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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 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4137452
(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) 302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days.
Yes X No ___
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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
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Common Stock, no par value 325,811,206
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EDISON INTERNATIONAL
INDEX
Page
No.
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Part I.Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income (Loss) - Three Months
Ended March 31, 2001, and 2000 1
Consolidated Statements of Comprehensive Income (Loss) -
Three Months Ended March 31, 2001, and 2000 1
Consolidated Balance Sheets - March 31, 2001,
and December 31, 2000 2
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2001, and 2000 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 20
Part II. Other Information:
Item 1. Legal Proceedings 49
Item 6. Exhibits and Reports on Form 8-K 52
EDISON INTERNATIONAL
PART I - FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
In millions, except per-share amounts
3 Months Ended
March 31,
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2001 2000
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(Unaudited)
Electric utility revenue $ 1,511 $ 1,830
Nonutility power generation 780 751
Financial services and other 171 142
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Total operating revenue 2,462 2,723
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Fuel 329 331
Purchased power 1,724 504
Provisions for regulatory adjustment clauses - net (29) 103
Other operation and maintenance 828 728
Depreciation, decommissioning and amortization 260 494
Property and other taxes 30 40
Net gain on sale of utility plant (1) (6)
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Total operating expenses 3,141 2,194
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Operating income (loss) (679) 529
Interest and dividend income 49 25
Other nonoperating income 11 36
Interest expense - net of amounts capitalized (408) (326)
Other nonoperating deductions (1) (34)
Dividends on preferred securities (23) (25)
Dividends on utility preferred stock (6) (6)
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Income (loss) before taxes (1,057) 199
Income taxes (440) 89
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Net income (loss) $ (617) $ 110
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Weighted-average shares of common stock outstanding 326 345
Basic earnings (loss) per share $ (1.89) $ 0.32
Weighted average shares, including effect of dilutive securities 326 346
Diluted earnings (loss) per share $ (1.89) $ 0.32
Dividends declared per common share -- $ 0.28
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In millions
3 Months Ended
March 31,
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2001 2000
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(Unaudited)
Net income (loss) $ (617) $ 110
Other comprehensive income, net of tax:
Cumulative translation adjustments (102) (47)
Unrealized gain (loss) on securities - net -- (7)
Cumulative effect of change in accounting for derivatives 167 --
Unrealized loss on cash flow hedges (405) --
Reclassification adjustment for losses on derivatives
included in net income (loss) (28) --
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Comprehensive income (loss) $ (985) $ 56
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In millions
March 31, December 31,
2001 2000
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(Unaudited)
ASSETS
Cash and equivalents $ 2,934 $ 1,973
Receivables, less allowances of $47 and $40 for uncollectible
accounts at respective dates 1,070 1,099
Accrued unbilled revenue 393 377
Fuel inventory 220 220
Materials and supplies, at average cost 208 210
Accumulated deferred income taxes - net 1,331 1,350
Trading and price risk management assets 221 252
Prepayments and other current assets 162 185
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Total current assets 6,539 5,666
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Nonutility property - less accumulated provision for
depreciation of $810 and $774 at respective dates 9,724 10,084
Nuclear decommissioning trusts 2,372 2,505
Investments in partnerships and unconsolidated subsidiaries 2,854 2,700
Investments in leveraged leases 2,380 2,345
Other investments 87 92
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Total investments and other assets 17,417 17,726
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Utility plant, at original cost
Transmission and distribution 13,247 13,129
Generation 1,749 1,745
Accumulated provision for depreciation and decommissioning (7,794) (7,834)
Construction work in progress 635 636
Nuclear fuel at amortized cost 134 143
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Total utility plant 7,971 7,819
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Regulatory assets - net 2,759 2,390
Other deferred charges 1,578 1,499
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Total deferred charges 4,337 3,889
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Total assets $ 36,264 $ 35,100
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In millions, except share amounts
March 31, December 31,
2001 2000
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current portion of long-term debt $ 2,515 $ 2,260
Short-term debt 4,339 3,920
Accounts payable 3,069 1,228
Accrued taxes 399 593
Accrued interest 293 232
Dividends payable 13 12
Regulatory liabilities - net 251 195
Trading and risk management liabilities 355 282
Deferred unbilled revenue 278 250
Other current liabilities 1,717 1,828
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Total current liabilities 13,229 10,800
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Long-term debt 11,792 12,150
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Accumulated deferred income taxes - net 5,184 5,328
Accumulated deferred investment tax credits 174 183
Customer advances and other deferred credits 1,922 1,692
Power-purchase contracts 439 467
Accumulated provision for pension and benefits 484 438
Other long-term liabilities 93 94
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Total deferred credits and other liabilities 8,296 8,202
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Commitments and contingencies (Notes 1, 2 and 4)
Minority interest 17 18
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Preferred stock of utility:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 256 256
Company-obligated mandatorily redeemable securities of subsidiaries
holding solely parent company debentures 949 949
Other preferred securities 161 176
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Total preferred securities of subsidiaries 1,495 1,510
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Common stock (325,811,206 shares at each date) 1,961 1,960
Accumulated other comprehensive income (loss) (508) (139)
Retained earnings (deficit) (18) 599
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Total common shareholders' equity 1,435 2,420
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Total liabilities and shareholders' equity $ 36,264 $ 35,100
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In millions
3 Months Ended
March 31,
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2001 2000
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(Unaudited)
Cash flows from operating activities:
Net income (loss) $ (617) $ 110
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation, decommissioning and amortization 260 494
Other amortization 20 43
Deferred income taxes and investment tax credits (231) 4
Equity in income from partnerships and unconsolidated
subsidiaries (85) (37)
Income from leveraged leases (32) (50)
Regulatory balancing accounts - long-term 69 (92)
Net gain on sale of marketable securities -- (15)
Other assets (256) (26)
Other liabilities 4 (70)
Changes in working capital:
Receivables and accrued unbilled revenue (3) (1)
Regulatory balancing accounts - short term 56 120
Fuel inventory, materials and supplies (6) 8
Prepayments and other current assets 131 (4)
Accrued interest and taxes (132) 68
Accounts payable and other current liabilities 1,682 (16)
Distributions from partnerships and unconsolidated entities 34 39
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Net cash provided by operating activities 894 575
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Cash flows from financing activities:
Long-term debt issued 1,010 2,308
Long-term debt repaid (1,210) (2,093)
Bonds repurchased and funds held in trust (156) --
Rate reduction notes repaid (63) (61)
Common stock repurchased -- (147)
Nuclear fuel financing - net (9) (14)
Short-term debt financing - net 720 352
Dividends paid -- (94)
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Net cash provided by financing activities 292 251
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Cash flows from investing activities:
Additions to property and plant (259) (331)
Proceeds from sale of nonutility property 23 --
Funding of nuclear decommissioning trusts -- (23)
Investments in partnerships and unconsolidated subsidiaries 61 (107)
Investment in leveraged leases -- 13
Proceeds from sales of marketable securities -- 17
Investments in other assets 7 21
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Net cash used by investing activities (168) (410)
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Effect of exchange rate changes on cash (57) (6)
Net increase in cash and equivalents 961 410
Cash and equivalents, beginning of period 1,973 507
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Cash and equivalents, end of period $ 2,934 $ 917
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The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments have been made that are necessary to present a fair statement of
the financial position and results of operations for the periods covered by this report.
Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated
Financial Statements" included in its 2000 Annual Report on Form 10-K filed with the Securities and Exchange
Commission. Edison International follows the same accounting policies for interim reporting purposes, with the
exception of the change in accounting for derivatives. This quarterly report should be read in conjunction with
Edison International's 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Certain prior-period amounts were reclassified to conform to the March 31, 2001, financial statement presentation.
Note 1. Liquidity Crisis
Edison International's liquidity is primarily affected by debt maturities, dividend payments, capital
expenditures and Southern California Edison Company's (SCE) power purchases. Capital resources include cash from
operations and external financings.
The increasing undercollection in the Transition Revenue Account (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 California Power Exchange (PX) or the Independent System Operator (ISO); (2) $1.3 billion to power producers
that are qualifying facilities (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 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 2. 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 Memorandum of Understanding (MOU) is implemented (as further
discussed in Note 2), it is expected to allow SCE to recover its undercollected costs and help to restore SCE's
creditworthiness, which would allow SCE to pay all of its past due obligations.
On March 27, 2001, the California Public Utilities Commission (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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 2). 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. As of April 30, 2001, SCE's preferred stock
dividends in arrears were $6 million. 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 on SCE's preferred stock
remain unpaid, SCE cannot pay any dividends on its common stock.
In addition to the above, SCE has implemented cost-cutting measures which, together with previously announced
actions, such as freezing new hires, postponing certain capital expenditures and ceasing new charitable
contributions, are aimed at reducing general operating costs. SCE's current cost-cutting measures are intended
to allow it to continue to operate while efforts to reach a regulatory solution, involving both state and federal
authorities, are underway. Additional actions by SCE may be necessary if the energy and liquidity crisis is not
resolved in the near future.
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.
The parent company and the nonutility affiliates believe that their corporate financing plans will be successful
in meeting cash requirements in 2001.
Note 2. Electric Utility 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 Nuclear
Generating Station Units 2 and 3 and the Palo Verde Nuclear Generating Station 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).
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
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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
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Total transition costs 8,991
Revenue available to recover transition costs (5,117)
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TCBA undercollections $ 3,874
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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 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Wholesale Electricity Markets
In October 2000, SCE filed a joint petition urging the Federal Energy Regulatory Commission (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 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 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
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o Edison Mission Energy (EME) 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.
EME 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 of California, 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. 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 increased to 10.277(cent)per kWh for electricity delivered after March 27, 2001,
due to the 3(cent)surcharge discussed in Rate Stabilization Proceeding), for electricity delivered by the CDWR to
SCE's retail customers after February 1, 2001, until more specific rates are calculated. The CPUC ordered SCE to
pay the CDWR within 45 days after the CDWR supplies power to retail customers, subject to penalties for each day
the payment is late. 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.
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 1) 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 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 credit worthiness 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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 3. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), an
unregulated power generation segment (EME), and a capital and financial services provider segment (Edison
Capital).
Segment information for the three months ended March 31, 2001, and 2000, was:
3 Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------
In millions 2001 2000
- ---------------------------------------------------------------------------------------------------
Operating Revenue:
Electric utility $ 1,511 $ 1,830
Unregulated power generation 780 751
Capital & financial services 42 66
Corporate and other* 129 76
- ---------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,462 $ 2,723
- ---------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ (598) $ 113
Unregulated power generation 8 (12)
Capital & financial services 12 28
Corporate and other(2) (39) (19)
- ---------------------------------------------------------------------------------------------------
Consolidated Edison International $ (617) $ 110
- ---------------------------------------------------------------------------------------------------
(1) Net income (loss) available for common stock.
(2) Includes amounts from nonutility subsidiaries not significant as a reportable segment.
Total segment assets as March 31, 2001, were: electric utility, $18 billion; unregulated power generation,
$14 billion; capital and financial services, $4 billion.
Note 4. Contingencies
In addition to the matters disclosed in these notes, Edison International is involved in legal, tax and
regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary
course of business. Edison International believes the outcome of these proceedings will not materially affect
its results of operations or liquidity.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
Edison International 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.
Edison International records its environmental liabilities when site assessments and/or remedial actions are
probable and a range of reasonably likely cleanup costs can be estimated. Edison International 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, Edison International records
the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted
amounts).
Edison International's recorded estimated minimum liability to remediate its 44 identified sites is $116
million. The ultimate costs to clean up Edison International'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. Edison International 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 Edison
International 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
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
through customer rates; and 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.
Edison International'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 Edison
International 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.
Edison International 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-month period ended March 31, 2001 were $17 million.
Based on currently available information, Edison International 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, Edison International believes that costs ultimately recorded will not materially
affect its results of operations or financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the identification of new sites, will not
require material revisions to such estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of the
San Onofre and Palo Verde nuclear plants 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 mutual
insurance companies 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 Department of Energy 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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Paiton Project
A wholly owned subsidiary of EME (Paiton Energy) owns a 40% interest and has a $499 million investment (at
March 31, 2001) in the Paiton project, a 1,230-MW coal-fired power plant in Indonesia. As discussed more fully in
Edison International's 2000 Annual Report on Form 10-K, Paiton Energy is continuing negotiations on a long-term
restructuring of the revenue schedule under a long-term power purchase agreement with the state-owned electricity
company. Paiton Energy and the state-owned electricity company have agreed on a Phase I Agreement for the period
from January 1, 2001, through June 30, 2001. This agreement provides for fixed monthly payments totaling $108
million over its six-month duration and for the payment for energy delivered to the state-owned electricity
company from the plant during this period. To date, the state-owned electricity company has made fixed payments
due under the Phase I Agreement totaling $52 million as scheduled. Paiton Energy and the state-owned electricity
company intended to complete the negotiations of the future phases of a new long-term revenue schedule during the
six-month duration of the Phase I Agreement. Paiton Energy has received lender approval of the Phase I Agreement
and has also entered into a lender interim agreement under which lenders have agreed to interest-only payments
and to deferral of principal payments while Paiton Energy and the state-owned electricity company seek a
long-term restructuring. The lenders have agreed to extend that agreement through December 31, 2001. Based on
the current status of negotiations between Paiton Energy and the state-owned electricity company, it is not
likely that a long-term restructuring of the revenue schedule will be completed by June 30, 2001. The Paiton
project is continuing to generate electricity to meet the power demand in the region. Paiton Energy believes
that the state-owned electricity company will continue to agree to make payments for electricity on an interim
basis beyond June 30, 2001, while negotiations regarding long-term restructuring of the revenue schedule
continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that
negotiations on the long-term restructuring of the revenue schedule will be successful.
Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new
long-term revenue schedule could require a renegotiation of the Paiton project's debt agreements. The impact of
any such renegotiations with the state-owned electricity company, the Indonesian government or the project's
creditors on EME's expected return on its investment in the Paiton project is uncertain at this time; however,
EME believes that it will ultimately recover its investment in the project.
Note 5. Derivative Instruments and Hedging Activities
Effective January 1, 2001, Edison International adopted a new accounting standard for derivative instruments and
hedging activities. The standard establishes accounting and reporting standards requiring that every derivative
instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The
standard requires that changes in the derivative's fair value be recognized currently in earnings unless specific
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of
the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities
or firm commitments through earnings or recognized in other comprehensive income until the hedged item is
recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized
in earnings.
Effective January 1, 2001, all derivatives were recorded at fair value unless the derivatives qualify for the
normal sales and purchases exception. This exception applies to physical sales and purchases of power or fuel
where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to
the contracted prices and the documentation requirements of the new accounting standard are met.
The majority of EME's physical long-term power and fuel contracts, and the similar business activities of EME's
affiliates, qualify under this exception. EME did not use this exception for forward sales contracts from the
Homer City plant due to net settlement procedures with counterparties.
The majority of EME's remaining risk management activities, including forward sales contracts from the Homer City
plant, qualify for treatment under the new accounting standard as cash flow hedges with appropriate adjustments
made to other comprehensive income. The hedge agreement EME has with the State Electricity Commission of
Victoria for electricity prices from the Loy Yang B project in Australia qualifies as a cash flow hedge. This
contract could not qualify under the normal sales and purchases exception because financial settlement of the
contract occurs without physical delivery. Some of EME's derivatives did not qualify for either the normal sales
and purchases exception or as cash flow hedges. These derivatives are recorded at fair value with subsequent
changes in fair value recorded through the income statement. The majority of EME's risk management activities
related to the Ferrybridge and Fiddler's Ferry power plants in the United Kingdom and fuel contracts related to
the Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash
flow hedges. In both these situations, EME could not conclude, based on information available at March 31, 2001,
that the timing of generation from these power plants met the probable requirement for a specific forecasted
transaction under the new accounting standard. Accordingly, the majority of these contracts are recorded at fair
value, with subsequent changes in fair value reflected in nonutility power generation revenue in the consolidated
income statement.
As a result of the adoption of the new standard, Edison International expects its quarterly earnings from its EME
subsidiary will be more volatile than earnings reported under the prior accounting policy. In the quarter ended
March 31, 2001, EME has recorded a net loss of $7 million (after tax) as the change in the fair value of
derivatives required under the new accounting standard that previously qualified for hedge accounting. EME
recorded a $6 million (after tax) increase to net income as a cumulative change in the accounting for derivatives
during the quarter ended March 31, 2001. In addition, EME recorded a $230 million (after tax) unrealized holding
loss upon adoption of a change in accounting principle reflected in accumulated other comprehensive income in the
consolidated balance sheet. EME has recorded a net gain of $155,000 representing the amount of cash flow hedges'
ineffectiveness during the quarter ended March 31, 2001, reflected in nonutility power generation revenue in the
consolidated income statement.
The unrealized losses on cash flow hedges at March 31, 2001, included forward sales contracts from EME's Homer
City plant that did not meet the normal sales and purchases exception under the new accounting standard due to
EME's net settlement procedures with counterparties. In addition, the hedge agreement EME has with the State
Electricity Commission of Victoria for electricity prices from the Loy Yang B project in Australia qualifies as a
cash flow hedge. This contract also could not qualify under the normal sales and purchases exception because
financial settlement of the contract occurs without physical delivery. Approximately 95% of EME's accumulated
other comprehensive loss at March 31, 2001, related to unrealized losses on cash flow hedges resulting from these
contracts. These losses arise from current forecasts of future electricity prices in these markets greater than
Page 18
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EME's contract prices. Although the contract prices are below the current market prices, EME believes that
prices included in its contracts mitigate price risk associated with future changes in market prices and are at
prices that meet EME's profit objectives. Assuming these contracts continue to qualify as cash flow hedges,
future changes in the forecast of market prices for contract volumes included in these agreements will increase
or decrease EME's other comprehensive income without affecting EME's net income.
As the positions are realized, approximately $33 million (after tax) of the net unrealized losses on cash flow
hedges will be reclassified into earnings during the remainder of 2001. Management expects that these net
unrealized losses will be offset when the hedged items are recognized in earnings. The maximum period over which
a cash flow hedge is designated, excluding those forecasted transactions related to the payment of variable
interest on existing financial instruments is 16 years.
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. Edison International'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.
Note 6. 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 and contracts with other
utilities and QFs. Purchased power detail is provided below:
3 Months Ended
March 31,
- --------------------------------------------------------------------------------------------------------
In millions 2001 2000
- --------------------------------------------------------------------------------------------------------
PX/ISO:
Purchases $ 1,081 $ 517
Generation sales (705) (441)
- --------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net 376 76
Purchased power - bilateral contracts 52 --
Purchased power - interutility/QF contracts 1,296 428
- --------------------------------------------------------------------------------------------------------
Total $ 1,724 $ 504
- --------------------------------------------------------------------------------------------------------
Page 19
EDISON INTERNATIONAL
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, Edison International, 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. Neither Edison International nor SCE can 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, Edison International's financial results for the year ended
December 31, 2000, included an after-tax charge at SCE 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
Page 20
transition costs were charged to earnings. This has resulted in further material declines in reported common
shareholders' 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, 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
First Quarter 2001 vs. First Quarter 2000
Earnings
Edison International recorded a loss of $1.89 per share. The loss reflects $661 million (after tax), or $2.03
per share, of SCE's 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. Excluding SCE's undercollected transition costs ($2.03 per share), Edison International's
basic earnings per share were 14(cent)for first quarter 2001, compared to 32(cent)for first quarter 2000. Excluding the
undercollected transition costs, SCE's first quarter 2001 earnings were 19(cent), compared with 33(cent)for the same
period last year. The 14(cent)quarterly decrease for SCE was primarily due to higher interest expense resulting from
its deteriorated financial condition 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), partially offset by the effects of Edison International's share
repurchase program. Edison Mission Energy (EME) earned 3(cent)for the quarter, compared to a loss of 3(cent)for the
prior-year period. The 6(cent)increase was primarily due to increased generation and higher energy prices for its
domestic projects, partially offset by decreased earnings at its United Kingdom projects due to lower pool
prices. Edison Capital's earnings were 4(cent), compared with 11(cent)for the year-earlier period. The 7(cent)decrease was
primarily due to lower earnings from leveraged lease transactions. Edison Enterprises and Edison International
(parent company) incurred losses of 12(cent)in first quarter 2001, compared to a 9(cent)loss in first quarter 2000,
primarily due to a gain on sale of marketable securities in first quarter 2000 and higher interest expense at the
parent company.
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).
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 TCBA undercollections, Edison
International expects its 2001 earnings to be negatively affected by the February 2001 fire and resulting outage
at San Onofre Unit 3.
