UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the quarterly period ended September 30, 1999
----------------------------------------------
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from ________________________ to ____________________
Commission File No. 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California
(Address of principal 91770
executive offices) (Zip Code)
(626) 302-1212
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No ___
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding at November 8, 1999
- -----------------------------------------------------------------------------
Common Stock, no par value 434,888,104
===============================================================================
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 1
Consolidated Statements of Income -- Three, Nine and
Twelve Months Ended September 30, 1999, and 1998 2
Consolidated Statements of Comprehensive Income --
Three, Nine and Twelve Months Ended September 30, 1999,
and 1998 2
Consolidated Balance Sheets -- September 30, 1999,
December 31, 1998, and September 30, 1998 3
Consolidated Statements of Cash Flows --
Three, Nine and Twelve Months Ended
September 30, 1999, and 1998 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 27
Part II. Other Information:
Item 1. Legal Proceedings 38
Item 6. Exhibits and Reports on Form 8-K 41
<PAGE>
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE), a California corporation, and its subsidiaries
as of September 30, 1999, December 31, 1998, and September 30, 1998, and the
related consolidated statements of income, comprehensive income, and cash flows
for each of the three-, nine- and twelve-month periods ended September 30, 1999,
and 1998. These financial statements are the responsibility of SCE's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of SCE and its subsidiaries as of
September 30, 1999, December 31, 1998, and September 30, 1998, and the results
of their operations and their cash flows for each of the three-, nine- and
twelve-month periods ended September 30, 1999, and 1998, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 2, 1999
1
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- ----------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenue $ 2,303,922 $ 2,369,498 $ 5,701,460 $ 5,610,970 $ 7,590,008 $ 7,591,334
- ----------------------------------------------------------------------------------------------------------------------------
Fuel 57,592 64,621 163,022 242,489 244,249 409,882
Purchased power-- contracts 823,470 908,407 1,856,130 2,010,269 2,471,762 2,747,155
Purchased power-- PX-- net 317,391 393,739 531,490 433,838 733,995 433,838
Provisions for regulatory
adjustment clauses-- net (201,430) (447,676) (562,179) (289,314) (745,384) (422,811)
Other operating expenses 368,033 437,065 1,218,331 1,124,693 1,574,281 1,502,105
Maintenance 84,378 104,265 279,395 304,627 385,335 407,916
Depreciation, decommissioning and
amortization 413,400 378,189 1,176,695 1,137,087 1,585,343 1,446,518
Income taxes 154,380 172,015 317,120 396,777 365,986 541,434
Property and other taxes 29,260 31,642 96,733 102,406 122,728 130,055
Net loss (gain) on sale of utility plant 767 89,939 (2,158) (529,099) (15,669) (529,840)
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,047,241 2,132,206 5,074,579 4,933,773 6,722,626 6,666,252
- ----------------------------------------------------------------------------------------------------------------------------
Operating income 256,681 237,292 626,881 677,197 867,382 925,082
- ----------------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan -- -- -- -- -- (12,578)
Allowance for equity funds
used during construction 4,040 3,051 9,932 8,740 13,017 10,800
Interest and dividend income 20,465 18,031 51,272 51,754 66,245 69,356
Other nonoperating income
(deductions)-- net 5,696 27,672 29,080 19,774 4,921 (1,234)
- ----------------------------------------------------------------------------------------------------------------------------
Total other income-- net 30,201 48,754 90,284 80,268 84,183 66,344
- ----------------------------------------------------------------------------------------------------------------------------
Income before interest expense 286,882 286,046 717,165 757,465 951,565 991,426
- ----------------------------------------------------------------------------------------------------------------------------
Interest and amortization on long-term debt 101,072 103,916 299,527 319,784 401,600 405,873
Other interest expense 20,806 16,032 64,276 50,142 78,361 78,342
Allowance for borrowed funds used
during construction (3,505) (2,076) (8,619) (5,947) (10,718) (8,427)
Capitalized interest (42) (330) (1,110) (612) (1,792) (691)
- ----------------------------------------------------------------------------------------------------------------------------
Total interest expense-- net 118,331 117,542 354,074 363,367 467,451 475,097
- ----------------------------------------------------------------------------------------------------------------------------
Net income 168,551 168,504 363,091 394,098 484,114 516,329
Dividends on preferred stock 8,445 5,612 20,253 19,019 25,865 25,778
- ----------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock $ 160,106 $ 162,892 $ 342,838 $ 375,079 $ 458,249 $ 490,551
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Net income $ 168,551 $ 168,504 $ 363,091 $ 394,098 $ 484,114 $ 516,329
Unrealized gain (loss) on securities--net 31,993 (21,631) 24,776 (9,189) 43,240 1,944
Reclassification adjustment for gains
included in net income (13,654) -- (45,899) -- (63,735) --
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 186,890 $ 146,873 $ 341,968 $ 384,909 $ 463,619 $ 518,273
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of
these financial statements.
2
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1999 1998 1998
- ------------------------------------------------------------------------------------------------------------------
ASSETS
Utility plant, at original cost:
<S> <C> <C> <C>
Transmission and distribution $ 12,134,001 $ 11,771,678 $ 11,591,649
Generation 1,698,781 1,689,469 1,728,929
Accumulated provision for depreciation
and decommissioning (7,265,355) (6,896,479) (6,765,106)
Construction work in progress 703,742 516,664 582,569
Nuclear fuel, at amortized cost 148,785 172,250 141,569
- -----------------------------------------------------------------------------------------------------------------
Total utility plant 7,419,954 7,253,582 7,279,610
- -----------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision
for depreciation of $8,794, $25,682
and $25,381 at respective dates 72,248 56,681 74,940
Nuclear decommissioning trusts 2,326,847 2,239,929 2,013,293
Other investments 181,560 179,480 210,116
- -----------------------------------------------------------------------------------------------------------------
Total other property and investments 2,580,655 2,476,090 2,298,349
- -----------------------------------------------------------------------------------------------------------------
Cash and equivalents 227,718 81,500 284,312
Receivables, including unbilled revenue, less
allowances of $27,417, $22,230 and $20,235
for uncollectible accounts at respective dates 1,299,047 1,112,630 1,266,361
Fuel inventory 51,150 51,299 50,561
Materials and supplies, at average cost 120,064 116,259 121,408
Accumulated deferred income taxes-- net 143,441 274,833 269,277
Regulatory balancing accounts-- net 127,516 287,377 6,539
Prepayments and other current assets 129,751 91,992 127,168
- -----------------------------------------------------------------------------------------------------------------
Total current assets 2,098,687 2,015,890 2,125,626
- -----------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net 1,564,807 2,161,998 2,387,998
Income tax-related deferred charges 1,352,336 1,463,256 1,454,606
Regulatory balancing accounts-- net 1,250,085 361,404 400,997
Unamortized debt issuance and reacquisition
expense 341,786 348,816 356,018
Other deferred charges 997,630 865,892 915,612
- -----------------------------------------------------------------------------------------------------------------
Total deferred charges 5,506,644 5,201,366 5,515,231
- -----------------------------------------------------------------------------------------------------------------
Total assets $ 17,605,940 $ 16,946,928 $ 17,218,816
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of
these financial statements.
3
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1999 1998 1998
- -----------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Common stock (434,888,104 shares
<S> <C> <C> <C>
outstanding at each date) $ 2,168,054 $ 2,168,054 $ 2,168,054
Additional paid-in capital 335,014 334,031 334,031
Accumulated other comprehensive income 18,339 39,462 38,834
Retained earnings 585,375 793,625 819,941
Preferred stock:
Not subject to mandatory redemption 128,755 128,755 128,755
Subject to mandatory redemption 255,700 255,700 255,700
Long-term debt 5,221,915 5,446,638 5,486,384
- ----------------------------------------------------------------------------------------------------------
Total capitalization 8,713,152 9,166,265 9,231,699
- ----------------------------------------------------------------------------------------------------------
Current portion of long-term debt 568,009 400,810 593,311
Short-term debt 605,003 469,565 105,780
Accounts payable 561,364 447,484 640,409
Accrued taxes 984,560 678,955 832,331
Accrued interest 88,778 89,828 70,506
Dividends payable 94,350 91,742 91,943
Deferred unbilled revenue and other current
liabilities 1,414,335 1,096,332 1,162,644
- ----------------------------------------------------------------------------------------------------------
Total current liabilities 4,316,399 3,274,716 3,496,924
- ----------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 2,768,891 2,993,142 2,880,334
Accumulated deferred investment tax credits 217,822 250,116 302,539
Customer advances and other deferred credits 824,537 795,266 791,081
Power purchase contracts 333,262 129,698 133,700
Other long-term liabilities 431,547 337,411 382,230
- ----------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 4,576,059 4,505,633 4,489,884
- ----------------------------------------------------------------------------------------------------------
Minority interest 330 314 309
- ----------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $ 17,605,940 $ 16,946,928 $ 17,218,816
- ----------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of
these financial statements.
