,722) $ 780
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Net income (loss) (592) (592)
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (422) (422)
Dividends accrued on preferred stock (6) (6)
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Balance at March 31, 2001 $ 2,168 $ 334 $ (25) $ (2,320) $ 157
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Balance at March 31, 1999 $ 2,168 $ 334 $ 16 $ 700 $ 3,218
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Net income 545 545
Unrealized gain on securities 59 59
Tax effect (22) (22)
Reclassified adjustment for gain
included in net income (48) (48)
Tax effect 19 19
Dividends declared on common stock (592) (592)
Dividends declared on preferred stock (25) (25)
Stock option appreciation and other (2) (2)
Capital stock expense 1 1
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Balance at March 31, 2000 $ 2,168 $ 335 $ 24 $ 626 $ 3,153
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Net income (loss) (2,740) (2,740)
Cumulative effect of change in
accounting for derivatives 397 397
Unrealized loss on cash flow hedges (422) (422)
Reclassified adjustment for gain
included in net income (41) (41)
Tax effect 17 17
Dividends declared on common stock (183) (183)
Dividends accrued on preferred stock (21) (21)
Stock option appreciation and other (2) (2)
Capital stock expense (1) (1)
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Balance at March 31, 2001 $ 2,168 $ 334 $ (25) $ (2,320) $ 157
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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 6
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 for
its 4.3 million customers in central, coastal and Southern California. SCE operates in a highly regulated
environment in which it has an obligation to deliver electric service to customers in return for an exclusive
franchise within its service territory. 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, those generating plants are owned by independent power companies.
Along with electric utility industry restructuring, a multi-year freeze on the rates that SCE could charge its
customers was mandated and transition cost recovery mechanisms allowing SCE to recover its stranded costs
associated with generation-related assets were implemented. 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, since the summer of 2000, the prices
charged by generators and other sellers have escalated far beyond what SCE can currently charge its customers.
See Note 3 for a further discussion.
SCE also produces electricity. On April 1, 1998, SCE began selling all of its electric generation through the
California Power Exchange (PX) and Independent System Operator (ISO) and scheduling delivery through the ISO, as
mandated by the CPUC's 1995 restructuring decision. By purchasing wholesale electricity through the PX and ISO,
SCE satisfied the electric energy needs for customers who did not choose an alternative energy provider. The
requirement for California utilities to buy and sell power exclusively through the ISO and PX was eliminated by
the Federal Energy Regulatory Commission (FERC) in December 2000. On January 31, 2001, the PX stopped operation
of its day-ahead and day-of markets and on March 9, 2001, the PX filed for Chapter 11 bankruptcy protection.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In light of
SCE's liquidity crisis, its Board of Directors did not declare quarterly common stock dividends to its parent,
Edison International, in either December 2000 or March 2001. See Note 2 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 March 31, 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 FERC. Since 1997, SCE has used accounting principles applicable to enterprises in general for its investment
in generation facilities, as a result of industry restructuring legislation enacted by the State of California
and related changes in the rate-recovery of generation-related assets. Application of such accounting principles
to SCE's generation assets did not result in any adjustment of their carrying value.
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE's outstanding common stock is owned entirely by its parent company, Edison International.
Estimates
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.
Regulatory Balancing Accounts
During the rate freeze period, the difference between certain generation-related revenue and generation-related
costs are 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.
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), pursuant to a CPUC decision. This balance was to remain in GABA until final market valuation of
the hydroelectric generation assets. If there was 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, pursuant to a 1997 CPUC decision. Due to a January 4, 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 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.
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 must assess the
probability of recovery of its generation-related regulatory assets in light of the CPUC's March 27, 2001, and
April 3, 2001, decisions (discussed in Note 3), including the retroactive transfer of balances from SCE's TRA to
its 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 contemplated by the memorandum of understanding (MOU, as discussed in Note 3) occur, or other 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 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 the MOU is implemented or 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 as losses are incurred. The regulatory and legislative
actions set forth in the MOU are expected to result in a rate-making mechanism that would make recovery of these
regulatory assets probable. If and when those actions are taken, or other actions occur that make such recovery
probable, and the rate-making mechanism is adopted, the regulatory assets would be restored to the balance sheet,
with a corresponding increase to earnings.
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory assets and liabilities included in the consolidated balance sheets are:
March 31, December 31, March 31,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Generation-related:
Unamortized nuclear investment - net $ -- $ -- $ 1,167
Flow-through taxes -- -- 245
Unamortized loss on sale of plant -- -- 107
Purchased-power settlements -- -- 507
Environmental remediation -- -- 16
Regulatory balancing accounts and other -- -- 1,013
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Subtotal -- -- 3,055
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Rate reduction notes - transition cost deferral 1,181 1,090 800
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Other:
Flow-through taxes 1,136 874 1,061
Unamortized loss on reacquired debt 267 273 289
Environmental remediation 57 52 106
Regulatory balancing accounts and other (133) (94) (111)
---------------------------------------------------------------------------------------------------------------
Subtotal 1,327 1,105 1,345
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Total $ 2,508 $ 2,195 $ 5,200
---------------------------------------------------------------------------------------------------------------
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. This reclassification had no effect on SCE's results of operations.
Nuclear
SCE had been recovering its investments in San Onofre Nuclear Generating Station Units 2 and 3 and Palo Verde
Nuclear Generating Station on an accelerated basis, as authorized by the CPUC. The accelerated recovery was to
continue through December 2001, earning a 7.35% fixed rate of return on investment. San Onofre's operating
costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, are
recovered through an incentive pricing plan which 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.
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 are required to be shared equally with
ratepayers beginning in 2004 and 2002, respectively. Palo Verde's existing nuclear unit incentive procedure will
continue through 2001 only for purposes of calculating a reward for performance of any unit above an 80% capacity
factor for a fuel cycle.
Under the MOU (discussed in Note 3), both nuclear facilities would be subject to cost-based ratemaking upon
completion of their respective rate-making plans and the sharing mechanisms that were to begin in 2004 and 2002
would be eliminated.
Cash Equivalents
Cash equivalents include tax-exempt investments, time deposits and other investments with original maturities of
three months or less.
Planned Major Maintenance
Certain plant facilities require major maintenance on a periodic basis. All such costs are expensed as
incurred.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and under the first-in, first-out
method for coal.
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end of each period.
Investments
Net unrealized gains (losses) on equity investments are recorded as a separate component of shareholder's equity
under the caption "Accumulated other comprehensive income." Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
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.
Interest rate differentials and amortization of premiums for interest rate caps are recorded as adjustments to
interest expense. If the derivatives were terminated before
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and $10 million for the three and twelve months ended March 31, 2001, respectively,
and $4 million and $14 million for the three and twelve months ended March 31, 2000, respectively. AFUDC - debt
was $3 million and $9 million for the three and twelve months ended March 31, 2001, respectively, and $3 million
and $12 million for the three and twelve months ended March 31, 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
3.6% and 3.5% for the three and twelve months ended March 31, 2001, respectively, and 3.7% for both the three and
twelve months ended March 31, 2000.
SCE's net investment in generation-related utility plant was approximately $1.0 billion at March 31, 2001, at
December 31, 2000, and at March 31, 2000.
Related Party Transactions
Certain Edison Mission Energy (a wholly owned subsidiary of Edison International) subsidiaries have ownership in
partnerships that sell electricity generated by their project facilities to SCE under long-term power purchase
agreements. Such sales to SCE were $160 million and $471 million for the three and twelve months ended March 31,
2001, respectively, and $45 million and $240 million for the three and twelve months ended March 31, 2000,
respectively. As a result of SCE's liquidity crisis, SCE has deferred payments for power purchases from some of
these facilities.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Purchased Power
SCE purchased power through the PX from April 1998 through January 18, 2001. Ancillary and other services are
purchased through the ISO. SCE also has bilateral forward contracts with other entities (as discussed in Note 4)
and contracts with other utilities and qualifying facilities (QFs). Purchased power detail is provided below:
3 Months Ended 12 Months Ended
March 31, March 31,
--------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------
PX/ISO:
Purchases $ 1,081 $ 517 $ 9,014 $ 2,595
Generation sales (705) (441) (6,385) (1,876)
--------------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net 376 76 2,629 719
Purchased power - bilateral contracts 52 -- 52 --
Purchased power - interutility/QF contracts 1,296 428 3,226 2,237
--------------------------------------------------------------------------------------------------------------
Total $ 1,724 $ 504 $ 5,907 $ 2,956
--------------------------------------------------------------------------------------------------------------
Other Nonoperating Income and Deductions
Other nonoperating income and deductions was comprised of:
3 Months Ended 12 Months Ended
March 31, March 31,
--------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------
Gain on sale of marketable securities $ -- $ -- $ 41 $ 48
AFUDC 5 7 19 26
Key person life insurance income 4 5 4 16
Other -- 8 42 51
--------------------------------------------------------------------------------------------------------------
Total other nonoperating income 9 $ 20 $ 106 141
--------------------------------------------------------------------------------------------------------------
Provisions for regulatory issues and refunds $ (16) $ 19 $ 43 $ 82
Other 8 4 36 26
--------------------------------------------------------------------------------------------------------------
Total other nonoperating deductions $ (8) $ 23 $ 79 $ 108
--------------------------------------------------------------------------------------------------------------
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 undercollection in the TRA, 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, SCE temporarily suspended payments of certain obligations
for principal and interest on outstanding debt and for purchased power. As of April 30, 2001, SCE had $3.1
billion in obligations that were unpaid and overdue including: (1) $882 million to the PX or the ISO; (2) $1.3
billion to QF power producers; (3) $230 million in PX energy credits for energy service providers;
(4) $531 million of matured commercial paper; and (5) $200 million of
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
principal on its 5-7/8% notes. If SCE is found responsible for the purchases of power by the California
Department of Water Resources (CDWR) or the ISO for sale to SCE's customers on or after January 18, 2001,
SCE's unpaid obligations as of April 30, 2001, could increase by as much as $800 million. See additional
discussion in Note 3. As applicable, unpaid obligations will continue to accrue interest. At April 30, 2001,
SCE had estimated cash reserves of approximately $1.9 billion, which is approximately $1.3 billion less
than its outstanding unpaid obligations and preferred stock dividends in arrears (see below).