Page 21
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 being assessed to noncompliant customers after October 1, 2000, until a reevaluation of
the operation of the interruptible programs can be completed.
Electric utility revenue decreased for the three months ended March 31, 2001, compared to the year-earlier
period. The quarterly decrease is 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 is 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.
More than 92% of electric utility 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.
Nonutility power generation revenue increased in 2001, primarily due to increases at EME related to its Homer
City and Illinois plants, its cogeneration projects and its oil and gas investments, partially offset by
decreases at its Ferrybridge, Fiddler's Ferry and First Hydro plants.
Due to warmer weather during the summer months, EME's nonutility power generation revenue related to its Homer
City plant and the Illinois plants is usually higher during the third quarter of each year. Higher summer
pricing for EME's energy projects located on the western coast of the United States, generally causes materially
higher third quarter nonutility power generation revenue than other quarters of the year. EME's First Hydro,
Ferrybridge and Fiddler's Ferry plants are expected to contribute more to nonutility power generation revenue
during the winter months.
Financial services and other revenue increased in 2001, mostly due to increases at two of Edison International's
nonutility subsidiaries. Beginning in January 2001, an Edison International nonutility subsidiary began
providing operation and maintenance services to the independent power companies who now own the generation
stations SCE sold in 1998. From 1998 through December 2000, SCE was providing these services. The increases
resulted from the selling of real estate and providing these operating and maintenance services. These increases
were partially offset by a decrease at Edison Capital related to lower revenue from leveraged lease transactions.
Operating Expenses
Purchased-power expense increased significantly for the three months ended March 31, 2001, compared to the same
period in 2000. The increase was 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
Page 22
qualifying facilities (QFs) and interutility contracts. See Purchased Power table in Note 6 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. 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 QFs at CPUC-mandated prices even though energy and capacity prices under many of these contracts are
generally higher than other sources. Purchased-power expense related to QFs increased for the three months ended
March 31, 2001, compared to the year-earlier period. The increase was 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.
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 and increased undercollections related to the administration of energy conservation programs
and other public benefit programs.
Other operation and maintenance expense increased primarily due to: increased plant operating expenses at EME's
Illinois plants; increased expenses at a nonutility subsidiary related to the sale of real estate; and an
increase at SCE mostly related to must-run reliability services.
Depreciation, decommissioning and amortization expense decreased significantly in 2001, primarily due to a
decrease in SCE's amortization expense, as well as a decrease at EME related to the sale-leaseback transactions
with third parties for power facilities in Illinois in August 2000. 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.
Other Income and Deductions
Interest and dividend income increased in 2001, primarily due to increases at Edison International, SCE and
Edison Capital, resulting from higher cash balances as they conserve cash due to their liquidity issues, and an
increase at EME related to foreign exchange gains on intercompany loans. SCE's interest income also increased
due to interest earned on undercollections in its 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.
Other nonoperating income decreased primarily due to lower CPUC-approved shareholder incentives at SCE resulting
from fewer QF contract restructurings and the gain on sale of an equity investment at Edison International's
insurance subsidiary in first quarter 2000.
Interest expense - net of amounts capitalized increased in 2001, reflecting additional long-term debt at SCE and
Edison Capital, and higher short-term debt balances at both SCE and the parent company. Interest expense
resulting from balancing account overcollections at SCE also contributed to the increase in 2001. Decreases in
interest expense at EME reflecting payments on long-term debt and favorable changes in foreign exchange rates
partially offset the increases in interest expense discussed above.
Other nonoperating deductions decreased due to lower accruals at SCE for regulatory matters in 2001.
Page 23
Income Taxes
Income taxes decreased in 2001, primarily due to a $497 million income tax benefit related to losses resulting
from SCE's undercollected transition costs during first quarter 2001 and lower pre-tax income.
Financial Condition
Edison International's liquidity is primarily affected by debt maturities, access to capital markets, dividend
payments, capital expenditures, investments in partnerships and unconsolidated subsidiaries, and SCE's power
purchases. Capital resources include cash from operations and external financings. As a result of SCE's lack of
creditworthiness (further discussed in Liquidity Issues), at March 31, 2001, the fair market value of
approximately $1.1 billion of Edison International's short-term debt was approximately 75% of its carrying value
and the fair market value of its long-term debt was approximately 90% of its carrying value.
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 Issues
SCE
- ---
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
Page 24
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 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 and Edison International's Board of
Directors did not declare a common stock dividend to Edison International's shareholders. 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.
Page 25
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.
EME
- ---
EME has three corporate credit facilities that are scheduled to expire in 2001, two on May 29 (total amount of
$850 million) and one in October ($425 million). As of April 30, 2001, EME has borrowed or issued letters of
credit aggregating $1.2 billion under these credit facilities and has an unused capacity of approximately
$52 million. EME is in the process of amending the credit facilities expiring in May to extend them to
October 10, 2001. EME plans to refinance its corporate credit facilities through modifications to its existing
credit facilities or by entering into new facilities prior to their expiration. EME's corporate cash
requirements in 2001 are expected to exceed cash distributions from its subsidiaries. EME's corporate cash
requirements in 2001 include: debt service under its senior notes and intercompany notes resulting from
sale-leaseback transactions which total $180 million; capital requirements for projects in development and under
construction of $289 million; and development costs, and general and administrative expenses.
On April 5, 2001, EME issued $600 million of 9.875% senior notes, due in 2011. EME used the proceeds of the notes
to repay indebtedness, including mandatory repayments of $225 million, which also reduced the amount available
under the corporate facilities. EME believes the proceeds from the notes will be adequate to meet its projected
net cash requirements in 2001. In addition, to reduce debt and to provide additional liquidity, EME may sell its
interest in individual projects in its project portfolio. Under one of EME's credit facilities, EME is required
to use 50% of the net proceeds from the sale of assets and 75% of the net proceeds from the issuance of capital
markets debt to repay senior bank indebtedness until the aggregate commitment amount under the corporate
facilities is reduced to $1 billion. There is no assurance that EME will be able to sell assets on favorable
terms or that the sale of individual assets will not result in a loss.
To isolate EME from the severe credit downgrades suffered by SCE, Edison Capital and the parent company, and to
help preserve the value of EME, EME has adopted certain amendments to its articles of incorporation and bylaws
(see additional discussion in Cash Flows from Financing Activities).
The financial performance of the Ferrybridge and Fiddler's Ferry plants has not matched EME's expectations,
largely due to lower energy power prices resulting from increased competition, climatic effects and uncertainties
surrounding the new electricity trading arrangements discussed in the EME Issues section of Market Risk
Exposures. Also, see additional discussion of the Ferrybridge and Fiddler's Ferry plants in Cash Flows from
Financing Activities. As a result of the change in power prices in the UK, EME is considering the sale of the
Ferrybridge and Fiddler's Ferry plants. A decision has not been made regarding whether or not the sale of these
plants will ultimately occur and, accordingly, these assets are not classified as held for sale. However, if a
decision to sell the Ferrybridge and Fiddler's Ferry plants were made, it is likely that the fair value of the
assets would be substantially below their book value at March 31, 2001. At March 31, 2001, EME's net investment
in the Ferrybridge and Fiddler's Ferry power plants was $991 million.