4
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- ------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
<S> <C> <C> <C> <C> <C> <C>
Net income $ 168,551 $ 168,504 $ 363,091 $ 394,098 $ 484,114 $ 516,329
Adjustments for non-cash items:
Depreciation, decommissioning and
amortization 413,400 378,189 1,176,695 1,137,087 1,585,343 1,446,518
Other amortization 26,295 25,784 69,419 63,316 95,426 89,610
Rate phase-in plan -- -- -- 3,777 -- 16,220
Deferred income taxes and
investment tax credits (81,249) 66,342 (14,233) (140,683) 31,946 (57,804)
Other long-term liabilities 22,511 20,227 103,822 36,293 55,001 11,196
Regulatory balancing
accounts-- long-term (424,415) (543,024) (888,681) (400,997) (849,088) (400,997)
Regulatory asset related to sale of
generating plants (58) (111,310) 183 (219,301) (748) (219,301)
Net loss (gain) on sale of
generating plants 227 88,355 (883) (551,984) (13,522) (551,984)
Other-- net (18,347) (16,338) (38,549) (35,631) 907 (55,936)
Changes in working capital:
Receivables (236,671) (235,569) (186,417) (359,973) (32,686) (58,360)
Regulatory balancing accounts 150,579 185,722 159,861 186,772 (120,977) 94,396
Fuel inventory, materials and supplies (2,060) (4,326) (3,656) 19,070 755 33,820
Prepayments and other current assets (112,281) (112,028) (37,759) (34,070) (2,583) (994)
Accrued interest and taxes 259,377 (87,083) 304,555 308,161 170,501 17,877
Accounts payable and other
current liabilities 430,448 357,382 431,883 464,493 172,646 420,744
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 596,307 180,827 1,439,331 870,428 1,577,035 1,301,334
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 135,300 -- 490,840 -- 490,840 --
Long-term debt repaid (145,410) (1,575) (362,872) (606,030) (532,872) (606,030)
Rate reduction notes issued -- -- -- -- -- 2,444,127
Rate reduction notes repaid (58,520) (78,605) (178,280) (161,070) (268,801) (155,908)
Preferred stocks redeemed -- (1,000) -- (74,300) -- (74,300)
Nuclear fuel financing-- net (13,828) 7,393 (22,844) (11,478) 4,878 (18,990)
Short-term debt financing-- net 197,888 (15,775) 135,438 (216,248) 499,223 (664,520)
Dividends paid (274,358) (429,124) (563,373) (982,146) (711,039) (2,258,643)
- -------------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (158,928) (518,686) (501,091) (2,051,272) (517,771) (1,334,264)
- -------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (242,254) (211,272) (717,391) (548,319) (1,029,910) (789,850)
Proceeds from sale of generating plants -- 43,000 -- 1,188,039 15,000 1,188,039
Funding of nuclear decommissioning trusts (29,049) (41,315) (95,473) (118,196) (140,202) (162,750)
Unrealized gain (loss) on securities--net 18,339 (21,631) (21,123) (9,189) (20,495) 1,944
Other-- net (29,136) 22,447 41,965 (9,451) 59,749 (16,192)
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by
investing activities (282,100) (208,771) (792,022) 502,884 (1,115,858) 221,191
- -------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash
and equivalents 155,279 (546,630) 146,218 (677,960) (56,594) 188,261
Cash and equivalents, beginning
of period 72,439 830,942 81,500 962,272 284,312 96,051
- ------------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 227,718 $ 284,312 $ 227,718 $ 284,312 $ 227,718 $284,312
- ------------------------------------------------------------------------------------------------------------------------
Cash payments for interest and taxes:
Interest-- net of amounts capitalized $ 98,112 $ 91,821 $ 215,425 $ 217,488 $ 261,681 $ 309,063
Taxes 92,616 325,666 92,628 326,092 171,533 548,129
</TABLE>
The accompanying notes are an integral part of
these financial statements.
5
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Southern California Edison Company (SCE) is a public utility which supplies
electric energy for its 4.3 million customers in central, coastal and Southern
California. SCE also produces electricity. The regulatory environment in which
SCE operates is changing as a result of a 1995 California Public Utilities
Commission (CPUC) decision on electric utility industry restructuring and state
legislation enacted in 1996.
Basis of Presentation
SCE's accounting policies conform with generally accepted accounting principles,
including the accounting principles for rate-regulated enterprises which reflect
the rate-making policies of the CPUC and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring legislation enacted by
the State of California and related changes in the rate-recovery of generation
related assets, SCE accounts for its investment in generation facilities in
accordance with accounting principles applicable to enterprises in general.
Application of such accounting principles to SCE's generation assets, beginning
in 1997, did not result in any adjustment of their carrying value; however, in
the second quarter of 1998, the carrying value of SCE's nuclear investments
(excluding decommissioning) was reduced by $2.6 billion and a regulatory asset
was established for the same amount.
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated. Certain prior-period amounts
were reclassified to conform to the September 30, 1999, financial statement
presentation.
SCE's outstanding common stock is owned entirely by its parent company, Edison
International.
Since April 1, 1998, when the new market structure began, SCE has been selling
all of its generation through the power exchange (PX), as mandated by the CPUC's
1995 restructuring decision. Through the PX, SCE satisfies the electric energy
needs of customers who did not choose an alternative energy provider. These
transactions through the PX are reported as Purchased power -- PX -- net.
Transactions through the PX were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- -------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Purchases $ 882 $ 1,081 $ 1,739 $ 1,425 $ 2,298 $ 1,425
Generation sales 565 687 1,208 991 1,564 991
- -------------------------------------------------------------------------------------------------------
Purchased power-- PX-- net $ 317 $ 394 $ 531 $ 434 $ 734 $ 434
- -------------------------------------------------------------------------------------------------------
</TABLE>
Cash Equivalents
Cash equivalents include tax-exempt investments and time deposits and other
investments with original maturities of three months or less.
Estimates
Financial statements prepared in compliance with generally accepted accounting
principles require management to make estimates and assumptions that affect the
amounts reported in the financial statements and disclosure of contingencies.
Actual results could differ from those estimates. Certain significant estimates
related to regulatory matters, decommissioning and contingencies are further
discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements,
respectively.
6
<PAGE>
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and
natural gas, and under the first-in, first-out method for coal.
Nuclear
SCE is recovering its investment in San Onofre Nuclear Generating Station Units
2 and 3 and Palo Verde Nuclear Generating Station on an accelerated basis, as
authorized by the CPUC. The accelerated recovery will continue through December
2001, earning a 7.35% fixed rate of return. San Onofre's operating costs,
including nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, are recovered through an incentive pricing plan which allows SCE
to receive about 4(cent) per kilowatt-hour through 2003. Any differences between
these costs and the incentive price will flow through to the shareholders. Palo
Verde's accelerated plant recovery, as well as operating costs, including
nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, are subject to balancing account treatment through 2001.
Beginning January 1, 1998, San Onofre's incentive pricing plan and accelerated
plant recovery and the Palo Verde balancing account became part of the
transition cost balancing account. SCE will be required to share equally with
ratepayers the net benefits received from operation of Palo Verde, beginning in
2002, and from the operation of the San Onofre units in 2004. Palo Verde's
existing nuclear unit incentive procedure will continue only for purposes of
calculating a reward for performance of any unit above an 80% capacity factor
for a fuel cycle.
CPUC-authorized rate phase-in plans, which deferred collection of revenue for
each unit at Palo Verde during the first four years of operation, ended in
February 1996, September 1996 and January 1998 for Units 1, 2 and 3,
respectively.
Regulation of Utility Business
SCE, which is subject to rate-regulation by the CPUC and the FERC, 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.
Effective January 1, 1998, SCE's rates were unbundled into separate charges for
energy, transmission, distribution, the non-bypassable competition transition
charge (CTC), public benefit programs and nuclear decommissioning. The
transmission component is being collected through FERC-approved rates, subject
to refund. SCE's costs associated with its hydroelectric plants are being
recovered through a performance-based mechanism. This mechanism sets the
hydroelectric revenue requirement and establishes a formula for extending it
through the duration of the electric industry restructuring transition period
(March 31, 2002), or until market valuation of the hydroelectric facilities,
whichever occurs first. Revenue from hydroelectric facilities in excess of the
hydroelectric revenue requirement is credited against the costs to transition to
a competitive market. Decommissioning costs are being recovered through a
CPUC-authorized non-bypassable charge.
The CTC provides SCE the opportunity to recover its costs to transition to a
competitive market (approximately $10.6 billion 1998 net present value).
Transition costs related to power-purchase contracts are being recovered through
the terms of the contracts while most of the remaining transition costs will be
recovered through 2001. A portion of the stranded costs that residential and
small commercial customers would have paid between 1998 and 2001, has been
financed by the issuance of rate reduction notes, allowing SCE to reduce rates
by at least 10% to these customers, effective January 1, 1998. The notes allow
for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
7
<PAGE>
costs until after the transition period. Additionally, the state legislation
contained provisions for the recovery (through 2006) of reasonable
employee-related transition costs, incurred and projected, for retraining,
severance, early retirement, outplacement and related expenses.
Regulatory Assets and Liabilities
In accordance with accounting principles for rate-regulated enterprises, SCE
records regulatory assets, which represent probable future revenue associated
with certain costs that will be recovered from customers through the rate-making
process, and regulatory liabilities, which represent probable future reductions
in revenue associated with amounts that are to be credited to customers through
the rate-making process. SCE's discontinuance of accounting principles for
rate-regulated enterprises to its generation assets did not result in a
write-off of its generation-related regulatory assets since the CPUC has
approved recovery of these assets through the CTC.
Regulatory assets and liabilities included in the consolidated balance sheets
are:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
In millions 1999 1998 1998
- -----------------------------------------------------------------------------------------------------
Generation-related:
<S> <C> <C> <C>
Unamortized nuclear investment-- net $ 1,565 $ 2,162 $ 2,388
Flow-through taxes 358 614 675
Rate reduction notes-- transition cost deferral 619 315 266
Unamortized loss on sale of plant 137 183 197
Purchased-power settlements 301 130 134
Environmental remediation 16 16 16
Regulatory balancing accounts and other 884 354 287
- ----------------------------------------------------------------------------------------------------
Subtotal 3,880 3,774 3,963
- ----------------------------------------------------------------------------------------------------
Other:
Flow-through taxes 995 849 780
Unamortized loss of reacquired debt 301 308 314
Environmental 114 125 129
Regulatory balancing accounts and other (18) 110 (7)
- ----------------------------------------------------------------------------------------------------
Subtotal 1,392 1,392 1,216
- ----------------------------------------------------------------------------------------------------
Total $ 5,272 $ 5,166 $ 5,179
- ----------------------------------------------------------------------------------------------------
</TABLE>
Generation-related regulatory assets and liabilities are being recovered through
the CTC through March 31, 2002, except for the rate reduction notes regulatory
asset which will be recovered over the terms of the rate reduction notes. The
other regulatory assets and liabilities are being recovered through other
components of the unbundled rates.