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 ordered SCE and other investor-owned utilities to pay QFs for power deliveries on a
going forward basis, commencing with April 2001 deliveries. SCE must pay QFs within 15 days of the end of the
QFs' billing periods, and QFs are allowed to establish 15-day billing periods. Failure to make a required
payment within 15 days of delivery would result in a fine equal to the amount owed to the QF. The CPUC decision
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.
On March 27, 2001, the CPUC also issued decisions on the California Procurement Adjustment (CPA) calculation and
the approval of a 3(cent)per kWh rate increase (see Note 3). Based on these two decisions, SCE estimates that cash
going forward may not be sufficient to cover retained generation, purchased-power and transition costs. In
comments filed with the CPUC on March 29, 2001, and April 2, 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 discussed above
could result in a shortfall to the CPA calculation of $1.7 billion for SCE 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
its parent, Edison International, in either December 2000 or March 2001. Also, SCE's Board has not declared the
regular quarterly dividends for SCE's cumulative preferred stock, 4.08% Series, 4.24% Series, 4.32% Series, 4.78%
Series, 6.05% Series, 6.45% Series and 7.23% Series in 2001. The total preferred stock dividends in arrears were
$6 million as of April 30, 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. SCE does not meet other conditions under which dividends can be paid
from sources other than retained earnings. 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 on the matters discussed above, see Notes 3 through 7.
SCE's future liquidity depends, in large part, on whether the MOU is implemented, or other 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 excessively high price of energy. Without a change in
circumstances, such as that contemplated by the MOU, 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.
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 San Onofre Units 2
and 3 and the Palo Verde units. Transition costs related to power-purchase QF contracts are being recovered
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 from January 2001 associated with retained generation and
existing power contracts, the implementation of the MOU requires the CPUC to modify various decisions. Until the
various regulatory and legislative actions to implement the MOU are taken, or other actions occur that make such
recovery probable, SCE is unable to conclude that the regulatory assets and liabilities related to
purchased-power settlements, the unamortized loss on SCE's generating plant sales in 1998, and various other
regulatory assets and liabilities 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.
However, due to events discussed elsewhere in this report, 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. During 1998, SCE sold all of its gas-fueled generation plants for $1.2 billion, over
$500 million more than the combined book value. Net proceeds of the 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. Since May 2000, 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. Pursuant
to 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.
Upon recalculating the TCBA balance based on the new decision, SCE received positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover its transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000. As a result of sustained higher market prices, SCE experienced the first month in
which costs exceeded revenue in May 2000. Since then, SCE's costs to provide power have continued to exceed
revenue from frozen rates and as a result, the cumulative positive residual CTC revenue flowing into the TCBA
mechanism has been reduced from $4.7 billion to $1.4 billion as of March 31, 2001. The cumulative TCBA
undercollection (as recalculated) was $2.9 billion as of December 31, 2000, and $3.9 billion as of March 31,
2001. A summary of the components of this cumulative undercollection as of March 31, 2001, is as follows:
In millions
---------------------------------------------------------------------------------------------------
Transition costs recorded in the TCBA:
QF and interutility costs $ 4,556
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 613
Other transition costs 732
---------------------------------------------------------------------------------------------------
Total costs 8,991
Revenue available to recover transition costs (5,117)
---------------------------------------------------------------------------------------------------
TCBA undercollections $ 3,874
---------------------------------------------------------------------------------------------------
Unless the regulatory and legislative actions required to implement the MOU or other actions that make 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 $996 million in TCBA undercollections was
charged to earnings as of March 31, 2001. In its interim rate stabilization decision of March 27, 2001, the CPUC
denied a December motion by SCE to end the rate
Page 16
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Proceeding
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. On
December 20, 2000, SCE filed an amended rate stabilization plan application, stating that the CPUC must recognize
that the statutory rate freeze is now over 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. Hearings were held in late December 2000.
On January 4, 2001, the CPUC issued an interim decision that authorized SCE to establish an interim surcharge of
1(cent)per kWh for 90 days, subject to refund. The revenue from the surcharge is being tracked through a balancing
account and applied to ongoing power procurement costs. The surcharge resulted in rate increases, on average, of
approximately 7% to 25%, depending on the class of customer. As noted in the decision, the 90-day period allowed
independent auditors engaged by the CPUC to perform a comprehensive review of SCE's financial position, as well
as that of Edison International and other affiliates.
On January 29, 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 (originally proposed on March 15, 2001). The order reopens the past CPUC decision
authorizing the utilities to form holding companies and initiates an investigation into: whether the holding
companies violated CPUC requirements to give priority to the capital needs of their respective utility
subsidiaries; whether ring-fencing actions by Edison International and PG&E Corporation and their respective
nonutility affiliates also violated the requirements to give priority to the capital needs of their utility
subsidiaries; whether the payment of dividends by the utilities violated requirements that the utilities maintain
dividend policies as though they were comparable stand-alone utility companies; any additional suspected
violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other changes to the
holding company decisions are necessary. An assigned commissioner's ruling on March 29, 2001, required SCE to
respond within 10 days to document requests and questions that are substantially identical to those included in
the March 15 proposed order instituting investigation. 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. 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.
In its interim rate stabilization order adopted on March 27, 2001, the CPUC granted SCE a rate increase in the
form of a 3(cent)per kWh surcharge applied only to electric power procurement costs, effective immediately, and
affirmed that the 1(cent)interim surcharge granted on January 4, 2001, is now permanent. Although the 3(cent)increase
was authorized immediately, the surcharge will not be collected in rates until the CPUC establishes an
appropriate rate design, which is not expected to occur until early June 2001. The CPUC also ordered that the 3(cent)
surcharge be added to the rate paid to the CDWR pursuant to the interim CDWR-related decision.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Also, in the interim 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 account, 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, thereby 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 it 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 consistent with the MOU, SCE intends to challenge this decision
through all appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 27, 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
aggravated SCE's cash flow and liquidity problems. Additionally, the CPUC expressed the view that Assembly Bill
1 (First Extraordinary Session, AB 1X; see CDWR Power Purchases) 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 implement the MOU, 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 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 and expedited action seeking reconsideration 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. On April 6, 2001, the FERC
Page 18
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
issued an order providing guidance to the PX, which should reduce SCE's energy costs owed to the PX for
the month of January 2001.
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. 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, SCE filed an emergency petition in the federal Court of Appeals challenging the FERC order and
seeking a writ of mandamus requiring the FERC to immediately establish cost-based wholesale rates. On January 5,
2001, the court denied SCE's petition. The effect of the denial is to leave in place the FERC's market controls
that have allowed wholesale prices to climb to current levels. SCE's petition for rehearing remains pending.
SCE cannot predict what action the FERC may take. SCE is considering the possibility of judicial appeals and
other actions.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69 million or submit
cost-of-service information to the FERC to justify their prices above $273/MWh during ISO Stage 3 emergencies in
January 2001. SCE will oppose the order as inadequate, particularly because the FERC is unwilling to exercise
any control over sellers' exercise of market power during periods other than Stage 3 emergencies. On March 16,
2001, the FERC ordered six wholesale sellers of energy to refund an additional $55 million or submit
cost-of-service information to the FERC to justify their prices above $430/MWh during ISO Stage 3 emergencies in
February 2001. A Stage 3 emergency refers to 1.5% or less in reserve power, which could trigger rotating
blackouts in some neighborhoods.
On April 25, 2001, the FERC issued an order providing for cost-based 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. The order is in effect for one year.
Memorandum of Understanding with the CDWR
On April 9, 2001, Edison International and 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 legislation, 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
Page 19
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 or
another state agency for the provision of power to the state at cost-based rates for ten years from a power
project currently under development. Edison Mission Energy will use all commercially reasonable efforts to
place the first phase of the project into service before the end of summer 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.