Edison Capital
- --------------
Edison Capital has fully drawn on its $300 million bank facility, which matures on June 30, 2001. Edison Capital
historically received cash from Edison International for the federal and state tax benefits and incentives
Page 26
flowing from Edison Capital's investments that are actually utilized on the Edison International consolidated tax
return. However, these tax benefits and incentives are not currently being utilized by Edison International and
Edison Capital is not currently receiving cash for them. Without such cash, Edison Capital must meet its current
obligations out of existing cash resources and/or by liquidating some of its investments. Any failure by Edison
Capital to meet its obligations as they become due, could be expected to have a material adverse effect on Edison
Capital's financial position and ability to conduct future operations. Under the current circumstances, Edison
Capital is not pursuing any new investment opportunities.
Edison International
- --------------------
The parent company has paid and expects to continue to pay its obligations, as they are due, subject to obtaining
financing. The parent company has fully drawn on the $618 million capacity of its existing 364-day credit
facility and has no other short-term borrowing capacity. The credit facility was scheduled to mature on May 14,
2001. The maturity date has been extended to June 30, 2001. Because of the payment defaults by SCE on its notes
and commercial paper, the parent company is technically in default under its credit facility due to cross-default
provisions. The administrative agent or a majority in interest of the lenders under the credit facility may
declare the outstanding loans to be immediately due and payable. The lenders have agreed to forbear from
exercising remedies until June 30, 2001. In addition, the parent company has two series of senior unsecured
notes that mature on July 18, 2001 ($250 million), and November 1, 2001 ($350 million), respectively. The parent
company's cash requirements in 2001 are expected to exceed its cash distributions from its subsidiaries.
Therefore, the parent company is dependent on obtaining additional financing to meet its cash requirements. The
parent company is seeking to arrange financing that would enable the parent company to pay the $600 million of
maturing notes during 2001 and repay the $618 million credit facility. In connection with a parent company
financing alternative under consideration, on April 30, 2001, EME filed an application with the FERC seeking
approval to form a new intermediate holding company that would own all of the common stock of EME and would serve
as a financing vehicle to issue new debt. The proceeds would be forwarded to the parent company and used to
repay the maturing debt. The common stock of EME would be pledged to secure the new debt. On May 14, 2001, the
FERC approved the application. The parent company believes that it will be able to obtain financing to meet its
cash requirements in 2001. The terms of such financing would likely include a pledge of the stock of EME among
other conditions. There is no assurance that the parent company will be able to obtain the financing that it
needs. To reduce current cash requirements, the parent company intends to exercise the right to defer interest
payments pursuant to the terms of its outstanding quarterly income debt securities issued to an affiliate. This
will cause a corresponding deferral of distributions on quarterly income preferred securities issued by that
affiliate. Interest payments may be deferred for up to 20 consecutive quarters. During the deferral period, the
principal of the debt securities and each unpaid interest installment will continue to accrue interest at the
applicable coupon rate. All interest in arrears must be paid in full at the end of the deferral period. The
parent company cannot pay dividends on or purchase its common stock while interest is being deferred. In
addition, to provide additional liquidity, the parent company may sell the assets of certain nonutility
subsidiaries. There is no assurance that the parent company will be able to sell assets on favorable terms or
that the sale of individual assets will not result in a loss.
As a result of SCE's $2.5 billion charge to earnings as of December 31, 2000, and its $661 million loss in first
quarter 2001 (discussed in Earnings section), Edison International's retained earnings are now in a deficit
position and therefore under California law, Edison International will be unable to pay dividends as long as a
deficit remains. Edison International does not meet other conditions under which dividends can be paid from
sources other than retained earnings.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $894 million in the first quarter of 2001, compared to $575
million in the first quarter of 2000. The increase in cash flows provided by operating activities in 2001 was
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primarily due to SCE's conservation of cash. Cash flows provided by operations is expected to increase in the
first half of 2001 as SCE continues to defer payments on its obligations as a result of its liquidity crisis (see
Liquidity Issues discussion).
Beginning first quarter 2001, the cash flow coverage of dividends quarterly calculation is not being presented
due to Edison International not paying dividends to its common stock shareholders (discussed above in Liquidity
Issues).
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, Edison International and its subsidiaries had $22 million of borrowing capacity available
under lines of credit totaling $4.1 billion. The parent company, SCE and Edison Capital have drawn on their
entire lines of credit. EME had total lines of credit of $1.5 billion, with $22 million available to finance
general cash requirements. These unsecured lines of credit have various expiration dates and, when available,
can be drawn down at negotiated or bank index rates. Both the parent company and SCE are currently negotiating
with bank lenders to extend their 364-day credit facilities ($618 million for the parent company and $200 million
for SCE) maturing on May 14, 2001.
The parent company's short-term and long-term debt is used for general corporate purposes, including investments
in nonutility business activities. EME uses its short-term and long-term debt to finance acquisitions and
development, as well as for general corporate purposes. Edison Capital's short-term and long-term debt is used
for general corporate purposes, as well as investments. SCE's 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, 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, the parent company, SCE and Edison Capital have been unable to sell their
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
Edison International, Edison Capital and SCE to substantially below investment grade. In mid-April, Moody's
removed the companies' ratings from review for possible downgrade. The ratings remain under review for possible
downgrade by the other two 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.
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
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non-bypassable rates charged to residential and small commercial customers. The rate reduction notes are being
repaid over 10 years through these non-bypassable 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.
To isolate EME from the credit downgrades of Edison International and SCE and to help preserve the value of EME,
EME has adopted certain amendments to its articles of incorporation and bylaws. The provisions include the
appointment of an independent EME director whose consent is required for EME to: consolidate or merge with any
entity that does not have substantially similar provisions in its organizational documents; institute or consent
to bankruptcy, insolvency or similar proceedings or actions; or declare or pay dividends unless certain
conditions exist. Such conditions are: EME has investment grade rating and receives rating agency confirmation
that the dividend or distribution will not result in a downgrade, or such dividends do not exceed $32.5 million
in any quarter and EME meets a certain interest coverage ratio for the immediately preceding four quarters.
EME has entered into a support agreement that commits it to contribute up to $300 million in equity to its
trading operation unit. EME has firm commitments related to the Italian wind projects of $3 million to make
equity contributions and $16 million for asset purchases, as well as $59 million related to its CBK acquisition
(see EME Acquisition). EME also has contingent obligations to make additional contributions of $44 million,
primarily for equity support guarantees related to the Paiton project in Indonesia and the ISAB project in
Italy. EME has capital commitments of: $986 million related to the turbine lease agreement; $396 million
related to the Sunrise project; and $250 million related to the Illinois plants.