The unamortized nuclear investment regulatory asset was created during the
second quarter of 1998. SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount in accordance with asset impairment accounting
standards. For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows. This reclassification
had no effect on SCE's results of operations.
If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at September 30, 1999) as a one-time, non-cash charge
against earnings.
8
<PAGE>
Regulatory Balancing Accounts
Beginning January 1, 1998, the difference between generation-related revenue and
generation-related costs is being accumulated in the transition cost balancing
account, effectively eliminating all other balancing accounts except those used
to assist in the administration of public purpose funds. Additionally, gains
resulting from the sale of the gas- and oil-fueled generation plants during 1998
were credited to the transition cost balancing account; the losses are being
amortized over the remaining transition period and accumulated in the transition
cost balancing account. These transition costs are being recovered from utility
customers (with interest) through the CTC mechanism.
Prior to January 1, 1998, the differences between CPUC-authorized and actual
base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy
costs were accumulated in balancing accounts until they were refunded to, or
recovered from, utility customers through authorized rate adjustments (with
interest). On January 1, 1998, the balances in these balancing accounts were
transferred to the transition cost balancing account.
Income tax effects on all balancing account changes are deferred.
Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant construction. If
construction does not occur, these costs are charged to expense.
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end
of each period.
Utility Plant
Plant additions, including replacements and betterments, are capitalized. Such
costs include direct material and labor, construction overhead and an allowance
for funds used during construction (AFUDC). AFUDC represents the estimated cost
of debt and equity funds that finance utility-plant construction. AFUDC is
capitalized during plant construction and reported in current earnings. AFUDC is
recovered in rates through depreciation expense over the useful life of the
related asset. Depreciation of utility plant is computed on a straight-line,
remaining-life basis.
Replaced or retired property and removal costs less salvage are charged to the
accumulated provision for depreciation. Depreciation expense stated as a percent
of average original cost of depreciable utility plant was 3.4%, 3.6% and 5.3%
for the three, nine and twelve months ended September 30, 1999, respectively,
and 3.4%, 4.6% and 5.1% for the three, nine and twelve months ended September
30, 1998, respectively.
SCE's net investment in generation-related utility plant was $1.0 billion, $1.1
billion and $1.0 billion at September 30, 1999, December 31, 1998, and September
30, 1998, respectively.
Note 2. Regulatory Matters
FERC Transmission Rate Case
SCE filed its first FERC transmission rate case in March 1997. The filing
proposed a transmission revenue requirement of $211 million. In March 1999, a
proposed FERC decision was issued recommending a return on equity of 9.68%
(compared to SCE's current CPUC rate for distribution of 11.6%) and a lower
revenue requirement. SCE filed briefs opposing the proposed decision in May
1999. In response to a recent FERC ruling, on November 1, 1999, SCE filed
additional evidence regarding return on equity. A final FERC decision is
expected in early 2000. SCE does not expect the final decision to have a
material effect on its results of operations or financial position.
9
<PAGE>
Recovery of Restructuring Implementation Costs
The independent system operator (ISO) assumed operational control of the
transmission system after the ISO and PX began accepting bids and schedules for
electricity purchases on March 31, 1998. The restructuring implementation costs
related to the start-up and development of the PX, which were paid by the
utilities, were to be recovered from all retail customers over the four-year
transition period. SCE's share of the charge is $45 million, plus interest and
fees. SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a 10-year period. In May 1998, SCE filed an
application with the CPUC to identify the categories of such costs (including
costs related to the implementation of direct access), and to establish the
reasonableness of those costs incurred in 1997.
On September 16, 1999, the CPUC approved a settlement between SCE, the CPUC's
Office of Ratepayer Advocates and several other parties allowing SCE to recover
substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation.
Note 3. Financial Instruments
Derivative Financial Instruments
SCE's risk management policy allows the use of derivative financial instruments
to manage financial exposure on its investments and fluctuations in interest
rates, but prohibits the use of these instruments for speculative or trading
purposes.
SCE uses the hedge accounting method to record its derivative financial
instruments, except for gas call options and PX block forward transactions.
Hedge accounting requires an assessment that the transaction reduces risk, that
the derivative be designated as a hedge at the inception of the derivative
contract, and that the changes in the market value of a hedge move in an inverse
direction to the item being hedged. Under hedge accounting, the derivative
itself is not recorded on SCE's balance sheet. Mark-to-market accounting would
be used if the hedge accounting criteria were not met. Interest rate
differentials and amortization of premiums for interest rate caps are recorded
as adjustments to interest expense. If the derivatives were terminated before
the maturity of the corresponding debt issuance, the realized gain or loss on
the transaction would be amortized over the remaining term of the debt.
SCE has gas call options that mitigate its exposure to increases in natural gas
prices. Increases in natural gas prices tend to increase the price of
electricity. The options cover various periods from 1998 through 2001. In July
1999, SCE began participating in the PX block forward market. In the PX block
forward market, SCE can purchase monthly blocks of energy for six days a week
(excluding Sundays and holidays) for 16 hours a day. These purchases can be made
up to 12 months in advance of the delivery date. The CPUC has currently limited
SCE's use of the PX block forward market to a maximum of approximately 2,400 MW
in any month.
SCE uses the mark-to-market accounting method for its gas call options. Gains
and losses from monthly changes in market prices are recorded as income or
expense. However, the costs of the options and the market price changes are
included in the transition cost balancing account. As a result, the
10
<PAGE>
mark-to-market gains or losses have no effect on earnings. Block forward
purchases receive the same accounting and ratemaking treatment as SCE's gas call
options.
Interest rate swaps are used to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At the balance sheet dates of
September 30, 1999, December 31, 1998, and September 30, 1998, SCE had an
interest rate swap agreement which fixed the interest rate at 5.585% for $196
million of debt due 2008; it expires February 28, 2008. The interest rate swap
agreement requires the parties to pledge collateral according to bond rating and
market interest rate changes. At September 30, 1999, SCE had pledged $26 million
as collateral due to a decline in market interest rates. SCE is exposed to
credit loss in the event of nonperformance by the counterparty to the agreement,
but does not expect the counterparty to fail to meet its obligation.
Fair Value of Financial Instruments
Fair values of financial instruments were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
In millions 1999 1998 1998
- -------------------------------------------------------------------------------------------------
Cost Fair Cost Fair Cost Fair
Instrument Basis Value Basis Value Basis Value
- -------------------------------------------------------------------------------------------------
Financial assets:
<S> <C> <C> <C> <C> <C> <C>
Decommissioning trusts $ 1,630 $ 2,327 $ 1,534 $ 2,240 $ 1,489 $ 2,013
Equity investments -- -- 7 72 9 88
Gas call options 31 23 39 31 42 50
Financial liabilities:
DOE decommissioning and
decontamination fees $ 45 $ 39 $ 45 $ 40 $ 50 $ 44
Interest rate swap -- 14 -- 28 -- 28
Long-term debt 5,222 5,214 5,447 5,699 5,486 5,756
Preferred stock subject to
mandatory redemption 256 261 256 274 256 276
- -------------------------------------------------------------------------------------------------
</TABLE>
Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts and equity investments and on financial models for
gas call options. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs for the interest rate
swap; brokers' quotes for long-term debt and preferred stock; and discounted
future cash flows for U.S. Department of Energy (DOE) decommissioning and
decontamination fees. Due to their short maturities, amounts reported for cash
equivalents and short-term debt approximate fair value.
Gross unrealized holding gains (losses) on financial assets were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
In millions 1999 1998 1998
- ----------------------------------------------------------------------------
Decommissioning trusts:
<S> <C> <C> <C>
Municipal bonds $ 179 $ 196 $ 162
Stocks 348 365 245
U.S. government issues 133 115 107
Short-term and other 37 30 10
- ----------------------------------------------------------------------------
697 706 524
Equity investments -- 65 79
Gas call options (8) (8) 8
- ----------------------------------------------------------------------------
Total $ 689 $ 763 $ 611
- ----------------------------------------------------------------------------
</TABLE>
11
<PAGE>
There were no unrealized holding losses on financial assets for the years
presented, other than the unrealized holding loss on the gas call options at
September 30, 1999, and December 31, 1998.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, requires all derivatives to be recognized on the balance sheet
at fair value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
Investments
Net unrealized gains (losses) on equity investments are recorded as accumulated
other comprehensive income. Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
affiliates that are not rate-regulated.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged
first and refunding mortgage bonds as security for borrowed funds obtained from
pollution-control bonds issued by government agencies. SCE used these proceeds
to finance construction of pollution-control facilities. Bondholders have
limited discretion in redeeming certain pollution-control bonds, and SCE has
arranged with securities dealers to remarket or purchase them if necessary.
Debt premium, discount and issuance expenses are amortized over the life of each
issue. Under CPUC rate-making procedures, debt reacquisition expenses are
amortized over the remaining life of the reacquired debt or, if refinanced, the
life of the new debt.
Commercial paper intended to be refinanced for a period exceeding one year and
used to finance nuclear fuel scheduled to be used more than one year after the
balance sheet date is classified as long-term debt.
Long-term debt maturities and sinking-fund requirements for the five
twelve-month periods following September 30, 1999, are: 2000 -- $568 million;
2001 -- $647 million; 2002 -- $247 million; 2003 -- $572 million; and 2004 --
$372 million.
In December 1997, SCE Funding LLC, a special purpose entity, of which SCE is the
sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. 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 pursuant to
the restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a
12
<PAGE>
non-bypassable rate charged to residential and small commercial customers.