Page 20
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. Edison
International, 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 MOU may be terminated by
either SCE or the CDWR if required legislation is not adopted and definitive agreements executed by August 15,
2001, or if the CPUC does not adopt required decisions within 60 days after the MOU was signed, or if certain
other adverse changes occur. SCE cannot provide assurance that all the required legislation will be enacted,
regulatory actions taken, and definitive agreements executed before the applicable deadlines. The CPUC has
stated it will expeditiously review those provisions of the MOU that require resolution. SCE and the Governor
have been working diligently to have the MOU supported by the legislature. However, no formal action has been
taken by either the CPUC or the legislature.
CDWR Power Purchases
Pursuant to 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 will become effective
in 90 days. 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 CDWR-related 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 on an interim basis to SCE's customers. The CPUC determined that the applicable rate
component is 7.277(cent)per kWh (which will increase 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. Using these rates, SCE has billed customers or accrued $251 million for sales made by
the CDWR and ISO during the period January 19 through April 30, 2001, and has forwarded $147 million to the CDWR
on behalf of these customers as of April 30, 2001.
Page 21
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On April 3, 2001, the CPUC adopted the method (originally proposed in the March 27 CDWR-related order discussed
above) it will use to calculate the CPA (which was established by AB 1X) and then applied the method to calculate
a company-wide CPA rate for SCE. The CPUC used that rate to determine the CPA revenue amount that can be used by
the CDWR for issuing bonds. The CPUC stated that its decision is narrowly focused to calculate the maximum
amount of bonds that the CDWR may issue and does not dedicate any particular revenue stream to the CDWR. In its
calculation of the CPA, the CPUC disregarded all of the adjustments requested by SCE in its comments filed on
March 29 and April 2, 2001. SCE's comments included, among other things, a forecast showing that the net effect
of the rate increases (discussed in Rate Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Note 2) and the payments ordered to be made to CDWR, could result in a shortfall in the CPA
calculation of $1.7 billion for SCE during 2001. SCE estimates that its future revenue will not be sufficient to
cover its retained generation, purchased-power and transition costs. To implement the MOU, the CPUC will need to
modify the calculation methods and provide reasonable assurance that SCE will be able to recover its ongoing
costs.
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, and has billed SCE a total
of $580 million for January and February 2001 purchases. 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 first quarter 2001 could increase by as much as $800 million. 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 recently executed
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 22
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
$379 million (nominal value) of its existing contracts were terminated by the counterparties in early 2001. At
March 31, 2001, these contracts had a nominal value of $435 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. Changes in the value of bilateral forward contracts affects purchased power expense in
the period when the power is delivered.
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 March 31, 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 on this interest rate swap terminated the agreement. As a result
of the termination of the swap, SCE is paying a floating rate on
Page 23
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$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 swap agreement
(terminated January 5, 2001) and its block forward power-purchase contracts at fair value on its 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 other elements
of the MOU are 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 March 31, 2001, balance sheet no longer includes these contracts.
As of March 31, 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.
Fair values of financial instruments were:
March 31, December 31, March 31,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------
Cost Fair Cost Fair Cost Fair
Instrument Basis Value Basis Value Basis Value
-------------------------------------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $1,720 $2,372 $ 1,720 $ 2,505 $ 1,673 $ 2,581
Equity investments -- -- -- -- -- 38
Gas call options -- -- -- -- 25 24
Financial liabilities:
DOE decommissioning and
decontamination fees 36 25 36 31 40 35
Interest rate swap -- -- -- 21 -- 10
Short-term debt 2,120 1,985 1,451 1,339 849 849
Long-term debt 5,405 4,642 5,631 5,178 5,109 5,020
Preferred stock subject to
mandatory redemption 256 89 256 157 256 258
-------------------------------------------------------------------------------------------------------------
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 March 31, 2001, December 31, 2000, and March 31,
2000.
Page 24
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gross unrealized holding gains on debt and equity investments were:
March 31, December 31, March 31,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $ 153 $ 193 $ 243
Stocks 322 384 474
U.S. government issues 113 136 148
Short-term and other 64 72 43
---------------------------------------------------------------------------------------------------------------
652 785 908
Equity investments -- -- 38
---------------------------------------------------------------------------------------------------------------
Total $ 652 $ 785 $ 946
---------------------------------------------------------------------------------------------------------------
There were no unrealized holding losses for the periods presented.
Note 5. Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage
bonds as security for borrowed funds obtained from pollution control bonds issued by government agencies. SCE
uses these proceeds to finance construction of pollution control facilities. Bondholders have limited discretion
in redeeming certain pollution-control bonds, and SCE has arrangements with securities dealers to remarket or
purchase them if necessary. As a result of investors' concerns regarding SCE's liquidity difficulties and
overall financial condition, SCE has 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.
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
Page 25
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
International and the transition property is legally not an asset of SCE or Edison International. Due to SCE's
recent credit downgrade, in January 2001, SCE began remitting its customer collections related to the rate-reduction
notes on a daily basis.
Long-term debt consisted of:
March 31, December 31, March 31,
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%) 1,662 1,724 1,909
Pollution control bonds:
2008 - 2040 (5.125% to 7.2% and variable) 1,216 1,216 1,197
Bonds repurchased (550) (420) --
Funds held by trustees (47) (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 71 79 56
Long-term debt due within one year (646) (646) (448)
Unamortized debt discount - net (26) (27) (28)
-------------------------------------------------------------------------------------------------------------------
Total $ 5,405 $ 5,631 $ 5,109
-------------------------------------------------------------------------------------------------------------------
Long-term debt maturities and sinking-fund requirements for the five twelve-month periods following March 31,
2001, are: 2002 - $646 million; 2003 - $746 million; 2004 - $1.4 billion; 2005 - $371 million; and 2006 -
$446 million. These projections assume no acceleration of payments arising from default. See further discussion
in Note 2.
As a result of its liquidity crisis, SCE has taken steps to conserve cash, and has been forced to consider
further alternatives for conserving 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 April 30, 2001, SCE has
failed to pay $200 million of maturing principal on its 5-7/8% notes. Under the indenture for SCE's senior
unsecured notes, the failure to pay principal was an immediate event of default as to the one series of notes on
which the principal was due. If an event of default occurs as to any series of senior unsecured notes, the
trustee or the holders of 25% in principal amount of the notes of such series may declare the principal of the
notes of that series to be immediately due and payable. In addition, SCE's failure to pay any obligation for
borrowed money in an aggregate amount in excess of $10 million would constitute an event of default with respect
to all of the senior unsecured notes and SCE's outstanding quarterly income preferred securities if not cured
within 30 days after notice from the trustee or holders of the securities. No such notice has been received by
SCE.
If a notice of default is received, SCE could cure the default only by paying $731 million in overdue principal
to holders of commercial paper and the 5-7/8% notes. (SCE has also deferred payment of maturing commercial
paper. See Note 6 for a further discussion.) Making such payment would further impact SCE's liquidity. If a
notice of default were received and not cured, and the trustee or noteholders 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.
Page 26
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In January 2001, three rating agencies lowered their credit ratings of SCE to substantially below investment
grade. In mid-April, one agency removed SCE's credit ratings from review for possible downgrade. The ratings
remain under review for possible downgrade by the other two agencies.
Note 6. Short-Term Debt
Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash
requirements, including PX and ISO payments. Commercial paper intended to finance nuclear fuel scheduled to be
used more than one year after the balance sheet date is classified as long-term debt in connection with
refinancing terms under five-year term lines of credit with commercial banks.
Short-term debt consisted of:
March 31, December 31, March 31,
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 (71) (79) (56)
Unamortized discount -- (5) (4)
----------------------------------------------------------------------------------------------------------
Total $ 2,120 $ 1,451 $ 849
----------------------------------------------------------------------------------------------------------
Weighted-average interest rate 6.4% 6.9% 6.0%
At March 31, 2001, SCE had lines of credit 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.
In SCE's efforts to conserve cash, SCE has deferred payment of approximately $531 million of maturing commercial
paper as of April 30, 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 March 31, 2001, are: 2002 -
zero; 2003 - $109 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.
Page 27
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
March 31, December 31, March 31,
Dollars in millions, except per share amounts 2001 2000 2000
-----------------------------------------------------------------------------------------------------------------------
March 31, 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
-------------------------------------------------------------------------------------------------------------------
Total $ 256 $ 256 $ 256
-------------------------------------------------------------------------------------------------------------------
There were no preferred stock issuances or redemptions for the periods presented.