EME may incur additional obligations to make equity and other contributions to projects in the future. EME has
interests in eight partnerships which own power plants (or QFs) in California and have power purchase agreements
with Pacific Gas and Electric Company (PG&E) and/or SCE. As discussed above, due to its current liquidity
crisis, SCE has deferred payments to QFs, among others, due in January, February and March 2001. However, on
April 17, 2001, SCE made payment to the partnerships for April deliveries, and subsequently made a supplemental
payment for power delivered between March 27 and March 31, 2001. At March 31, 2001, EME's share of accounts
receivable due from SCE was $234 million.
Some of the QFs owed by SCE, in which EME has interests, have sought to minimize their exposure by reducing
deliveries under power purchase agreements. Three of these partnerships have filed lawsuits against SCE (see
further discussion in the Litigation section of SCE's Regulatory Environment). On April 6, 2001, PG&E filed for
Chapter 11 bankruptcy protection. As of that date, EME's share of accounts receivable due from PG&E was $23
million. It is unclear at this time what additional actions, if any, the partnerships will take in regard to the
utilities' suspension of payments. As a result of the deferral of payments to these QFs, the partnerships in
which EME has interests have called on the partners to provide additional capital to fund operating costs of the
power plants. Between January 1, 2001, and April 30, 2001, EME subsidiaries have made equity contributions of
approximately $132 million to meet capital calls by the partnerships. EME's subsidiaries and the other partners
may be required to make additional capital contributions to the partnerships.
EME's UK subsidiary has deferred certain required capital expenditures at the Ferrybridge and Fiddler's Ferry
power plants because the plants' financial performance has not met expectations. As a result, the subsidiary is
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in breach of technical requirements set forth in the plants' financing agreements related to the acquisition of
the plants. Also, due to the lower financial performance, the subsidiary's debt service coverage ratio during
2000 declined below the threshold specified in the financing documents. The subsidiary is currently in
discussions with financing parties to revise the required capital expenditures program and to waive the breach of
the financial ratio covenant for 2000 and related technical defaults. There are no assurances that an agreement
can be met. The financing documents state that a breach of the financial ratio covenant constitutes an immediate
event of default and, if the event of default is not waived, the financing parties are entitled to enforce their
security over the affiliate's assets, including the power plants. Due to the timing of its cash flows and debt
service payments, EME's UK subsidiary utilized its debt service reserve to meet its debt service requirements in
2000. In March 2001, EME's UK subsidiary met its debt service requirements for the first quarter of 2001.
Edison Capital has firm commitments of $187 million to fund affordable housing, and energy and infrastructure
investments. In February 2001, as a result of Edison Capital's financial condition, it deposited approximately
$20 million as collateral for the commitments.
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.
Cash used for the nonutility subsidiaries' investing activities was $49 million for the three months ended March
31, 2001, compared to $172 million for the same period in 2000. The decrease is primarily the result of Edison
Capital's receipt of a loan repayment in January 2001, partially offset by an increase at EME related to equity
contributions made during first quarter 2001 to meet capital calls by partnerships who own QFs (see further
discussion in Cash Flows from Financing Activities).
Projected Capital Requirements
Edison International's projected construction expenditures for 2001 are $1.1 billion. This projection reflects
SCE's cost-cutting measures discussed above in the Liquidity Issues section.
Long-term debt maturities and sinking fund requirements for the five twelve month periods following March 31,
2001, are: 2002 - $2.5 billion; 2003 - $1.1 billion; 2004 - $1.2 billion; 2005 - $2.2 billion; and 2006 - $702
million. These projections assume no acceleration of payments arising from default. See further discussion in
Liquidity Issues.
Estimated noncancelable lease payments for the next five years are: 2001 - $192 million; 2002 - $212 million;
2003 - $211 million; 2004 - $233 million; and 2005 - $269 million.
Preferred stock redemption requirements for the five twelve month periods following March 31, 2001, are: 2002-
zero; 2003 - $105 million; 2004 - $9 million; 2004 - $9 million; and 2005 - $9 million.
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Market Risk Exposures
Edison International's primary market risk exposures arise from fluctuations in energy prices, oil and gas
prices, interest rates and foreign currency exchange rates. Edison International'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, except at the trading operation unit acquired by EME in
September 2000.
SCE Issues
Changes in interest rates and in energy prices can have a significant impact on SCE's results of operations.
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 the 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 Issues 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. Edison International'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
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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 SCE's Regulatory Environment.
EME Issues
Changes in electricity and fuel prices and in interest rates and fluctuations in foreign currency exchange rates
can have a significant impact on EME's results of operations.
EME is exposed to changes in interest rates because they affect the cost of capital needed to finance the
construction and operation of EME's projects. EME does not believe that its short-term debt is subject to
interest rate risk, due to the fair market value being approximately equal to the carrying value. However, EME's
long-term debt with fixed interest rates is subject to interest rate risk.
EME has mitigated a portion of the risk of interest rate fluctuations by arranging for fixed rate or variable
rate financing with interest rate swaps or other hedging mechanisms for a number of its project financings.
Several of EME's interest rate swap agreements mature prior to their underlying debt.
EME hedges a portion of the electric output of its merchant plants in order to lock in desirable outcomes. EME
also manages the margin between electric prices and fuel prices when deemed appropriate. EME uses forward
contracts, swaps, futures or option contracts to achieve these objectives.
Electric power generated at the Homer City plant is sold under bilateral arrangements with domestic utilities and
power marketers under short-term contracts (two years or less) or to the Pennsylvania-New Jersey-Maryland Power
Pool (PJM) or the New York Independent System Operator (NYISO). These pools have short-term markets, which
establish an hourly clearing price. The Homer City plant is located in the PJM control area and is physically
connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City plant can
also transmit power to the mid-western United States.
Electric power generated at the Illinois plants is sold under power purchase agreements in which Exelon
Generation Company (ExGen) will purchase capacity and have the right to purchase energy generated by EME's
Illinois plants. The agreements, which began in December 1999, and have a term of up to five years, provide for
capacity and energy payments. ExGen will be obligated to make a capacity payment for the units under contract
and an energy payment for the electricity produced by these units and taken by ExGen. The capacity payments
provide the Illinois plants revenue for fixed charges, and the energy payments compensate the Illinois plants for
variable costs of production. If ExGen does not order all the power from the units under contract, the Illinois
plants may sell, subject to specified conditions, the excess energy at market prices to neighboring utilities,
municipalities, third-party electric retailers, large consumers and power marketers on a spot basis.
EME's trading and price risk management activities give rise to market risk, which represents the potential loss
that can be caused by a change in the market value of a particular commitment. Market risks are actively
monitored to ensure compliance with the risk management policies of EME, which limit its total net exposure. EME
performs a value at risk analysis daily to monitor its overall market risk exposure. Value at risk measures the
worst expected loss over a given time interval, under normal market conditions, at a given confidence level.
Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements
this approach with other techniques, including the use of stress testing and worst-case scenario analysis, as
well as stop limits and counterparty credit exposure limits.
Since 1989, EME's projects in the UK sold their electric energy and capacity through a centralized electricity
pool, which establishes a half-hourly clearing price, or pool price, for electric energy. On March 27, 2001,
this system was replaced with a bilateral physical trading system, referred to as the new electricity trading
arrangements.