Despite the legal sale of the transition property by SCE to SCE Funding LLC, the
amounts reflected as assets on SCE's balance sheet have not been reduced by the
amount of the transition property sold, and the liabilities of SCE Funding LLC
for the rate reduction notes are for accounting purposes reflected as long-term
debt on the consolidated balance sheets of SCE. SCE used the proceeds from the
sale of the transition property to retire debt and equity securities. The rate
reduction notes are secured solely by the transition property and certain other
assets of SCE Funding LLC, and there is no recourse to SCE or Edison
International.
Although SCE Funding LLC is consolidated with SCE in the financial statements,
as required by generally accepted accounting principles, 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.
Long-term debt consisted of:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
In millions 1999 1998 1998
- ---------------------------------------------------------------------------------------------
First and refunding mortgage bonds:
<S> <C> <C> <C> <C> <C> <C>
2000-- 2026 (5.625% to 7.25%) $ 1,400 $ 1,550 $ 1,550
Rate reduction notes:
2000-- 2007 (6.14% to 6.42%) 2,039 2,217 2,307
Pollution-control bonds:
2008-- 2031 (5.125% to 7.2% and variable) 1,196 1,201 1,201
Funds held by trustees (2) (2) (2)
Debentures and notes:
2000-- 2029 (5.875% to 8.25%) 1,000 700 870
Subordinated debentures:
2044 (8.375%) 100 100 100
Commercial paper for nuclear fuel 85 108 80
Long-term debt due within one year (568) (401) (593)
Unamortized debt discount-- net (28) (26) (27)
- ---------------------------------------------------------------------------------------------
Total $ 5,222 $ 5,447 $ 5,486
- ---------------------------------------------------------------------------------------------
</TABLE>
Short-Term Debt
SCE has lines of credit totaling $1.25 billion that can be used at negotiated or
bank index rates. At September 30, 1999, $50 million was available for
short-term debt and $515 million was available for the long-term refinancing of
certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel inventories
and general cash requirements. Commercial paper outstanding at September 30,
1999, December 31, 1998, and September 30, 1998, was $685 million, $581 million
and $187 million, respectively. Commercial paper intended to finance nuclear
fuel scheduled to be used more than one year after the balance sheet date is
classified as long-term debt in connection with refinancing terms under
five-year term lines of credit with commercial banks. Weighted-average interest
rates were 5.5%, 5.3% and 5.6% at September 30, 1999, December 31, 1998, and
September 30, 1998, respectively.
On October 25, 1999, SCE issued $175 million of floating rate notes due October
2000.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. At September 30, 1999, SCE had the capacity to pay
approximately $586 million in additional dividends and continue to maintain its
authorized capital structure.
13
<PAGE>
Changes in SCE's common shareholder's equity were as follows:
Three months ended September 30, 1998, and 1999:
<TABLE>
<CAPTION>
Accumulated Total
Additional Other Common
Common Paid-in Comprehensive Retained Shareholder's
In millions Stock Capital Income Earnings Equity
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at June 30, 1998 $ 2,168 $ 334 $ 61 $ 1,079 $ 3,642
- --------------------------------------------------------------------------------------------------------------------
Net income 169 169
Unrealized loss on securities (22) (22)
Dividends declared on common stock (422) (422)
Dividends declared on preferred stock (6) (6)
- --------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998 $ 2,168 $ 334 $ 39 $ 820 $ 3,361
- --------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1999 $ 2,168 $ 334 $ - $ 694 $ 3,196
- --------------------------------------------------------------------------------------------------------------------
Net income 169 169
Unrealized gain on securities 53 53
Tax effect (21) (21)
Reclassified adjustment for gains
included in net income (23) (23)
Tax effect 9 9
Dividends declared on common stock (269) (269)
Dividends declared on preferred stock (8) (8)
Capital stock expense 1 1
- -------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999 $ 2,168 $ 335 $ 18 $ 586 $ 3,107
- -------------------------------------------------------------------------------------------------------------------
Nine months ended September 30, 1998, and 1999:
In millions
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 $ 2,168 $ 334 $ 48 $ 1,408 $ 3,958
- -------------------------------------------------------------------------------------------------------------------
Net income 394 394
Unrealized loss on securities (2) (2)
Tax effect (7) (7)
Dividends declared on common stock (960) (960)
Dividends declared on preferred stock (19) (19)
Stock option appreciation (3) (3)
- -------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998 $ 2,168 $ 334 $ 39 $ 820 $ 3,361
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ 2,168 $ 334 $ 39 $ 794 $ 3,335
- -------------------------------------------------------------------------------------------------------------------
Net income 363 363
Unrealized gain on securities 42 42
Tax effect (17) (17)
Reclassified adjustment for gains
included in net income (77) (77)
Tax effect 31 31
Dividends declared on common stock (548) (548)
Dividends declared on preferred stock (20) (20)
Stock option appreciation (3) (3)
Capital stock expense 1 1
- -------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999 $ 2,168 $ 335 $ 18 $ 586 $ 3,107
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
14
<PAGE>
Twelve months ended September 30, 1998, and 1999:
<TABLE>
<CAPTION>
Accumulated Total
Additional Other Common
Common Paid-in Comprehensive Retained Shareholder's
In millions Stock Capital Income Earnings Equity
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at September 30, 1997 $ 2,168 $ 334 $ 37 $ 2,559 $ 5,098
- --------------------------------------------------------------------------------------------------------------------
Net income 516 516
Unrealized gain on securities 4 4
Tax effect (2) (2)
Dividends declared on common stock (2,227) (2,227)
Dividends declared on preferred stock (26) (26)
Stock option appreciation (2) (2)
- --------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998 $ 2,168 $ 334 $ 39 $ 820 $ 3,361
- --------------------------------------------------------------------------------------------------------------------
Net income 484 484
Unrealized gain on securities 58 58
Tax effect (15) (15)
Reclassified adjustment for gains
included in net income (107) (107)
Tax effect 43 43
Dividends declared on common stock (689) (689)
Dividends declared on preferred stock (26) (26)
Stock option appreciation (3) (3)
Capital stock expense 1 1
- -------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999 $ 2,168 $ 335 $ 18 $ 586 $ 3,107
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
Authorized common stock is 560 million shares with no par value. Authorized
shares of preferred and preference stock are: $25 cumulative preferred -- 24
million; $100 cumulative preferred -- 12 million; and preference -- 50 million.
All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund provisions.
When preferred shares are redeemed, the premiums paid are charged to common
equity.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1999, are: 2000 and 2001 -- zero; 2002 -- $105 million;
2003 -- $9 million; and 2004 -- $9 million.
15
<PAGE>
Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
Dollars in millions, except per share amounts 1999 1998 1998
- -------------------------------------------------------------------------------------------------------------
September 30, 1999
-------------------------
Shares Redemption
Outstanding Price
-------------------------
Not subject to mandatory redemption:
$25 par value:
<S> <C> <C> <C> <C> <C>
4.08% Series 1,000,000 $25.50 $ 25 $ 25 $ 25
4.24 1,200,000 25.80 30 30 30
4.32 1,653,429 28.75 41 41 41
4.78 1,296,769 25.80 33 33 33
- ------------------------------------------------------------------------------------------------------------
Total $ 129 $ 129 $ 129
- ------------------------------------------------------------------------------------------------------------
Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000 $100.00 $ 75 $ 75 $ 75
6.45 1,000,000 100.00 100 100 100
7.23 807,000 100.00 81 81 81
- -----------------------------------------------------------------------------------------------------------
Total $ 256 $ 256 $ 256
- -----------------------------------------------------------------------------------------------------------
</TABLE>
In the third quarter of 1998, 10,000 shares of Series 7.23% preferred stock were
redeemed. In the second quarter of 1998, 2.2 million shares of Series 5.80%
preferred stock and 183,000 shares of Series 7.23% were redeemed. There were no
preferred stock issuances for the periods presented.
Note 5. Income Taxes
SCE and its subsidiaries will be included in Edison International's consolidated
federal income tax and combined state franchise tax returns. Under income tax
allocation agreements, each subsidiary calculates its own tax liability.
Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. Investment tax credits are
amortized over the lives of the related properties.
16
<PAGE>
The components of the net accumulated deferred income tax liability were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
In millions 1999 1998 1998
- -----------------------------------------------------------------------------------------------------
Deferred tax assets:
<S> <C> <C> <C>
Property-related $ 196 $ 197 $ 208
Unrealized gains or losses 408 387 --
Investment tax credits 133 152 153
Regulatory balancing accounts 133 96 84
Decommissioning-related 129 126 801
Unbilled revenue 124 117 147
Other 396 356 34
- ------------------------------------------------------------------------------------------------------
Total $ 1,519 $ 1,431 $ 1,427
- ------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $ 2,685 $ 3,005 $ 3,046
Capitalized software costs 236 196 173
Regulatory balancing accounts 434 162 62
Unrealized gains and losses 306 284 240
Other 484 502 517
- ------------------------------------------------------------------------------------------------------
Total $ 4,145 $ 4,149 $ 4,038
- ------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net $ 2,626 $ 2,718 $ 2,611
- ------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $ 2,769 $ 2,993 $ 2,880
Included in current assets 143 275 269
</TABLE>
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- ----------------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------
Current:
<S> <C> <C> <C> <C> <C> <C>
Federal $ 199 $ 96 $ 263 $ 452 $ 261 $ 486
State 52 22 69 100 70 105
- ----------------------------------------------------------------------------------------------------------------
251 118 332 552 331 591
- ----------------------------------------------------------------------------------------------------------------
Deferred -- federal and state:
Accrued charges (54) (10) (38) (24) (57) (33)
Amortization of regulatory assets 10 63 22 53 33 53
Depreciation (52) (22) (148) (106) (211) (115)
Investment and energy tax credits-- net (11) (6) (32) (22) (85) (27)
Regulatory balancing accounts 61 152 198 36 339 66
State tax-- privilege year (17) (7) 10 -- 10 (2)
Unbilled revenue (21) (100) (7) (98) 23 (51)
Other (11) (2) (7) 15 (16) 43
- ----------------------------------------------------------------------------------------------------------------
(95) 68 (2) (146) 36 (66)
- ----------------------------------------------------------------------------------------------------------------
Total income tax expense $ 156 $ 186 $ 330 $ 406 $ 367 $ 525
- ----------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income $ 154 $ 172 $ 317 $ 397 $ 366 $ 541
Included in other income 2 14 13 9 1 (16)
</TABLE>
The composite federal and state statutory income tax rate was 40.551% for the
three, nine and twelve months ended September 30, 1999, and 1998.