SCE's Board has not declared the regular quarterly dividends for SCE's cumulative preferred stock, 4.08% Series,
4.24% Series, 4.32% Series, 4.78% Series, 6.05% Series, 6.45% Series and 7.23% Series in 2001. As of April 30,
2001, SCE's preferred stock dividends in arrears were $6 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 28
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net accumulated deferred income tax liability were:
March 31, December 31, March 31,
In millions 2001 2000 2000
---------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Property-related $ 226 $ 277 $ 181
Unrealized gains or losses 420 420 453
Investment tax credits 73 81 105
Regulatory balancing accounts 2,123 1,763 77
Decommissioning 94 98 127
Accrued charges 387 379 254
Unbilled revenue 92 101 113
Other 173 56 77
---------------------------------------------------------------------------------------------------------------
Total $ 3,588 $ 3,175 $ 1,387
---------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $ 2,316 $ 2,184 $ 2,545
Capitalized software costs 214 264 231
Regulatory balancing accounts 1,819 1,632 476
Unrealized gains and losses 317 317 351
Other 357 242 539
---------------------------------------------------------------------------------------------------------------
Total $ 5,023 $ 4,639 $ 4,142
---------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net $ 1,435 $ 1,464 $ 2,755
---------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $ 1,960 $ 2,009 $ 2,880
Included in current assets 525 545 125
The current and deferred components of income tax expense were:
3 Months Ended 12 Months Ended
March 31, March 31,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Current:
Federal $ (172) $ 132 $ (409) $ 437
State -- 30 (30) 112
-------------------------------------------------------------------------------------------------------------------
(172) 162 (439) 549
-------------------------------------------------------------------------------------------------------------------
Deferred - federal and state:
Accrued charges (9) (9) (133) (134)
Contributions in aid of construction 6 6 (10) (9)
Property related 62 (48) (192) (196)
Investment and energy tax credits - net (5) (10) (36) (44)
Operating loss carryforwards (51) -- (66) --
Regulatory assets (53) 1 197 5
Regulatory balancing accounts (193) (9) (923) 317
State tax privilege year (10) 16 4 (11)
Unbilled revenue (1) 9 11 (10)
Other 16 2 35 3
-------------------------------------------------------------------------------------------------------------------
(238) (42) (1,113) (79)
-------------------------------------------------------------------------------------------------------------------
Total $ (410) $ 120 $ (1,552) $ 470
-------------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income $ (419) $ 123 $ (1,549) $ 491
Included in other income 9 (3) (3) (21)
Page 29
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The composite federal and state statutory income tax rate was 40.551% for all periods presented.
The federal statutory income tax rate is reconciled to the effective tax rate below:
3 Months Ended 12 Months Ended
March 31, March 31,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0% 35.0%
Capitalized software 0.2 (0.9) 0.3 (2.3)
Property-related and other -- 13.5 (4.2) 9.1
Investment and energy tax credits 0.5 (4.4) 0.8 (4.1)
State tax - net of federal deduction 5.3 6.8 4.2 8.4
-------------------------------------------------------------------------------------------------------------------
Effective tax rate 41.0% 50.0% 36.1% 46.1%
-------------------------------------------------------------------------------------------------------------------
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 and $29 million for the three- and twelve-months ended March 31,
2001, respectively, and $8 million and $28 million for the three- and twelve-months ended March 31, 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 30
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
3 Months Ended Year Ended 3 Months Ended
March 31, December 31, March 31,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 2,200 $ 2,075 $ 2,075
Service cost 17 63 16
Interest cost 38 155 39
Actuarial loss -- 90 --
Benefits paid (61) (183) (52)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 2,194 $ 2,200 $ 2,078
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 3,067 $ 3,078 $3,078
Actual return on plan assets (191) 143 177
Employer contributions -- 29 29
Benefits paid (61) (183) (52)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 2,815 $ 3,067 $ 3,232
-------------------------------------------------------------------------------------------------------------------
Funded status $ 621 $ 867 $ 1,154
Unrecognized net loss (gain) (483) (745) (1,125)
Unrecognized transition obligation 21 22 27
Unrecognized prior service cost 114 118 128
-------------------------------------------------------------------------------------------------------------------
Recorded asset $ 273 $ 262 $ 184
-------------------------------------------------------------------------------------------------------------------
Discount rate 7.25% 7.25% 7.75%
Rate of compensation increase 5.0% 5.0% 5.0%
Expected return on plan assets 8.5% 8.5% 7.5%
The components of pension expense were:
3 Months Ended 12 Months Ended
In millions March 31, March 31,
-------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 17 $ 16 $ 64 $ 64
Interest cost 38 39 154 147
Expected return on plan assets (63) (57) (272) (197)
Net amortization and deferral (3) (8) (35) 1
-------------------------------------------------------------------------------------------------------------------
Pension expense (benefit ) under
accounting standards (11) (10) (89) 15
Regulatory adjustment - deferred 11 10 89 22
-------------------------------------------------------------------------------------------------------------------
Net pension expense recognized $ -- $ -- $ -- $ 37
-------------------------------------------------------------------------------------------------------------------
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 31
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
3 Months Ended Year Ended 3 Months Ended
March 31, December 31, March 31,
In millions 2001 2000 2000
-------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of period $ 1,762 $ 1,462 $ 1,462
Service cost 11 39 9
Interest cost 33 121 29
Actuarial loss -- 202 --
Benefits paid (17) (62) (15)
-------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 1,789 $ 1,762 $ 1,485
-------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 1,200 $ 1,283 $ 1,283
Actual return on plan assets 26 (40) 23
Employer contributions 5 19 21
Benefits paid (17) (62) (15)
-------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 1,214 $ 1,200 $ 1,312
-------------------------------------------------------------------------------------------------------------------
Funded status $ (575) $ (562) $ (173)
Unrecognized net loss (gain) 141 141 (206)
Unrecognized transition obligation 317 323 342
-------------------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (117) $ (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 12 Months Ended
March 31, March 31,
-------------------------------------------------------------------------------------------------------------------
In millions 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------
Service cost $ 11 $ 9 $ 41 $ 44
Interest cost 33 29 125 112
Expected return on plan assets (26) (23) (109) (83)
Net amortization and deferral 6 6 27 26
-------------------------------------------------------------------------------------------------------------------
Total $ 24 $ 21 $ 84 $ 99
-------------------------------------------------------------------------------------------------------------------
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 March 31, 2001, by $282 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 March 31, 2001, by $242 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
Page 32
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
limited annual award of Edison International common shares and options on shares. The annual 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 8.4 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 expire 10 years
after the date of grant, and vest over a period of up to five years. No special stock options from the 2000
Equity Plan may 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 executive long-term incentive program 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 May 2000 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.
Page 33
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The performance share values are accrued ratably over a three-year performance period. SCE measures compensation
expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under
the stock-compensation programs was $0 million and $3 million for the three and twelve months ended March 31,
2001, respectively, and $1 million and $5 million for the three and twelve months ended March 31, 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 $(600) million and $(2.767) billion for the three and twelve months
ended March 31, 2001, respectively, and $118 million and $544 million for the three and twelve months ended March
31, 2000, respectively.
The fair value for each option granted, reflecting 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:
March 31, March 31,
2001 2000
----------------------------------------------------------------------------------------------------------
Expected life 7 years - 10 years 7 years - 10 years
Risk-free interest rate 4.7% - 6.0% 5.0% - 5.6%
Expected volatility 17% - 48% 17% - 24%
----------------------------------------------------------------------------------------------------------
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 March 31, 2001, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
-------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 41 $ 11 $ 1 60%
Pacific Intertie 230 81 8 50%
Generating stations:
Four Corners Units 4 and 5 (coal) 463 354 3 48%
Mohave (coal) 328 243 3 56%
Palo Verde (nuclear)(1) 1,626 1,461 16 16%
San Onofre (nuclear)(1) 4,270 3,893 22 75%
-------------------------------------------------------------------------------------------------------------------
Total $ 6,958 $ 6,043 $ 53
-------------------------------------------------------------------------------------------------------------------
(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 34
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 March 31, 2001, were:
Year ended December 31, In millions
-------------------------------------------------------------------------------------------------
2001 $ 11
2002 12
2003 11
2004 10
2005 6
Thereafter 15
-------------------------------------------------------------------------------------------------
Total $ 65
-------------------------------------------------------------------------------------------------
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 $11 million and $93 million for the three and twelve months ended March 31, 2001,
respectively, and $23 million and $108 million for the three and twelve months ended March 31, 2000. The
accumulated provision for decommissioning, excluding San Onofre Unit 1, was $1.4 billion at March 31, 2001, and
at December 31, 2000, and $1.3 billion at March 31, 2000. The estimated costs to decommission San Onofre Unit 1
(approximately $344 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 35
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Trust investments (cost basis) include:
Maturity March 31, December 31, March 31,
In millions Dates 2001 2000 2000
----------------------------------------------------------------------------------------------------------------
Municipal bond 2001 - 2033 $ 491 $ 548 $ 661
Stocks -- 614 531 482
U.S. government issues 2001 - 2029 397 421 419
Short-term and other 2001 218 220 111
----------------------------------------------------------------------------------------------------------------
Total $ 1,720 $ 1,720 $ 1,673
----------------------------------------------------------------------------------------------------------------
Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated
provision for decommissioning. Net earnings (loss) were $(13) million and $16 million for the three and twelve
months ended March 31, 2001, respectively, and $9 million and $53 million for the three and twelve months ended
March 31, 2000, respectively. Proceeds from sales of securities (which are reinvested) were $765 million and
$3.7 billion for the three and twelve months ended March 31, 2001, respectively, and $1.7 billion and $4.0
billion for the three and twelve months ended March 31, 2000, respectively. Approximately 90% 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 commitments for the years 2001 through 2005 are estimated below:
In millions 2001 2002 2003 2004 2005
------------------------------------------------------------------------------------------------------------
Fuel supply contracts $ 151 $ 108 $ 116 $ 97 $ 97
Purchased-power capacity payments 647 644 637 635 632
------------------------------------------------------------------------------------------------------------
Page 36
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE's projected construction expenditures for 2001 total approximately $602 million. The construction program is
subject to periodic review and revision, and actual construction costs may vary from estimates because of
numerous factors.