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The new electricity trading arrangements are the direct result of an October 1997 request by the Minister for
Science, Energy and Industry who asked the UK Director General of Electricity Supply to review the operation of
the pool pricing system. In July 1998 the Director General proposed that the current structure of contracts for
differences and compulsory trading via the pool at half-hourly clearing prices bid a day ahead be abolished. The
UK government accepted the proposals in October 1998 subject to reservations. Following this, further proposals
were published by the government and the Director General in July and October 1999. The proposals include, among
other things, the establishment of a spot market or voluntary short-term power exchanges operating from 24 hours
to 3 1/2hours before a trading period; a balancing mechanism to enable the system operator to balance generation
and demand and resolve any transmission constraints; a mandatory settlement process for recovering imbalances
between contracted and metered volumes with strong incentives for being in balance; and a Balancing and
Settlement Code Panel to oversee governance of the balancing mechanism. Contracting over time periods longer
than the day-ahead market is not directly affected by the proposals. Physical bilateral contracts will replace
the current contracts for differences, but will function in a similar manner. However, it remains difficult to
evaluate the future impact of the proposals. A key feature of the new electricity trading arrangements is to
require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery,
against their contracted positions or face assessment of energy imbalance penalty charges by the system
operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance
and develop forwards and futures markets of greater liquidity than at present. Recent experience has been that
the new electricity trading arrangements have placed a significant downward pressure on forward contract prices.
Furthermore, another consequence may be that counterparties may require additional credit support, including
parent company guarantees or letters of credit. Legislation in the form of the Utilities Act, which was
approved in July 2000, allows for the implementation of new electricity trading arrangements and the necessary
amendments to generators' licenses. Various key documents were designated by the Secretary of State and signed by
participants in August 2000; however, due to difficulties encountered during testing, implementation of the new
trading arrangements was delayed from November 2000 until March 27, 2001.
The Utilities Act sets a principal objective for the UK Government and the Director General to "Protect the
interests of consumers...where appropriate by promoting competition..." This objective represents a shift in
emphasis toward consumer interest, but is qualified by the recognition that license holders should be able to
finance their activities. The Act also contains new powers for the government to issue guidance to the Director
General on social and environmental matters, changes to the procedures for modifying licenses, and a new power
for the Director General to impose financial penalties on companies for breach of license conditions. EME will
be monitoring the operation of these new provisions.
The Loy Yang B project in Australia sells its electrical energy through a centralized electricity pool, which
provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market
for each half-hour of every day. The National Electricity Market Management Company, operator and administrator
of the pool, determines a system marginal price each half-hour. To mitigate the exposure to price volatility of
the electricity traded in the pool, Loy Yang B has entered into a number of financial hedges. The State hedge
with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price
commencing May 1997 and terminating in October 2016. The State government guarantees the State Electricity
Commission of Victoria's obligations under the State hedge. From January 2001 to July 2014, approximately 77% of
the plant output sold is hedged under the State hedge. From August 2014 to October 2016, approximately 56% of
the plant output sold is hedged under the State hedge. Additionally, Loy Yang B entered into a number of fixed
forward electricity contracts commencing either in 2001 or 2002, which expire on various dates through December
2002, and which will further mitigate the price volatility of the electricity pool.
The New Zealand government has been undergoing a steady process of electric industry deregulation since 1987.
Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity
distribution and provided for competition in the retail electric supply function. The New Zealand Energy Market,
established in 1996, is a voluntary competitive wholesale market that allows for the trading of physical
electricity on a half-hourly basis. The Electricity Industry Reform Act, which was passed in July 1998, was
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designed to increase competition at the wholesale generation level by splitting up Electricity Company of New
Zealand Limited, the large state-owned generator, into three separate generation companies. The Electricity
Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity.
The New Zealand government commissioned an inquiry into the electricity industry in February 2000. This Inquiry
Board's report was presented to the government in mid-2000. The main focus of the report was on the monopoly
segments of the industry, transmission and distribution, with substantial limitations being recommended in the
way in which these segments price their services in order to limit their monopoly power. Recommendations were
also made with respect to the retail customer in order to reduce barriers to customers switching. In addition,
the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of
streamlining them. The recommended changes are now being progressively implemented.
Foreign currencies in the UK, Australia and New Zealand decreased in value compared to the US dollar by 5%, 12%
and 9%, respectively (determined by the change in the exchange rates from December 31, 2000, to March 31, 2001).
The decrease in value of these currencies was the primary reason for EME's foreign currency translation loss of
$97 million during the first quarter of 2001.
In December 2000, EME entered into foreign currency forward exchange contracts, in the ordinary course of
business, to protect itself from adverse currency rate fluctuations on anticipated foreign currency commitments.
The periods of the foreign currency forward exchange contracts correspond to the periods of the hedged
transactions. At March 31, 2001, the outstanding notional amount of the contracts was $83 million, consisting of
contracts to exchange US dollars to pound sterling with varying maturities ranging from April 2001 to July 2002.
During the first quarter of 2001, EME recognized a foreign exchange loss (less than $100,000) related to the fuel
purchases underlying the contracts that matured in January, February and March of 2001. EME will continue to
monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the
future.
Fluctuations in foreign currency exchange rates can affect the amount of EME's equity contributions to, and
distributions from its international projects. As EME continues to expand into foreign markets, fluctuations in
foreign currency exchange rates can be expected to have a greater impact on EME's results of operations in the
future. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates
through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying
project agreements to US dollars or other indices reasonably expected to correlate with foreign exchange
movements. Statistical forecasting techniques are used to help assess foreign exchange risk and the
probabilities of various outcomes. There can be no assurance, however, that fluctuations in exchange rates will
be fully offset by hedges or that currency movements and the relationship between macroeconomic variables will
behave in a manner that is consistent with historical or forecasted relationships.
Edison Capital Issues
Changes in interest rates and fluctuations in foreign currency exchange rates can have a significant impact on
Edison Capital's results of operations.
Edison Capital is exposed to changes in interest rates primarily as a result of its borrowing and investing
activities used for general corporate purposes, as well as investments. The nature and amount of Edison
Capital's long-term and short-term debt can be expected to vary as a result of future business requirements,
market conditions and other factors.
Edison Capital does not believe that its short-term debt is subject to interest rate risk, due to the fair market
value being approximately equal to the carrying value. However, Edison Capital does believe that the fair market
value of its fixed rate long-term debt is subject to interest rate risk.
Page 34
Edison Capital has entered into interest rate swap agreements to reduce actual or expected exposure to interest
rate fluctuations.
Edison Capital has entered into foreign currency contracts to reduce the potential impact of changes in foreign
exchange rates and future foreign currency denominated cash flows. At March 31, 2001, the outstanding notional
amount of the contracts was approximately $10 million, consisting of contracts to exchange US dollars to pounds
sterling.