17
<PAGE>
The federal statutory income tax rate is reconciled to the effective tax rate
below:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- --------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Ad valorem lien date adjustment (0.2) 3.0 0.3 1.6 (0.5) 1.2
Amortization of regulatory assets 2.7 17.7 2.8 6.6 3.5 5.0
Capitalized software (4.3) 1.0 (2.7) (0.1) (2.8) (0.5)
Property-related and other 9.0 (8.8) 8.0 2.5 8.7 4.8
Investment and energy tax credits (3.2) (1.2) (4.5) (1.6) (9.7) (1.7)
State tax-- net of federal deduction 8.9 5.8 8.5 6.3 8.7 6.3
- --------------------------------------------------------------------------------------------------------
Effective tax rate 47.9% 52.5% 47.4% 50.3% 42.9% 50.1%
- --------------------------------------------------------------------------------------------------------
</TABLE>
Note 6. Employee Compensation and Benefit Plans
Employee Savings Plan
SCE has a 401(k) defined contribution savings plan designed to supplement
employees' retirement income. The plan received employer contributions of $6
million, $18 million and $23 million for the three, nine and twelve months ended
September 30, 1999, respectively, and $4 million, $12 million and $16 million
for the three, nine and twelve months ended September 30, 1998, respectively.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers employees
meeting minimum service requirements. In April 1999, SCE adopted a cash balance
feature for its non-represented employees. SCE recognizes pension expense as
calculated by the actuarial method used for ratemaking. In 1998, SCE adopted a
new accounting standard that revises the disclosure requirements for pension
plans. Prior periods have been restated.
18
<PAGE>
Information on plan assets and benefit obligations is shown below:
<TABLE>
<CAPTION>
9 Months Ended Year Ended 9 Months Ended
September 30, December 31, September 30,
In millions 1999 1998 1998
- --------------------------------------------------------------------------------------------------------
Change in benefit obligation
<S> <C> <C> <C>
Benefit obligation at beginning of period $ 2,251 $ 2,094 $ 2,094
Service cost 50 59 42
Interest cost 114 141 105
Plan amendments (25) -- --
Actuarial loss -- 90 --
Benefits paid (105) (133) (103)
- --------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 2,285 $ 2,251 $ 2,138
- --------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 2,552 $ 2,298 $ 2,298
Actual return on plan assets 241 334 63
Employer contributions 51 53 43
Benefits paid (105) (133) (103)
- -------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 2,739 $ 2,552 $ 2,301
- -------------------------------------------------------------------------------------------------------
Funded status $ 454 $ 301 $ 163
Unrecognized net loss (gain) (463) (372) (227)
Unrecognized transition obligation (17-year amortization) 30 33 35
Unrecognized prior service cost 133 168 169
- -------------------------------------------------------------------------------------------------------
Pension asset (liability) $ 154 $ 130 $ 140
- ------------------------------------------------------------------------------------------------------
Discount rate 6.75% 6.75% 7.0%
Rate of compensation increase 5.0% 5.0% 5.0%
Expected return on plan assets 7.5% 7.5% 8.0%
</TABLE>
The components of pension expense were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- ------------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 16 $ 14 $ 50 $ 42 $ 67 $ 53
Interest cost 38 35 114 105 150 139
Expected return on plan assets (48) (45) (144) (135) (179) (175)
Net amortization and deferral 2 4 7 12 9 13
- ------------------------------------------------------------------------------------------------------------
Pension expense under accounting standards 8 8 27 24 47 30
Regulatory adjustment-- deferred 5 5 12 15 8 22
- ------------------------------------------------------------------------------------------------------------
Net pension expense recognized $ 13 $ 13 $ 39 $ 39 $ 55 $ 52
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service are
eligible for postretirement health and dental care, life insurance and other
benefits. In 1998, SCE adopted a new accounting standard that revises the
disclosure requirements for postretirement benefit plans. Prior periods have
been restated.
19
<PAGE>
Information on plan assets and benefit obligations is shown below:
<TABLE>
<CAPTION>
9 Months Ended Year Ended 9 Months Ended
September 30, December 31, September 30,
In millions 1999 1998 1998
- -----------------------------------------------------------------------------------------------------------
Change in benefit obligation
<S> <C> <C> <C>
Benefit obligation at beginning of period $ 1,545 $ 1,533 $ 1,533
Service cost 33 41 27
Interest cost 78 99 78
Actuarial loss (gain) -- (74) --
Benefits paid (45) (54) (48)
- -----------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 1,611 $ 1,545 $ 1,590
- -----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 1,029 $ 815 $ 815
Actual return on plan assets 57 147 48
Employer contributions 75 121 81
Benefits paid (45) (54) (48)
- ----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 1,116 $ 1,029 $ 896
- ----------------------------------------------------------------------------------------------------------
Funded status $ (495) $ (516) $ (694)
Unrecognized net loss 84 84 241
Unrecognized transition obligation (20-year
amortization) 355 376 382
- ----------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (56) $ (56) $ (71)
- ----------------------------------------------------------------------------------------------------------
Discount rate 6.75% 6.75% 7.0%
Expected return on plan assets 7.5% 7.5% 8.0%
</TABLE>
The components of postretirement benefits other than pension expense were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
- -------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 11 $ 9 $ 33 $ 27 $ 47 $ 36
Interest cost 26 26 78 78 99 102
Expected return on plan assets (19) (16) (57) (48) (71) (59)
Amortization of loss (gain) -- 1 -- 3 (2) 1
Amortization of transition obligation 7 7 21 21 27 27
- -------------------------------------------------------------------------------------------------
Total expense $ 25 $ 27 $ 75 $ 81 $ 100 $ 107
- -------------------------------------------------------------------------------------------------
</TABLE>
The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1999, gradually decreasing to 5.0% for 2009 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of September 30, 1999, by $275 million
and annual aggregate service and interest costs by $34 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of September 30, 1999, by $220 million and annual
aggregate service and interest costs by $26 million.
Stock Option Plans
In April 1998, Edison International shareholders approved the Edison
International Equity Compensation Plan. The plan replaces the Long-Term
Incentive Compensation Program, consisting of officer, director, and management
plans, which was adopted by Edison International shareholders in 1992. No new
awards will be made under the prior program; however, it will remain in effect
as long as any awards remain outstanding under the prior program.
20
<PAGE>
The prior program participated in the use of 8.2 million shares of common stock
reserved for potential issuance under various stock compensation programs to
directors, officers and senior managers of Edison International and its
affiliates. Under these programs, options on 2.8 million shares of Edison
International common stock are currently outstanding to officers and senior
managers.
The new plan authorizes the annual issuance of shares equal to one percent of
the issued and outstanding shares of Edison International common stock as of
December 31 of the prior year. This authorization is cumulative so that to the
extent shares are not needed to meet new plan requirements in any year, the
excess authorized shares carry over to subsequent years until plan termination.
One percent of the issued and outstanding Edison International common stock on
December 31, 1998, and December 31, 1997, was 3.5 million and 3.8 million
shares, respectively. Under the new plan, options on 4.0 million shares of
Edison International common stock are currently outstanding to officers and
senior managers of SCE.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. All Edison International stock
options granted prior to 1999 include a dividend equivalent feature. Generally,
for options issued before 1994, amounts equal to dividends accrue on the options
at the same time and at the same rate as would be payable on the number of
shares of Edison International common stock covered by the options. The amounts
accumulate without interest. For Edison International stock options issued after
1993, dividend equivalents are subject to reduction unless certain shareholder
return performance criteria are met. Beginning with the 1999 Edison
International stock option awards, some stock options include a dividend
equivalent feature, and some stock options do not include a dividend equivalent
feature.
The new plan's stock options have a 10-year term with one-fourth of the total
award vesting after each of the first four years of the award term. The prior
program's stock options have a 10-year term with one-third of the total award
vesting after each of the first three years of the award term. If an optionee
retires, dies or is permanently and totally disabled during the vesting period,
the unvested options will vest and be exercisable to the extent of 1/36 (prior
program) or 1/48 (the new plan) of the grant for each full month of service
during the vesting period.
Unvested options of any person who has served in the past on the Edison
International or SCE Management Committee (which was dissolved in 1993) will
vest and be exercisable upon the member's retirement, death or permanent and
total disability. Upon retirement, death or permanent and total disability, the
vested options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by retirement,
death or permanent and total disability, options which had vested as of the
prior anniversary date of the grant are forfeited unless exercised within 180
days of the date of termination. All unvested options are forfeited on the date
of termination.
SCE measures compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the
stock-compensation program was $2 million, $3 million and $5 million for the
three, nine and twelve months ended September 30, 1999, respectively, and $1
million, $8 million and $9 million for the three, nine and twelve months ended
September 30, 1998, respectively.
Stock-based compensation expense under the fair-value method of accounting would
have resulted in pro forma earnings of $160 million, $342 million and $458
million for the three, nine and twelve months ended September 30, 1999,
respectively; and $163 million, $377 million and $492 million for the three,
nine and twelve months ended September 30, 1998, respectively.
21
<PAGE>
The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:
12 Months Ended
September 30,
- ---------------------------------------------------------
1999 1998
- ---------------------------------------------------------
Expected life 7 years 7 years
Risk-free interest rate 4.7% - 5.6% 4.7% - 5.6%
Expected volatility 17% - 18% 17%
- ---------------------------------------------------------
The application of fair-value accounting to calculate the pro forma disclosures
above is not an indication of future income statement effects. The pro forma
disclosures do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.