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 class action securities lawsuit was filed in federal district court in Los Angeles against SCE
and Edison International. As amended in December 2000 and March 2001, the lawsuit alleges that SCE and Edison
International are engaging in fraud by over-reporting and improperly 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 beginning June 1, 2000, and continuing until such time as TRA-related undercollections
are recorded as a loss by SCE. The response to the second amended complaint was deferred. This lawsuit has been
consolidated with another similar lawsuit filed on March 15, 2001. SCE believes that its current and past
accounting for the TRA undercollections and related items is appropriate and in accordance with accounting
principles generally accepted in the United States.
As of May 11, 2001, 25 lawsuits have been filed against SCE by QFs. The lawsuits have been filed by various
parties, including geothermal or wind energy suppliers or owners of cogeneration projects. 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. On April 5, 2001, SCE submitted
a petition requesting the coordination before a single judge of those QF lawsuits then pending in California
state court. A state court coordination judge has been assigned and SCE's motion to coordinate is pending. SCE
is also taking steps to coordinate the QF cases on file in federal court. 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.
Page 37
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 $74 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 March 31, 2001, were $17 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.
Page 38
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $175 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. These policies are issued primarily by a mutual
insurance company owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the
arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed
retrospective premium adjustments of up to $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 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 has not determined
the costs for spent-fuel storage beyond that period, which would require new and separate interim storage
facilities. 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 39
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 Proceeding. Since 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 has been accumulated in the transition revenue account (TRA), a CPUC-authorized
regulatory asset. 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. The MOU is
discussed in detail in the Memorandum of Understanding with the CDWR section. 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. If required legislation is not adopted and definitive agreements executed by
August 15, 2001, or if the CPUC does not adopt required implementing decisions by June 8, 2001, the MOU may be
terminated by SCE or the CDWR. SCE cannot provide assurance that all the required legislation will be enacted,
regulatory actions taken and definitive agreements executed before the applicable deadlines.
Accounting principles generally accepted in the United States permit SCE to defer costs as 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 transition cost balancing account (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 Proceeding. 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 contemplated by the MOU occur, or other 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 (as restated to reflect the CPUC's March 27, 2001, decisions) and 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. For first quarter 2001, $661 million (after tax) of unrecovered transition costs were charged to
earnings. 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 revenue to cover its ongoing costs and
obligations through the CPUC's March 27, 2001,
Page 40
decisions. 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 the MOU is implemented, or 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, current
accounting standards provide that a regulatory asset would be reinstated with a corresponding
increase in earnings.
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.
Results of Operations
Earnings
SCE recorded a loss of $598 million and $2.8 billion, respectively, for the three and twelve months ended March
31, 2001. The quarterly and twelve-months-ended losses reflect $661 million (after tax) of transition costs in
excess of transition revenue during the first quarter of 2001. For financial reporting purposes, these
undercollected costs are no longer accumulated in the TCBA 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 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 was unable to conclude that, under applicable accounting principles, the $2.9 billion
TCBA undercollection (as recalculated above) and $1.3 billion (book value) of other regulatory assets and
liabilities, 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.
The regulatory and legislative actions set forth in the MOU, if implemented, are expected to result in a
rate-making mechanism that would make recovery of the regulatory assets that were written off probable. If and
when those actions are taken, or others occur that make such recovery probable, and the necessary rate-making
mechanism is adopted, 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 recorded a loss of $598 million and $2.8 billion, respectively, for the three and twelve
months ended March 31, 2001, compared with earnings of $113 million and $520 million, respectively, for the same
periods in 2000. Excluding the $661 million (after tax) of undercollected
Page 41
transition costs that are no longer accumulated in balancing accounts and instead are expensed as incurred,
SCE's first quarter 2001 earnings were $63 million, down $50 million from the prior-year period. The
quarterly decrease was mainly due to higher interest expense resulting from the deteriorated financial
condition of SCE and lower earnings resulting from the February 2001 fire and resulting outage at the
San Onofre Nuclear Generating Station. See further discussion of the San Onofre fire in the San Onofre
Nuclear Generating Station section. Excluding the $661 million (after tax) of undercollected transition
costs and the $2.5 billion (after tax) December 31, 2000, write-off, SCE would have earned $421 million
for the twelve months ended March 31, 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 March 31, 2000, were $505 million. The $84 million decrease for the twelve months ended March 31,
2001, from the prior-year period, was mainly the result of higher interest expense and adjustments to reflect
potential regulatory refunds.
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 in the TCBA 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. In addition to the losses from the unrecovered transition costs, SCE
expects its 2001 earnings to be negatively affected by the February 2001 fire and resulting outage at San Onofre
Unit 3.
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.
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 and twelve months ended March 31, 2001, compared to the year-earlier
periods. The quarterly decrease was primarily due to a 23% decrease in retail sales volume, as well as the
credit given to customers who chose direct access. The volume decrease was primarily the result of SCE no longer
supplying its customers with all of their electricity needs, beginning on January 18, 2001. See CDWR Power
Purchases discussion. These decreases were partially offset by the effects of the 1(cent)-per-kWh surcharge
originally granted on January 4, 2001, and affirmed by the CPUC on March 27, 2001. The twelve-months-ended
decrease was primarily due to the credit given to customers who chose direct access. This decrease was partially
offset by the effects of the 1(cent)-per-kWh surcharge and an increase in revenue related to penalties customers
incurred for not adhering to their interruptible contracts.
More than 92% of operating revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale
rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warmer weather during the summer months, operating revenue during the third quarter of each year is
significantly higher than other quarters.
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Operating Expenses
Fuel expense decreased for the twelve months ended March 31, 2001, compared with the same period in 2000,
primarily due to fuel-related refunds resulting from a settlement with another utility that SCE recorded in the
second and third quarters of 2000.
Purchased-power expense increased significantly for both the three and twelve months ended March 31, 2001,
compared to the same periods in 2000. The increases were the result of: increased California Power Exchange
(PX)/Independent System Operator (ISO) purchased-power expense through January 18, 2001, and increased
purchased-power expense related to qualifying facilities (QFs) and interutility contracts. See Purchased Power
table in Note 1 to the Consolidated Financial Statements. See further discussion in CDWR Power Purchases.
PX/ISO purchased-power expense increased significantly 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 March 31, 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 March 31, 2001, compared to the same period in 2000, purchased-power expense
was reduced by $104 million and $682 million, respectively, due to SCE's use of gas call options and PX block
forward contracts. For a further discussion of SCE's hedging instruments and the significant increases in power
prices, see Market Risk Exposures. In December 2000, the FERC eliminated the requirement that SCE buy and sell
its purchased and generated power through the PX and ISO. See further discussion in Wholesale Electricity
Markets. 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 for the day-of market effective January 18, 2001, and, for the day-ahead market
effective January 19, 2001. See further discussion of SCE's liquidity crisis in Financial Condition.
Prior to April 1998, SCE was required under federal law and CPUC orders to enter into contracts to purchase power
from qualifying facilities (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
both the three and twelve months ended March 31, 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 with the CDWR, as well as the terms in some of the QF
contracts reverting to lower prices.
Provisions for regulatory adjustment clauses decreased for the three months ended March 31, 2001, compared to the
year-earlier period. The decrease primarily resulted from SCE no longer accumulating undercollected transition
costs in the TCBA, as well as undercollections related to the administration of energy conservation programs and
other public benefit programs. Provisions for regulatory adjustment clauses increased for the twelve months
ended March 31, 2001, compared to the same period in 2000, mainly due to a $4 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 the
interruptible rate programs. SCE's use of gas call options decreased the provisions by $4 million for the
quarter ended March 31, 2000. SCE's use of gas call options increased the provisions by $105 million and $2
million, respectively, for the twelve months ended March 31, 2001, and March 31, 2000.
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Depreciation, decommissioning and amortization expense decreased for both the three and twelve months ended March
31, 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 did not
record any amortization expense related to this asset during first quarter 2001.
Income taxes decreased for both the three and twelve months ended March 31, 2001, compared to the year-earlier
periods, primarily due to a $497 million income tax benefit arising from the transition costs in excess of
transition revenue during first quarter 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.
Other Income and Deductions
Interest and dividend income increased for both the three and twelve months ended March 31, 2001, compared to the
year-earlier periods. The quarterly increase resulted primarily from higher cash balances as SCE conserves cash
due to its liquidity crisis, as well as interest earned on undercollections in SCE's remaining balancing
accounts. SCE wrote off its $2.9 billion (after tax) TCBA undercollection (as restated to reflect the CPUC's
March 27, 2001, decisions) as of December 31, 2000. The twelve months ended increase is primarily due to
interest earned, prior to the write-off, on higher balancing account undercollections.
Other nonoperating income decreased for both the three and twelve months ended March 31, 2001. The quarterly
decrease was primarily due to 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 less gains on the sales of equity
investments.