Edison International Issues
The parent company is exposed to changes in interest rates primarily as a result of its borrowing and investing
activities used for general corporate purposes, including investments in nonutility business activities. The
nature and amount of the parent company's long-term and short-term debt can be expected to vary as a result of
future business requirements, market conditions and other factors.
The parent company believes that, due to the liquidity issues it faces, its short-term debt is subject to
interest rate risk and that the fair market value of its fixed rate long-term debt is subject to interest rate
risk.
Paiton Project
Paiton Energy, a wholly owned subsidiary of EME, owns a 40% interest and has a $499 million investment (at
March 31, 2001) in the Paiton project, a 1,230-MW coal-fired power plant in Indonesia. As discussed more fully in
Edison International's 2000 Annual Report on Form 10-K, Paiton Energy is continuing negotiations on a long-term
restructuring of the revenue schedule under a long-term power purchase agreement with the state-owned electricity
company. Paiton Energy and the state-owned electricity company have agreed on a Phase I Agreement for the period
from January 1, 2001, through June 30, 2001. This agreement provides for fixed monthly payments totaling $108
million over its six-month duration and for the payment for energy delivered to the state-owned electricity
company from the plant during this period. To date, the state-owned electricity company has made fixed payments
due under the Phase I Agreement totaling $52 million as scheduled. Paiton Energy and the state-owned electricity
company intended to complete the negotiations of the future phases of a new long-term revenue schedule during the
six-month duration of the Phase I Agreement. Paiton Energy has received lender approval of the Phase I Agreement
and has also entered into a lender interim agreement under which lenders have agreed to interest-only payments
and to the deferral of principal payments while Paiton Energy and the state-owned electricity company seek a
long-term restructuring. The lenders have agreed to extend that agreement through December 31, 2001. Based on
the current status of negotiations between Paiton Energy and the state-owned electricity company, it is not
likely that a long-term restructuring of the revenue schedule will be completed by June 30, 2001. The Paiton
project is continuing to generate electricity to meet the power demand in the region. Paiton Energy believes
that the state-owned electricity company will continue to agree to make payments for electricity on an interim
basis beyond June 30, 2001, while negotiations regarding long-term restructuring of the revenue schedule
continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that
negotiations on the long-term restructuring of the revenue schedule will be successful.
Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new
long-term revenue schedule could require a renegotiation of the Paiton project's debt agreements. The impact of
any such renegotiations with the state-owned electricity company, the Indonesian government or the project's
creditors on EME's expected return on its investment in the Paiton project is uncertain at this time; however,
EME believes that it will ultimately recover its investment in the project.
EME Acquisition
In February 2001, EME completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20
million. CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with National
Page 35
Power Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the
Philippines. Financing for this $460 million project has been completed with equity contributions of $117
million (EME's share is $59 million) required to be made upon completion of the rehabilitation and expansion,
currently scheduled in 2003. Debt financing has been arranged for the remainder of the cost for this project.
SCE's 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
Page 36
of 7.35%. In addition, the San Onofre incentive pricing plan authorizes a fixed rate of approximately 4(cent)per kWh
generated for operating costs including incremental capital costs, nuclear fuel and nuclear fuel financing
costs. The San Onofre plan commenced in April 1996, and ends at the earlier of December 2001 or the date when
the statutory rate freeze ends for the accelerated recovery portion, and in December 2003 for the
incentive-pricing portion. The Palo Verde Nuclear Generating Station's operating costs, including incremental
capital costs, and nuclear fuel and nuclear fuel financing costs, are subject to balancing account treatment.
The Palo Verde plan commenced in January 1997 and ends in December 2001. 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.
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 become
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
Page 37
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 Issues) 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
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
Page 38
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.
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
Page 39
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
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
Page 40
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, and 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 additional 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 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
Page 41
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).
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
Page 42
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).
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, 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 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.
Page 43
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 EME 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. EME 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. 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
Page 44
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. Edison International and 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
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.
Page 45
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.
Environmental Protection
Edison International 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 4 to the Consolidated Financial Statements, Edison International records its
environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International's recorded estimated minimum liability to remediate
its 44 identified sites is $116 million. Edison International 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 4. SCE has recorded a regulatory
asset of $74 million for its estimated minimum environmental-cleanup costs expected to be recovered through
customer rates.
Edison International'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. Edison
International 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, Edison International 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, Edison International 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 46
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.
Edison International's projected environmental capital expenditures are $1.7 billion for the 2001-2005 period,
mainly for undergrounding certain transmission and distribution lines at SCE and upgrading environmental controls
at EME.
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 recovery plan (discussed in the Generation and
Power Procurement section of SCE's 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.
Page 47
Accounting Changes
On January 1, 2001, Edison International 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 or a foreign currency exposure, 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. 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. As a result of the adoption of the
new standard, Edison International expects that earnings from its EME subsidiary will be more volatile than
earnings reported under the prior accounting policy. For Edison International's first quarter 2001 earnings, the
cumulative effect on prior years from the adoption of the new standard is an increase of approximately $6 million
(after tax).
Effective January 1, 2000, EME changed its accounting method for major maintenance to record such expenses as
incurred. Previously, EME recorded major maintenance costs on an accrue-in-advance method. EME voluntarily made
the change in accounting due to guidance provided by the Securities and Exchange Commission. The cumulative
effect of the change in accounting method was an $18 million after-tax benefit.
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 Edison International's and SCE's ability to regain an investment grade rating and re-enter the
credit markets; the ability of Edison International to obtain financing without regaining an investment grade
rating (such as through a pledge of EME's stock); changes in financial market conditions; risks of doing business
in foreign countries, such as political changes and currency devaluations; power plant construction and operation
risks; new or increased environmental liabilities; the amount of revenue available to recover both transition and
non-transition costs; the financial viability of new businesses, such as telecommunications; weather conditions;
and other unforeseen events.
Page 48
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Edison International
Shareholder Litigation
As previously reported in Part 1, Item 3 of Edison International's Annual Report on Form 10-K for the fiscal year
ended December 31, 2000 (2000 Form 10-K), Edison International has been named as a defendant along with SCE in
two lawsuits. These lawsuits are more fully described under Southern California Edison Company - Shareholder
Litigation.
Qualifying Facilities Litigation
As previously reported in Part 1, Item 3 of Edison International's 2000 Form 10-K, Edison International along
with SCE has been named as a defendant in one of the lawsuits generally described under Southern California
Edison Company - Qualifying Facilities Litigation.
Southern California Edison Company
San Onofre Personal Injury Litigation
As previously reported in Part 1, Item 3 of Edison International's 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 Edison International'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
Page 49
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.
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 Edison International's 2000 on Form 10-K for the fiscal year ended
December 31, 2000, 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.
Page 50
In addition to the cases previously referenced in Edison International'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
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
Page 51
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 7, 1998
(File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior participating Cumulative Preferred Stock of
Edison International dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on February 17,
2000 (File No. 1-9936, filed as Exhibit 3.3 to Form 10-K for the year 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
11 Computation of Primary and Fully Diluted Earnings per Share
(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.
Page 52
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.
EDISON INTERNATIONAL
(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