Note 7. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems for
which each participant provides its own financing. SCE's share of expenses for
each project is included in the consolidated statements of income.
The investment in each project, as included in the consolidated balance sheet as
of September 30, 1999, was:
<TABLE>
<CAPTION>
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
- ---------------------------------------------------------------------------------------------
Transmission systems:
<S> <C> <C> <C> <C>
Eldorado $ 36 $ 6 $ 3 60%
Pacific Intertie 241 81 6 50%
Generating stations:
Four Corners Units 4 and 5 (coal) 460 320 2 48%
Mohave (coal) 321 210 3 56%
Palo Verde (nuclear)(1) 1,608 1,091 16 16%
San Onofre (nuclear)(1) 4,264 3,139 22 75%
- -------------------------------------------------------------------------------------------
Total $ 6,930 $ 4,847 $ 52
- --------------------------------------------------------------------------------------------
</TABLE>
(1) Reported as "Unamortized nuclear investment -- net."
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.
Estimated remaining commitments for noncancelable leases at September 30, 1999,
were:
Year ended December 31, In millions
- -------------------------------------------
1999 $ 3
2000 13
2001 10
2002 6
2003 5
Thereafter 9
- -------------------------------------------
Total $ 46
- -------------------------------------------
22
<PAGE>
Note 9. Commitments
Nuclear Decommissioning
Decommissioning is estimated to cost $1.9 billion in current-year dollars, based
on site-specific studies performed in 1998 for San Onofre and Palo Verde.
Changes in the estimated costs, timing of decommissioning, or the assumptions
underlying these estimates could cause material revisions to the estimated total
cost to decommission in the near term. SCE estimates that it will spend
approximately $8.6 billion through 2060 to decommission its nuclear facilities.
This estimate is based on SCE's current dollar decommissioning costs, escalated
at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.
These costs are expected to be funded from independent decommissioning trusts,
which, effective June 3, 1999, receive contributions of approximately $25
million per year. SCE estimates annual after-tax earnings on the decommissioning
funds of 3.9% to 4.9%.
SCE plans to decommission its nuclear generating facilities by a prompt removal
method authorized by the Nuclear Regulatory Commission. Decommissioning is
expected to begin after the plants' operating licenses expire. The operating
licenses expire in 2013 for San Onofre Units 2 and 3, and 2025-2027 for Palo
Verde. Decommissioning costs, which are accrued and recovered through
non-bypassable customer rates over the term of each nuclear facility's operating
license, are recorded as a component of depreciation expense.
In June 1999, the CPUC authorized SCE to access its nuclear decommissioning
trust funds to commence decommissioning of San Onofre Unit 1 (shut down in 1992
pursuant to a CPUC agreement) effective immediately.
Decommissioning expense was $34 million, $103 million and $149 million for the
three, nine and twelve months ended September 30, 1999, respectively, and $41
million, $119 million and $155 million for the three, nine and twelve months
ended September 30, 1998, respectively. The accumulated provision for
decommissioning, excluding San Onofre Unit 1, was $1.3 billion at September 30,
1999, and $1.2 billion at both December 31, 1998, and September 30, 1998. The
estimated costs to decommission San Onofre Unit 1 ( approximately $360 million)
are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Trust investments (cost basis) include:
<TABLE>
<CAPTION>
Maturity September 30, December 31, September 30,
In millions Dates 1999 1998 1998
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Municipal bonds 2000 - 2033 $ 571 $ 547 $ 537
Stocks - 503 550 543
U.S. government issues 1999 - 2029 447 355 396
Short-term and other 1999 - 2030 109 82 13
- --------------------------------------------------------------------------------------------
Total $ 1,630 $ 1,534 $ 1,489
- --------------------------------------------------------------------------------------------
</TABLE>
Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $25
million, $49 million and $68 million for the three, nine and twelve months ended
September 30, 1999, respectively; and $17 million, $44 million and $55 million
for the three, nine and twelve months ended September 30, 1998, respectively.
Proceeds from sales of securities (which are reinvested) were $776 million, $1.8
billion and $2.1 billion for the three, nine and twelve months ended September
30, 1999, respectively; and $342 million, $911 million and $1.1 billion for the
three, nine and twelve months ended September 30, 1998, respectively.
Approximately 90% of the trust fund contributions were tax-deductible.
23
<PAGE>
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase. Additionally, SCE's gas and coal fuel contracts require
payment of certain fixed charges whether or not gas or coal is delivered.
SCE has power-purchase contracts with certain qualifying facilities (QF)
(cogenerators and small power producers) and other utilities. These contracts
provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There are
no requirements to make debt-service payments. As a result of the utility
industry restructuring, SCE has entered into purchased-power settlements to end
its contract obligations with certain QFs. The settlements (approximately $300
million) are reported as long-term liabilities. Settlement payments are being
recovered through the CTC.
SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another utility.
Minimum payments are based, in part, on the debt-service requirements of the
provider, whether or not the plant or transmission line is operable. SCE's
minimum commitment under both contracts is approximately $172 million through
2017. The purchased-power contract (approximately $30 million) is expected to
provide approximately 5.5% of current or estimated future operating capacity,
and is reported as a long-term liability. The transmission service contract
requires a minimum payment of approximately $6 million a year.
Certain commitments for the years 1999 through 2003 are estimated below:
<TABLE>
<CAPTION>
In millions 1999 2000 2001 2002 2003
- ---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Projected construction expenditures $ 975 $ 940 $ 891 $ 860 $ 856
Fuel supply contracts 168 138 124 140 133
Purchased-power capacity payments 654 629 627 625 620
- ---------------------------------------------------------------------------
</TABLE>
Note 10. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in other
legal, tax and regulatory proceedings before various courts and governmental
agencies regarding matters arising in the ordinary course of business. SCE
believes the outcome of these other proceedings will not materially affect its
results of operations or liquidity.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
SCE records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site using
currently available information, including existing technology, presently
enacted laws and regulations, experience gained at similar sites, and the
probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, SCE records the lower end of this reasonably likely
range of costs (classified as other long-term liabilities at undiscounted
amounts).
24
<PAGE>
SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $165 million. The ultimate costs to clean up SCE's identified sites may vary
from its recorded liability due to numerous uncertainties inherent in the
estimation process, such as: the extent and nature of contamination; the
scarcity of reliable data for identified sites; the varying costs of alternative
cleanup methods; developments resulting from investigatory studies; the
possibility of identifying additional sites; and the time periods over which
site remediation is expected to occur. SCE believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed its
recorded liability by up to $284 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. SCE has sold all of its gas- and oil-fueled
generation plants and has retained some liability associated with the divested
properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $85 million of its recorded liability, through an incentive
mechanism (SCE may request to include additional sites). Under this mechanism,
SCE will recover 90% of cleanup costs through customer rates; shareholders fund
the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $130 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can now be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$5 million to $15 million. Recorded costs for the twelve-month period ended
September 30, 1999, were $15 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.8
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from
this secondary level, effective June 1994. The maximum deferred premium for each
nuclear incident is $88 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its ownership
interests, SCE could be required to pay a maximum of $175 million per nuclear
incident. However, it would have to pay no more than $20 million per incident in
any one year. Such amounts include a 5% surcharge if additional funds are needed
to satisfy public liability claims and are subject to adjustment for inflation.
If the public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
25
<PAGE>
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 $21 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the DOE is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste.
Such a facility was to be in operation by January 1998. However, the DOE did not
meet its obligation. It is not certain when the DOE will begin accepting spent
nuclear fuel from San Onofre or from other nuclear power plants.
SCE 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. Meeting spent-fuel storage requirements beyond that
period would require new and separate interim storage facilities, the costs for
which have not been determined. 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 2002
for Units 1 and 2, and until 2003 for Unit 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.
SCE and other owners of nuclear power plants may be able to recover interim
storage costs arising from DOE delays in the acceptance of utility spent nuclear
fuel by pursuing relief under the terms of the contracts, as directed by the
courts, or through other court actions.
26
<PAGE>
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
Results of Operations
Earnings
Southern California Edison Company's (SCE) earnings for the three, nine and
twelve months ended September 30, 1999, were $160 million, $343 million and $458
million, respectively, compared with $163 million, $375 million and $491 million
for the same periods in 1998. The year-to-date and twelve-months-ended decreases
were mainly due to the scheduled refueling outages at the San Onofre Nuclear
Generating Station during the first half of 1999.
Operating Revenue
As a result of industry restructuring, customers have an option to buy power
from SCE or directly from the power exchange (PX), thus becoming direct access
customers. Direct access customers are continuing to be billed by SCE, but are
also given a credit for the generation portion of their bills. Operating revenue
decreased 3% for the three months ended September 30, 1999, compared to the
year-earlier period, primarily due to a credit given to customers who choose
direct access. Operating revenue increased for the nine months ended September
30, 1999, compared to the same period last year. The increase resulted primarily
from maintenance service SCE is providing the new owners of the divested gas-
and oil-fueled plants, partially offset by the energy credit given to direct
access customers in the third quarter of 1999. Over 93% of operating revenue was
from retail sales. Retail rates are regulated by the California Public Utilities
Commission (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.
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction for residential and small commercial customers beginning in 1998
and other rates to remain frozen at June 1996 levels (system average of
10.1(cent) per kilowatt-hour). See the discussion in Regulatory Environment
below.
Operating Expenses
Fuel expense decreased 33% and 40%, respectively, for the nine and twelve months
ended September 30, 1999, compared with the same periods in 1998. The decreases
resulted from the sale of the generating plants in 1998.