Interest expense - net of amounts capitalized increased for both the three and twelve months ended March 31,
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 both the three and twelve months ended March 31, 2001, compared to
the same periods in 2000, due to lower accruals for regulatory matters.
The taxes on other income and deductions increased for the quarter ended March 31, 2001, compared to the
year-earlier period, mostly due to higher pre-tax nonoperating income. Tax benefits on other income and
deductions decreased for the twelve months ended March 31, 2001, compared to the same period in 2000, primarily
the result of tax expense related to interest income and other nonoperating income exceeding the tax benefits
related to interest expense and other nonoperating deductions, as well as a $15 million one-time tax benefit in
1999 due to an Internal Revenue Service ruling.
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 lack of creditworthiness (further discussed in Liquidity Crisis), at March 31, 2001, the fair
market value of $541 million of its short-term debt was approximately 75% of its carrying value.
Page 44
Beginning in 1995, Edison International's Board of Directors authorized the repurchase of up to $2.8 billion of
its outstanding shares of common stock. Edison International repurchased more than 21 million shares
(approximately $400 million) of its common stock during the first six months of 2000. These were the first
repurchases since first quarter 1999. Between January 1, 1995, and June 30, 2000, Edison International
repurchased $2.8 billion (approximately 122 million shares) of its outstanding shares of common stock, funded by
dividends from its subsidiaries (primarily from SCE).
Liquidity Crisis
Sustained higher wholesale energy prices that began in May 2000 persisted through Spring 2001. This resulted in
an increasing undercollection in the TRA. The increasing undercollection, coupled with SCE's anticipated
near-term capital requirements (detailed in the Projected Capital Requirements 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, SCE temporarily suspended payments of certain
obligations for principal and interest on outstanding debt and for purchased power. As of April 30, 2001, SCE
had $3.1 billion in obligations that were unpaid and overdue including: (1) $882 million to the PX or ISO; (2)
$1.3 billion to QFs; (3) $230 million in PX energy credits for energy service providers; (4) $531 million of
matured commercial paper; and (5) $200 million of principal on its 5-7/8% notes. 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 April 30, 2001, could increase by as much as $800 million. See additional discussion in CDWR
Power Purchases. As applicable, unpaid obligations will continue to accrue interest. SCE's failure to pay when
due the principal amount of the 5-7/8% series of notes constitutes 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 notes (totaling $2.5 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, entitling those lenders to exercise their remedies including potential acceleration of the
outstanding borrowings of $1.6 billion. If a notice of default is received, SCE could cure the default only by
paying $731 million in overdue principal to holders of commercial paper and the 5-7/8% 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.
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% notes and commercial paper when due. The forbearance agreement has been
extended three times and currently expires on September 15, 2001. The $200 million short-term bank credit
facility was scheduled to mature on May 14, 2001. The maturity date has been extended to September 15, 2001. At
April 30, 2001, SCE had estimated cash reserves of approximately $1.9 billion, which was approximately $1.3
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 ordered SCE and the other California investor-owned utilities to pay QFs for power
deliveries on a going forward basis, commencing with April 2001 deliveries. SCE must pay the QFs within 15 days
of the end of the QFs' billing periods, and QFs are allowed to establish 15-day billing
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periods. Failure to make a required payment within 15 days of delivery would result in a fine equal to the
amount owed to the QF. The CPUC decision 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 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. See further discussion of QFs in Litigation.
On March 27, 2001, the CPUC also issued decisions on the California Procurement Adjustment (CPA) calculation (see
CDWR Power Purchases discussion) and the approval of a 3(cent)-per-kWh rate increase (see Rate Stabilization
Proceeding discussion). Based on these two decisions, SCE estimates that cash going forward may not be
sufficient to cover retained generation, purchased-power and transition costs. In comments filed with the CPUC
on March 29, 2001, and April 2, 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 discussed above could result in a shortfall to
the CPA calculation of $1.7 billion for SCE 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 either December 2000 or March 2001. Also, SCE's Board has not declared the
regular quarterly dividends for SCE's cumulative preferred stock, 4.08% Series, 4.24% Series, 4.32% Series, 4.78%
Series, 6.05% Series, 6.45% Series and 7.23% Series in 2001. As of April 30, 2001, SCE's preferred stock
dividends in arrears were $6 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. SCE does not meet other conditions under which dividends
can be paid from sources other than retained earnings. 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. These actions were expected to impact about 1,450 to 1,850 jobs, affect service levels
for customers, and reduce near-term capital expenditures to levels that will not sustain operations in the long
term. However, on March 15, 2001, the CPUC issued an order rescinding SCE's layoffs of employees involved with
service and reliability. SCE was also ordered to restore specified service levels, make regular reports to the
CPUC concerning its cost-cutting measures, and track its cost savings pending future adjustments to rates. The
amount of the cost savings affected by the order is not material. SCE's current actions, including the
suspension of debt and purchased-power payments, 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 the MOU is implemented, or other 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 excessively high price of energy. Without a change in
circumstances, such as that contemplated by the MOU, 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.
Page 46
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.2 billion and $1.4 billion, respectively, for the three and
twelve months ended March 31, 2001, compared with $581 million and $1.7 billion for the same periods in 2000.
The quarterly increase in cash flows provided by operating activities was primarily due to SCE's conservation of
cash. The decrease in cash flows provided by operating activities for the twelve months ended March 31, 2001,
was due to the extremely high prices SCE paid for energy and ancillary services procured through the PX and ISO
since May 2000. Cash flows provided by operations is expected to continue to increase in the first half of 2001
as SCE continues to defer payments on its obligations as a result of its liquidity crisis.
Beginning first quarter 2001, the cash flow coverage of dividends quarterly calculation is not being presented
due to SCE's inability to pay dividends (discussed above in the Liquidity Crisis section). For the twelve months
ended March 31, 2001, the cash flow coverage of dividends was 4.8 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.
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 March 31, 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. SCE is
currently negotiating with bank lenders to extend the $200 million 364-day credit facility maturing on May 14,
2001.
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. In mid-April, Moody's removed SCE's credit ratings from review for
possible downgrade. The ratings remain under review for possible downgrade by the other agencies.
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.
Page 47
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.
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.
Projected Capital Requirements
SCE's projected construction expenditures for 2001 are $602 million. This projection reflects SCE's cost-cutting
measures discussed above in the Liquidity Crisis section.
Long-term debt maturities and sinking fund requirements for the five twelve month periods following March 31,
2001, are: 2002 - $646 million; 2003 - $746 million; 2004 - $1.4 billion; 2005 - $371 million; and 2006 -
$446 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 March 31, 2001, are: 2002-
zero; 2003 - $109 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.
Page 48
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in both energy prices and interest rates. 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, since May 2000, market power prices have skyrocketed, 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 these caps are set at high levels and are not entirely
effective (see further discussion in Wholesale Electricity Markets). For example, SCE paid an average of $248
per megawatt in December 2000, versus an average of $32 per megawatt in December 1999.
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 March 31, 2001, the nominal value of SCE's bilateral forward contracts was $435 million.
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 other elements of the MOU are 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 March 31, 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.
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Regulatory Environment
SCE operates in a highly regulated environment in which it has an obligation to deliver electric service to
customers in return for an exclusive franchise within its service territory and certain obligations of the
regulatory authorities 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 gas-fired
generation portfolio. Today, independent power companies own those generating plants. Along with electric
industry restructuring, a multi-year freeze on the rates that SCE could charge its customers was mandated and
transition cost recovery mechanisms (as described in Status of Transition and Power-Procurement Cost Recovery)
allowing SCE to recover its stranded costs associated with generation-related assets were implemented.
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 were to remain in
effect until the earlier of March 31, 2002, or the date when the CPUC-authorized costs for utility-owned
generation assets and obligations were recovered. However, since May 2000, 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 has been recovered 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 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 have now been transferred to the TRA on a monthly basis, retroactive to
January 1, 1998. In addition, the TRA balance, whether over- or undercollected, has now been 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,
Page 50
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. 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. 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. Under the MOU, both nuclear facilities would be subject to
cost-based ratemaking upon completion of their respective rate-making plans and the sharing mechanisms that were
to begin in 2004 and 2002 would be eliminated. 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 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),
pursuant to 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 Proceeding) was written off as of December 31,
2000.
During 2000, SCE entered into agreements to sell 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.
Page 51
CDWR Power Purchases
--------------------
Pursuant to 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. The new law 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 will be effective
in 90 days. AB 1X directed the CPUC to determine the amount of a 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 CDWR-related 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 non-generation 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. The CPUC determined that the company-wide generation-related 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 each kWh delivered to customers beginning 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. Using these rates, SCE has billed customers or accrued $251 million for
energy sales made by the CDWR and ISO during the period January 19 through April 30, 2001, and has forwarded $147
million to the CDWR on behalf of these customers as of April 30, 2001.