Since April 1, 1998, SCE has been required to sell all of its generated power
through the PX and acquire all of its power through the PX to distribute to its
customers. These transactions with the PX are reported net. PX purchased-power
expense decreased for the quarter ended September 30, 1999, compared to the
year-earlier period, due to lower prices and lower volume of purchases during
the third quarter of 1999. The lower volume was partially due to an increase in
direct access customers. PX purchased-power expense increased for the
year-to-date and twelve-months ended periods due to higher prices in May and
June of 1999. There were no comparable purchases during the first quarter of
1998. SCE is continuing to purchase power under existing contracts from certain
nonutility generators (known as qualifying facilities) and from other utilities.
This purchased power is also sold through the PX. Purchased-power expense --
contracts decreased for the three, nine and twelve months ended September 30,
1999, compared to the same periods last year, primarily due to SCE entering into
settlements to end its contractual obligations with certain qualifying
facilities. SCE was required under federal law to purchase power from certain
qualifying facilities at CPUC-mandated prices even though energy and capacity
prices under these contracts are generally higher than other sources. For the
twelve months ended September 30, 1999, SCE paid about $1.5 billion (including
energy and capacity payments) more for these power purchases than the cost of
power available from other sources.
27
<PAGE>
Provisions for regulatory adjustment clauses increased for the three months
ended September 30, 1999, compared to the year-earlier period. The quarterly
increase primarily reflects overcollections related to the difference between
generation-related revenue and generation-related costs and overcollections
related to the administration of public purpose funds. These overcollections
were partially offset by revenue deferrals related to the rate-making treatment
of the rate reduction notes. This rate-making treatment has allowed for the
deferral of the recovery of a portion of the transition-related costs, from a
four-year period to a 10-year period. Provisions for regulatory adjustment
clauses decreased for the nine and twelve months ended September 30, 1999,
compared to same periods last year. These decreases were mainly due to
undercollections related to the difference between generation-related revenue
and generation-related costs and the rate-making treatment of the rate reduction
notes. These undercollections were partially offset by overcollections related
to the administration of public purpose funds. See the discussion in Revenue and
Cost-Recovery Mechanisms.
Other operating expenses decreased 16% for the three months ended September 30,
1999, compared to the same period in 1998, primarily due to a reduction in
mandated transmission service (known as must-run reliability services) expenses
due to a new calculation method adopted by the FERC, partially offset by an
increase in grid management payments to the independent system operator (ISO).
Other operating expenses increased for the nine and twelve months ended
September 30, 1999, mostly due to increases in direct access activities and PX
costs incurred by SCE in early 1999. These increases were partially offset by
the decrease in the third quarter discussed above.
Maintenance expense decreased 19% for the quarter ended September 30, 1999,
compared to the year-earlier period, mainly due to lower expenses incurred at
distribution facilities.
Depreciation, decommissioning and amortization expense increased for the three,
nine and twelve months ended September 30, 1999, compared to the prior-year
periods, primarily due to the recovery of direct-access related items as a
result of a recent CPUC decision. The twelve-months-ended increase also reflects
the amortization of the loss on the sales of the generating plants in 1998. The
amortization of the loss on plant sales is part of the competition transition
charge (CTC) mechanism.
Income taxes decreased for the three, nine and twelve months ended September 30,
1999, compared to the same periods in 1998, primarily due to the increased tax
expense associated with the gain on plant sales in 1998. The year-to-date and
twelve-months-ended decreases are also due to lower pre-tax income for those
periods. In addition, the twelve-months-ended decrease resulted from the
increased tax expense associated with CTC amortization in the 1998 period.
Net loss (gain) on sale of utility plant resulted from the sale of SCE's 12 gas-
and oil-fueled generation plants in 1998. Gains were used to reduce stranded
costs. Losses will be recovered from customers over the transition period.
Other Income
The provision for rate phase-in plan reflected a CPUC-authorized, 10-year rate
phase-in plan, which deferred the collection of revenue during the first four
years of operation for the Palo Verde units. The deferred revenue (including
interest) was collected evenly over the final six years of each unit's plan. The
plan ended in February 1996, September 1996 and January 1998 for Units 1, 2 and
3, respectively. The provision was a non-cash offset to the collection of
deferred revenue.
Other nonoperating income decreased for the three months ended September 30,
1999, compared to the prior-year period, primarily due to additional accruals
for regulatory matters in 1999 and the reversal of an accrual in 1998, partially
offset by the gain on sale of an equity investment. Other nonoperating income
increased for the both the nine and twelve months ended September 30, 1999,
mostly due to the gain on sales of equity investments, partially offset by the
third quarter decreases discussed above. The twelve-months-ended increase also
reflects regulatory accruals made in the fourth quarter of 1997.
28
<PAGE>
Interest Expense
Other interest expense increased 30% and 28%, respectively, for the three and
nine months ended September 30, 1999, compared to the same periods in 1998,
mostly due to higher overall short-term debt balances necessary to meet general
cash requirements during the periods.
Financial Condition
SCE's liquidity is primarily affected by debt maturities, dividend payments and
capital expenditures. Capital resources include cash from operations and
external financings.
Edison International's board of directors has authorized the repurchase of up to
$2.8 billion (increased from $2.3 billion in July 1998) of its outstanding
shares of common stock. Edison International repurchased approximately 101
million shares ($2.4 billion) between January 1995 and February 28, 1999, funded
by dividends from its subsidiaries and the proceeds of the rate reduction notes
issuance.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $596 million, $1.4 billion and
$1.6 billion, respectively, for the three, nine and twelve months ended
September 30, 1999, compared with $181 million, $870 million and $1.3 billion
for the same periods in 1998. Cash from operations exceed capital requirements
for all periods presented. SCE's cash flow coverage of dividends for the three,
nine and twelve months ended September 30, 1999, was 2.2 times, 2.6 times and
2.2 times, respectively, compared to 0.4 times, 0.9 times and 0.6 times for the
year-earlier periods. The increases in 1999 primarily reflect the special
dividends SCE paid to Edison International ($350 million in second quarter 1998,
$330 million in third quarter 1998 and $1.2 billion in December 1997 from the
rate reduction note proceeds).
Cash Flows from Financing Activities
At September 30, 1999, SCE had total credit lines of $1.25 billion, with $50
million available for short-term debt and $515 million available for the
long-term refinancing of its variable-rate pollution-control bonds. These
unsecured lines of credit are at negotiated or bank index rates and expire in
2002.
Short-term debt is used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital expenditures.
External financings are influenced by market conditions and other factors,
including limitations imposed by SCE's articles of incorporation and trust
indenture. As of September 30, 1999, SCE could issue approximately $11.2 billion
of additional first and refunding mortgage bonds and $2.9 billion of preferred
stock at current interest and dividend rates.
California law prohibits SCE from incurring or guaranteeing debt for its
affiliates that are not rate-regulated. Additionally, the CPUC regulates SCE's
capital structure, limiting the dividends it may pay Edison International. At
September 30, 1999, SCE had the capacity to pay approximately $586 million in
additional dividends and continue to maintain its authorized capital structure.
In December 1997, SCE Funding LLC, a special purpose entity, of which SCE is the
sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. 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 pursuant to
the restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a non-bypassable rate
charged to residential and small commercial customers. Despite the legal sale of
the transition property by SCE to SCE Funding LLC, the amounts reflected as
29
<PAGE>
assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to SCE Funding LLC, and the liabilities of SCE Funding
LLC for the rate reduction notes are for accounting purposes reflected as
long-term liabilities on the consolidated balance sheet of SCE. SCE used the
proceeds from the sale of the transition property to retire debt and equity
securities.
The remaining series of outstanding rate reduction notes have scheduled
maturities beginning in 2000 and ending in 2007, with interest rates ranging
from 6.14% to 6.42%. The rate reduction notes are secured solely by the
transition property and certain other assets of SCE Funding LLC, and there is no
recourse to SCE or Edison International.
Although SCE Funding LLC is consolidated with SCE in the financial statements,
as required by generally accepted accounting principles, 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.
On October 25, 1999, SCE issued $175 million of floating rate notes, due October
2000.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, proceeds from the sale of generating plants (see the discussion in
Regulatory Environment below) and funding of nuclear decommissioning trusts.
Decommissioning costs are accrued and recovered in rates over the term of each
nuclear generating facility's operating license. SCE estimates that it will
spend approximately $8.6 billion through 2060 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar decommissioning costs
($1.9 billion), escalated at rates ranging from 0.3% to 10.0% (depending on the
cost element) annually. These costs are expected to be funded from independent
decommissioning trusts which receive SCE contributions of approximately $25
million per year.
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in energy prices and
interest rates. SCE's risk management policy allows the use of derivative
financial instruments to manage its financial exposures, but prohibits the use
of these instruments for speculative or trading purposes.
As a result of the rate freeze established in the restructuring legislation,
SCE's transition costs are recovered as the residual component of rates once the
costs for distribution, transmission, public purpose programs, nuclear
decommissioning and the cost of supplying power to its customers through the PX
and ISO have already been recovered. Accordingly, more revenue will be available
to cover transition costs when market prices in the PX and ISO are low than when
PX and ISO prices are high. The PX and ISO market prices to date have generally
been reasonable, although some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap on the market for such services
until certain actions have been completed to improve the functioning of those
markets. Similarly, the ISO currently maintains a cap on its market for
imbalance energy until adequate measures to improve the efficient operation of
the market have been implemented. The caps in these markets mitigate the risk of
costly price spikes that would reduce the revenue available to SCE to pay
transition costs. The price cap instituted by the ISO in the summer of 1998 was
$250/MWh. In October 1999, that cap was raised to $750/MWh and will remain at
that level through the summer of 2000, unless certain identified market
improvements do not occur. Under such circumstances, the price cap will be
reduced to $500/MWh. SCE has entered into hedges against high natural gas
prices, since increases in natural gas prices tend to raise the price of
electricity.