On April 3, 2001, the CPUC adopted the method (originally proposed in the March 27 CDWR-related order discussed
above) it will use to calculate the CPA (which was established by AB 1X) and then applied the method to calculate
a company-wide CPA rate for SCE. The CPUC used that rate to determine the CPA revenue amount that can be used by
the CDWR for issuing bonds. The CPUC stated that its decision is narrowly focused to calculate the maximum
amount of bonds that the CDWR may issue and does not dedicate any particular revenue stream to the CDWR. In its
calculation of the CPA, the CPUC disregarded all of the adjustments requested by SCE in its comments filed on
March 29 and April 2, 2001. SCE's comments included, among other things, a forecast showing that the net effect
of the rate increases (discussed in Rate Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Liquidity Crisis) and the payments ordered to be made to CDWR (discussed above), could result in a
shortfall in the CPA calculation of $1.7 billion for SCE during 2001. SCE estimates that its future revenue will
not be sufficient to cover its retained generation, purchased-power and transition costs. To implement the MOU
described in Memorandum of Understanding with CDWR, the CPUC will need to modify the calculation methods and
provide reasonable assurance that SCE will be able to recover its ongoing costs.
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
Page 52
position that it will charge SCE for the costs of power it purchases in this manner, and has billed SCE a total
of $580 million for January and February 2001 purchases. 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 first quarter 2001 could increase by as much as $800 million. In its March 27, 2001, interim
order, the CPUC stated that it can not 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 recently executed 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 San Onofre Units 2
and 3 and the Palo Verde units. Transition costs related to power-purchase QF contracts are being recovered
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 from January 2001 associated with retained generation and
existing power contracts, the implementation of the MOU requires the CPUC to modify various decisions (discussed
in Rate Stabilization Proceeding). Until the various regulatory and legislative actions necessary to implement
the MOU, or other actions that make such recovery probable are taken, SCE is unable to conclude that the
regulatory assets and liabilities related to purchased-power settlements, the unamortized loss on SCE's
generating plant sales in 1998, and various other regulatory assets and liabilities 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 revenue from the
sale of SCE-controlled generation into the ISO and PX markets, and competition transition charge (CTC) revenue.
However, due to events discussed elsewhere in this report, revenue from the sale or valuation of generation
assets in excess of book values (state legislation enacted in January 2001 bars 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) are no longer available to SCE. During 1998, SCE sold all of its
gas-fueled generation plants for $1.2 billion, over $500 million more than the combined book value. Net proceeds
of the sales were used to reduce transition costs, which otherwise were expected to be collected through the TCBA
mechanism.
Page 53
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. Since May 2000, 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. Pursuant
to 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 Proceeding).
Upon recalculating the TCBA balance based on the new decision, SCE received positive residual CTC revenue (TRA
overcollections) of $4.7 billion to recover its transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000. As a result of sustained higher market prices, May 2000 was the first month in
which SCE's costs exceeded revenue. Since then, SCE's costs to provide power have continued to exceed revenue
from frozen rates and as a result, the cumulative positive residual CTC revenue flowing into the TCBA mechanism
has been reduced from $4.7 billion to $1.4 billion as of March 31, 2001. The cumulative TCBA undercollection (as
recalculated) was $2.9 billion as of December 31, 2000, and $3.9 billion as of March 31, 2001. A summary of the
components of this cumulative undercollection as of March 31, 2001, is as follows:
In millions
-----------------------------------------------------------------------------------------------------
Transition costs recorded in the TCBA:
QF and interutility costs $ 4,556
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 613
Other transition costs 732
-----------------------------------------------------------------------------------------------------
Total costs 8,991
Revenue available to recover transition costs (5,117)
-----------------------------------------------------------------------------------------------------
TCBA undercollections $ 3,874
-----------------------------------------------------------------------------------------------------
Unless the regulatory and legislative actions required to implement the MOU, or other 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 $996
million in TCBA undercollections was charged to earnings as of March 31, 2001. In its interim rate stabilization
decision of March 27, 2001, the CPUC denied a December motion by SCE to end the rate freeze, and stated that it
Page 54
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 Proceeding.
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 class action securities lawsuit was filed in federal district court in Los Angeles against SCE
and Edison International. As amended in December 2000 and March 2001, the lawsuit alleges that SCE and Edison
International are engaging in fraud by over-reporting and improperly 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 beginning June 1, 2000, and continuing until such time as TRA-related undercollections
are recorded as a loss on SCE's income statement. The response to the second amended complaint was due April 2,
2001. As indicated below in the March 15, 2001, lawsuit discussion, the Court has agreed that the date for the
response to the second amended complaint may be deferred. 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. A consolidated complaint is expected to be filed by
mid-May 2001. Edison International and SCE must respond within 30 days of receipt of the consolidated complaint.
In addition to the two lawsuits filed against SCE and discussed above, as of May 11, 2001, 25 lawsuits have been
filed against SCE by QFs. The lawsuits have been filed by various parties, including geothermal or wind energy
suppliers or owners of cogeneration projects. The lawsuits are seeking payments of at least $833 million for
energy and capacity supplied to SCE under QF contracts, and in some cases additional damages as well. Many of
Page 55
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. On April 5, 2001, SCE submitted a petition requesting the coordination before a
single judge of those QF lawsuits then pending in California state court. A state court coordination judge has
been assigned and SCE's motion to coordinate is pending. SCE is also taking steps to coordinate the QF cases on
file in federal court. SCE cannot predict the outcome of any of these matters.
Rate Stabilization Proceeding
-----------------------------
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 CPUC must recognize
that the statutory rate freeze is now over 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. Hearings were held in late December 2000.
On January 4, 2001, the CPUC issued an interim decision that authorized SCE to establish an interim surcharge of
1(cent)per kWh for 90 days, subject to refund (see additional discussion below). The revenue from the surcharge is
being tracked through a balancing account and applied to ongoing power procurement costs. The surcharge resulted
in rate increases, on average, of approximately 7% to 25%, depending on the class of customer. As noted in the
decision, the 90-day period allowed independent auditors engaged by the CPUC to perform a comprehensive review of
SCE's financial position, as well as that of Edison International and other affiliates.
On January 29, 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 (originally proposed on March 15, 2001). The order reopens past CPUC decisions
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. An assigned commissioner's ruling on March 29, 2001, required SCE to respond
within 10 days to document requests and questions that are substantially identical to those included in the March
15 proposed order instituting investigation. 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. 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.
In its interim rate stabilization order adopted on March 27, 2001, the CPUC granted SCE a rate increase in the
form of a 3(cent)-per-kWh surcharge applied only to electric power procurement costs, effective immediately, and
affirmed that the 1(cent)interim surcharge granted on January 4, 2001, is now permanent. Although the 3(cent)-increase
was authorized immediately, the surcharge will not be collected in rates until the CPUC establishes an
appropriate rate design, which is not expected to occur until early June 2001. The CPUC also ordered that the
3(cent)-surcharge be added to the rate paid to the CDWR pursuant to the interim CDWR-related decision (see CDWR Power
Purchases).
Page 56
Also, in the interim 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 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 it 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 proceeding. If the CPUC does not
modify this decision in a manner consistent with the MOU, SCE intends to challenge this decision through all
appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 27, 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
aggravated SCE's cash flow and liquidity problems. Additionally, the CPUC expressed the view 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 implement the MOU, 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.
The implementation of the MOU requires various regulatory and legislative actions to be taken in the future.
Unless those actions or other 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 is
unable to conclude that its $2.9 billion TCBA undercollection (as redefined in the March 27 decisions) and $1.3
billion (book value) of its generation-related regulatory assets and liabilities 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 require that the balances in the accounts be written off as a charge to earnings as of
December 31, 2000 (see Earnings).
Page 57
As discussed below, an MOU has been negotiated with representatives of the Governor as a step to resolving the
energy crisis. The regulatory and legislative actions set forth in the MOU, if implemented, are expected to
result in a rate-making mechanism that would make recovery of these regulatory assets probable. If and when
those actions, or other actions that make such recovery probable are taken, and the necessary rate-making
mechanism is adopted, 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
legislation, 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.
Page 58
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 or
another state agency for the provision of power to the state at cost-based rates for 10 years from a power
project currently under development. Edison Mission Energy will use all commercially reasonable efforts to
place the first phase of the project into service before the end of summer 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 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 executed by August 15, 2001, or if the CPUC does
not adopt required implementing decisions within 60 days after the MOU was signed, or if certain other adverse
changes occur. SCE cannot provide assurance that all the required legislation will be enacted, regulatory
actions taken, and definitive agreements executed before the applicable deadlines. The CPUC has stated it will
expeditiously review those provisions of the MOU that require resolution. SCE and the Governor have been working
diligently to have the MOU supported by the legislature. However, no formal action has been taken by either the
CPUC or the legislature.
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
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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 and expedited action seeking reconsideration 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. On April 6, 2001, the FERC issued an
order providing guidance to the PX, which should reduce SCE's energy costs owed to the PX for the month of
January 2001.
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. 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 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, SCE filed an emergency petition in the federal Court of Appeals challenging the FERC order and
seeking a writ of mandamus requiring the FERC to immediately establish cost-based wholesale rates. On January 5,
2001, the court denied SCE's petition. The effect of the denial is to leave in place the FERC's market controls
that have allowed wholesale prices to climb to current levels. SCE's petition for rehearing remains pending.
SCE cannot predict what action the FERC may take. SCE is considering the possibility of judicial appeals and
other actions.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69 million or submit
cost-of-service information to the FERC to justify their prices above $273/MWh during ISO Stage 3 emergencies in
January 2001. SCE will oppose the order as inadequate, particularly because the FERC is unwilling to exercise
any control over the sellers' exercise of market power during periods other than Stage 3 emergencies. On March
16, 2001, the FERC ordered six wholesale sellers of energy to refund an additional $55 million or submit
cost-of-service information to the FERC to justify their prices above $430/MWh during ISO Stage 3 emergencies in
February 2001. A Stage 3 emergency refers to 1.5% or less in reserve power, which could trigger rotating
blackouts in some neighborhoods.
On April 25, 2001, the FERC issued an order providing for cost-based 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. The order is in effect for one year.
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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 $74 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 March 31, 2001,
were $17 million.
Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or
financial position. There can be no assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will not require material revisions to such
estimates.
The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide. Power companies
receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to
have excess allowances under Phase II of the Clean Air Act (2000 and later). A study was undertaken to determine
the specific impact of air contaminant emissions from the Mohave Generating Station on visibility in Grand Canyon
National Park. The final report on this study, which was issued in March 1999, found negligible correlation
between measured Mohave station tracer concentrations and visibility impairment. The absence of any obvious
relationship cannot rule out Mohave station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. In June 1999, the Environmental Protection
Agency (EPA) issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at
the Grand Canyon. SCE filed comments on the proposed rulemaking in November 1999. In 1998, several
environmental groups filed suit against the co-owners of the Mohave station regarding alleged violations of
emissions limits. In order to accelerate resolution of key environmental issues regarding the plant, the parties
filed, in concurrence with SCE and the other station owners, a consent decree, which was approved by the court in
December 1999. In a letter to SCE, the EPA has expressed its belief that the controls provided in the consent
decree will likely resolve the potential Clean Air Act visibility concerns. The EPA is considering incorporating
the decree into the visibility provisions of its Federal Implementation Plan for Nevada.
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SCE's 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
On February 3, 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. SCE expects that Unit 3 will return to service at the end of June 2001. SCE anticipates
that its lost revenue under the currently effective San Onofre rate-recovery plan (discussed in the Generation
and Power Procurement section of Regulatory Environment) will be approximately $110 million.
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 Standard
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 March 31, 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.
Page 62
PART II OTHER INFORMATION
Item 1. Legal Proceedings
San Onofre Personal Injury 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 is actively involved in three lawsuits claiming personal injuries
allegedly resulting from exposure to radiation at San Onofre. In addition, a fourth lawsuit claiming personal
injuries from exposure to radiation at San Onofre has recently been filed and served on SCE.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District Court for the Southern District
of California. Plaintiffs also named Combustion Engineering. The trial in this case resulted in a jury verdict
for both defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed an appeal of the trial
court's judgment to the Ninth Circuit Court of Appeal. Briefing on the appeal was completed in January 1999,
oral argument took place on February 10, 2000, and the matter was taken under submission. On July 20, 2000, the
Ninth Circuit Court of Appeals issued an opinion reversing the District Court judgment and ordering a retrial as
to both defendants. On August 10, 2000, SCE filed a petition for rehearing with the Ninth Circuit Court of
Appeals. On January 2, 2001, the Court granted SCE's rehearing petition as to certain issues and ordered further
briefing on those rehearing issues within 30 days. This further briefing was filed on February 1, 2001. On
February 20, 2001, the Court issued an order setting oral argument on the rehearing issues which took place on
April 26, 2001. The matter is now under submission and a decision on the rehearing is not expected for at least
several weeks.
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. This is the fourth lawsuit claiming personal injuries from exposure to radiation at San Onofre
that SCE is actively involved in.
Shareholder Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, these purported class actions both involve
securities fraud claims arising from alleged improper accounting by Edison International and SCE of
undercollections in SCE's TRA.
On October 30, 2000, a purported class action lawsuit (the "Stubblefield Action") was filed in federal district
court in Los Angeles against SCE and Edison International. On December 28, 2000, plaintiffs, without requiring a
response to the original complaint, filed a first amended complaint. In February 2001, the Court approved a
stipulation of the parties providing that, in lieu of a motion to dismiss directed to the first amended
complaint, plaintiffs would voluntarily file a second amended complaint. Pursuant to this stipulation, on
March 5, 2001, plaintiffs filed a second amended complaint. The second amended complaint alleges that the
companies are engaging in securities fraud by over-reporting income and improperly accounting for the TRA
undercollections. The second amended complaint purports to be filed on behalf of a class of persons who
purchased Edison International common stock beginning June 1, 2000, and continuing until such time as TRA-related
undercollections are recorded as a loss on SCE's income statements. The second amended complaint seeks
compensatory damages caused by the alleged fraud as well as punitive damages. The response to the second amended
complaint was due April 2, 2001. As discussed below, plaintiff's counsel has agreed with counsel for Edison
International and SCE that the date for Edison International and SCE to respond to the second amended complaint
may be deferred.
Page 63
On March 15, 2001, a purported class action lawsuit (the "King Action") was filed in federal district court in
Los Angeles, California, 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
overreported income and improperly accounted for the TRA undercollections. The complaint purports to be 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. Plaintiffs seek damages, in an unstated amount, in connection with their purchase
of securities during the class period.
The Court has granted a motion to consolidate this action with the Stubblefield Action, and has ordered
plaintiffs to file a consolidated complaint by mid-May 2001. The Court has taken under consideration a motion to
have the named plaintiffs in both cases be appointed "lead plaintiffs" in the consolidated matter. The Court has
agreed that defendants need not respond to the separate Stubblefield and King Action complaints and, instead,
must respond to the consolidated complaint within thirty days of the time that it is filed and served.
Qualifying Facilities Litigation
As previously reported in Part 1, Item 3 of SCE's 2000 Form 10-K, SCE is involved in a number of legal actions
brought by various QFs alleging SCE's failure to timely pay for power deliveries made beginning in November
2000. The lawsuits, and the additional legal actions listed below, have been filed by various QF parties
including gas-fired QFs, geothermal or wind energy QFs, and owners of cogeneration projects. The lawsuits, in
aggregate, are seeking payments of more than $833,000,000 for energy and capacity supplied to SCE under QF
contracts, and in some cases 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. SCE is seeking
coordination of all of the QF-related lawsuits that have commenced in various California courts.
On April 5, 2001, SCE submitted to the Chairperson of the California Judicial Counsel a petition requesting the
coordination before a single judge of those QF lawsuits then-pending in California state court. A state court
Coordination Judge has been assigned, and SCE's Motion to Coordinate is pending. In addition, SCE is taking
steps to coordinate those QF cases on file in federal court.
Writs of attachment have been granted in four cases (Beowawa Power, L.L.C., Heber Geothermal Company, IMC
Chemicals, Inc., and City of Long Beach) in the approximate amounts of $20,000,000, $28,000,000, $7,500,000, and
$9,000,000 respectively, contingent on the posting of bonds. As of this date, SCE has not been notified that the
bonds have been posted.
In addition to the cases previously referenced in SCE's 2000 Form 10-K, the following legal proceedings,
identified by principal party, filing date, and court jurisdiction, have been brought against SCE:
Principal Party Date Filed Court Jurisdiction
--------------- ---------- ------------------
Oak Creek Wind Power, Inc. April 16, 2001 Kern County Superior Court, Central
District
Willamette Industries, Inc. April 17, 2001 Ventura County Superior Court
Berry Petroleum Company May 2, 2001 Los Angeles County Superior Court,
Central District
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Ace Cogeneration Company May 1, 2001 Los Angeles County Superior Court,
Central District
Cabazon Power Partners LLC May 2, 2001 Los Angeles County Superior Court,
Central District
Black Hills Ontario, LLC May 7, 2001 San Bernardino County Superior Court,
Rancho Cucamonga District
U.S. Borax Inc. f/k/a United States May 8, 2001 Kern County Superior Court
Borax and Chemical Corporation
Luz Solar Partners LTD. May 8, 2001 Sacramento County Superior Court
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 17, 2000 (File No. 1-2313, filed as Exhibit 3.3 to Form 10-K for the period ended
December 31, 1999)*
10.1 Executive Retirement Plan Amendment 2001-1
10.2 Restatement of Terms of 2000 basic long-term incentive awards under the Equity Compensation
Plan or the 2000 Equity Plan
10.3 Terms of 2001 basic long-term incentive awards under the Equity Compensation Plan or the 2000
Equity Plan
10.4 Terms of 2001 special long-term incentive awards under the Equity Compensation Plan or the 2000
Equity Plan
10.5 Terms of 2001 retention incentives under the Equity Compensation Plan
10.6 Terms of Executive Severance Plan as adopted effective January 1, 2001
23. Consent of Independent Public Accountants
Page 65
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
January 15, 2001 January 16, 2001 5
January 18, 2001 January 18, 2001 5
February 1, 2001 February 5, 2001 5
February 12, 2001 February 16, 2001 5
March 20, 2001 March 22, 2001 5
------------------
* Incorporated by reference pursuant to Rule 12b-32.
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
May 14, 2001