In July 1999, SCE began participating in forward purchases through a PX block
forward market. In the PX block forward market, SCE can purchase monthly blocks
of energy for six days a week (excluding Sundays and holidays) for 16 hours a
day. These purchases can be made up to 12 months in advance of the delivery
date. The CPUC has currently limited SCE's use of the PX block forward market to
a maximum of approximately 2,400 MW in any month. SCE requested permission from
the CPUC to begin a pilot demand responsiveness program that would allow
customers to be paid to curtail their load during times of very high prices.
This request was denied for 1999, but SCE will continue to work with the CPUC
and others to implement some form of demand responsiveness programs prior to the
summer of 2000.
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A 10% increase in market interest rates would result in a $7 million increase in
the fair value of SCE's interest rate hedge agreements. A 10% decrease in market
interest rates would result in a $7 million decline in the fair market value of
interest rate hedge agreements. A 10% increase in natural gas prices would
result in a $21 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in a $13 million decline in the
fair market value of gas call options. A 10% change in market rates is expected
to have an immaterial effect on SCE's other financial instruments.
Projected Capital Requirements
SCE's projected construction expenditures for the next five years are: 1999--
$975 million; 2000-- $940 million; 2001-- $891 million; 2002-- $860 million; and
2003-- $856 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1999, are: 2000 -- $568 million;
2001 -- $647 million; 2002 -- $247 million; 2003 -- $572 million; and 2004 --
$372 million.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1999, are: 2000 and 2001 -- zero; 2002 -- $105 million;
2003 -- $9 million; and 2004 -- $9 million.
Regulatory Environment
SCE currently 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. This regulatory environment is changing
as a result of a 1995 CPUC decision on restructuring and state legislation
enacted in 1996. The Statute substantially adopted the CPUC's restructuring
decision by addressing stranded-cost recovery for utilities and providing a
certain cost-recovery time period for the transition costs associated with
generation-related assets. The Statute also 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. The Statute mandated
other rates to remain frozen at June 1996 levels (system average of 10.1(cent)
per kilowatt-hour), including those for large commercial and industrial
customers, and included provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the rate
freeze, SCE expects to be able to recover its revenue requirement during the
1998--2001 transition period. In addition, the Statute mandated the
implementation of the CTC (see the detailed discussion below) that provides
utilities the opportunity to recover costs made uneconomic by electric utility
restructuring.
Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation.
Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. 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 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 revenue is
being determined through FERC-authorized rates that are subject to refund.
SCE's transition costs are being recovered through a non-bypassable CTC. This
charge applies to all customers who were using or began using utility services
on or after the CPUC's December 1995 restructuring decision date. SCE has
estimated its transition costs to be approximately $10.6 billion (1998 net
present value) from 1998 through 2030. This estimate was based on incurred
costs, forecasts of future costs and assumed market prices. However, changes in
the assumed market prices could materially affect these estimates. Transition
costs related to power-purchase contracts are being recovered through the terms
of their contracts while most of the remaining transition costs will be
recovered through 2001. The potential transition costs are comprised of $6.4
billion from SCE's qualifying facilities contracts, which are the direct result
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of prior legislative and regulatory mandates, and $4.2 billion from costs
pertaining to certain generating assets (including the 1998 sale of SCE's
generating plants) and regulatory commitments consisting of costs incurred
(whose recovery has been deferred by the CPUC) to provide service to customers.
Such commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Units 2 and 3 and the Palo Verde units, and certain other
costs. During 1998, SCE sold all of its gas- and oil-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 stranded costs, which otherwise were
expected to be collected through the CTC mechanism. If events occur during the
restructuring process that result in all or a portion of the transition costs
being improbable of recovery, SCE could have write-offs associated with these
costs if they are not recovered through another regulatory mechanism.
Revenue from generation-related operations is being determined through the
competitive market and the CTC mechanism, which now includes the nuclear
rate-making agreements. The portion of revenue related to fossil and
hydroelectric generation operations that is made uneconomic by electric industry
restructuring is recovered through the CTC mechanism. The portion that is
economic is recovered through the market. SCE's costs associated with its
hydroelectric plants are being recovered through a performance-based mechanism.
The mechanism sets the hydroelectric revenue requirement and establishes a
formula for extending it through the duration of the electric industry
restructuring transition period, or until market valuation of the hydroelectric
facilities, whichever occurs first. The mechanism provides that power sales
revenue from hydroelectric facilities in excess of the hydroelectric revenue
requirement be credited against the costs to transition to a competitive market.
In 1999, fossil and hydroelectric generation assets have the opportunity to earn
a 7.22% return.
SCE is recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return. SCE's nuclear assets
are earning an annual rate of return of 7.35%. In addition, the San Onofre plan
authorizes a fixed rate of approximately 4(cent) per kilowatt-hour generated for
operating costs including incremental capital costs, and nuclear fuel and
nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and
ends in December 2001 for the accelerated recovery portion and in December 2003
for the incentive-pricing portion. Palo Verde'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. Beginning January 1, 1998, both the San
Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
The changes in distribution, transmission and generation revenue from the
regulatory mechanisms discussed above, excluding the effects of other rate
actions, are expected to have an approximately $20 million negative impact on
1999 earnings.
In March 1997, SCE filed its first FERC transmission rate case. In March 1999, a
proposed FERC decision was issued which recommended a reduced rate of return on
equity of 9.68% (compared to SCE's current CPUC rate for distribution of 11.6%)
and a reduced return on transmission assets of 8.41% (compared to the current
rate of 9.43% being earned on transmission assets). SCE filed comments opposing
the proposed decision in May 1999. In response to a recent FERC ruling, on
November 1, 1999, SCE filed additional evidence regarding return on equity. A
final FERC decision is expected in early 2000. SCE does not expect the final
decision to have a material effect on its results of operations or financial
position.
Restructuring Implementation Costs
The ISO assumed operational control of the transmission system after the ISO and
PX had begun accepting bids and schedules for electricity purchases on March 31,
1998. The restructuring implementation costs related to the start-up and
development of the PX, which are paid by the utilities, were to be recovered
from all retail customers over the four-year transition period. SCE's share of
the charge is $45 million, plus interest and fees. SCE's share of the ISO's
start-up and development costs (approximately $16 million per year) will be paid
over a 10-year period. In May 1998, SCE filed an application with the CPUC to
identify the categories of such costs (including costs related to the
implementation of direct access) and to establish the reasonableness of those
costs incurred in 1997.
On September 16, 1999, the CPUC approved the settlement agreement between SCE,
the CPUC's Office of Ratepayer Advocates and several other parties allowing SCE
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to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation.
Accounting for Generation-Related Assets
If the CPUC's electric industry restructuring plan continues as described above,
SCE will be allowed to recover its transition costs through non-bypassable
charges to its distribution customers (although its investment in certain
generation assets would be subject to a lower authorized rate of return). In
1997, SCE discontinued application of accounting principles for rate-regulated
enterprises for its investment in generation facilities based on new accounting
guidance. The new guidance did not require SCE to write off any of its
generation-related assets, including related regulatory assets. SCE has retained
these assets on its balance sheet because the Statute and restructuring plan
referred to above make probable their recovery through a non-bypassable CTC to
distribution customers. The regulatory assets relate primarily to the recovery
of accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments and unamortized losses on
reacquired debt. The new accounting guidance also permits the recording of new
generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording 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 future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at September 30, 1999) as a one-time, non-cash charge
against earnings. At this time, SCE cannot predict what other revisions will
ultimately be made during the restructuring process in subsequent proceedings or
the effect, after the transition period, that competition will have on its
results of operations or financial position.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
As further discussed in Note 10 to the Consolidated Financial Statements, SCE
records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site. Unless
there is a probable amount, SCE records the lower end of this likely range of
costs.
SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $165 million. One of SCE's sites, a former pole-treating facility, is
considered a federal Superfund site and represents 40% of its recorded
liability. The ultimate costs to clean up SCE's identified sites may vary from
its recorded liability due to numerous uncertainties inherent in the estimation
process. SCE believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to $284
million. The upper limit of this range of costs was estimated using assumptions
least favorable to SCE among a range of reasonably possible outcomes. SCE has
sold all of its gas- and oil-fueled power plants and has retained some liability
associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $85 million of its recorded liability, through an incentive
mechanism. Under this mechanism, SCE will recover 90% of cleanup costs through
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customer rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. Costs
incurred at SCE's remaining sites are expected to be recovered through customer
rates. SCE has recorded a regulatory asset of $130 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer
rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$5 million to $15 million. Recorded costs for the twelve-month period ended
September 30, 1999, were $15 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
The 1990 Federal 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).
The act also calls for a study to determine if additional regulations are needed
to reduce regional haze in the southwestern U.S. In addition, another 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 issued an advanced notice of proposed
rulemaking regarding assessment of visibility impairment at the Grand Canyon.
SCE intends to file comments on the proposed rulemaking. At this time, SCE is
unable to predict the potential effect of these studies on sulfur dioxide
regulations for Mohave, or what effect the final reports may have on SCE's
results of operations or financial position.
SCE's projected environmental capital expenditures are $900 million for the
1999--2003 period, mainly for undergrounding certain transmission and
distribution lines.
San Onofre Steam Generator Tubes
The San Onofre Units 2 and 3 steam generators have performed relatively well
through the first 15 years of operation, with low rates of ongoing steam
generator tube degradation. However, during the Unit 2 scheduled refueling and
inspection outage in 1997, an increased rate of tube degradation was identified,
which resulted in the removal of more tubes from service than had been expected.
The steam generator design allows for the removal of up to 10% of the tubes
before the rated capacity of the unit must be reduced. As a result of the
increased degradation, a mid-cycle inspection outage was conducted in early 1998
for Unit 2. Continued degradation was found during this inspection. A favorable
or decreasing trend in degradation was observed during inspection in the
scheduled refueling outage in January 1999. Analysis of results of the January
1999 inspection determined that a mid-cycle inspection outage in early 2000 will
be unnecessary. With the results from the January 1999 outage, 7.5% of the tubes
have now been removed from service.
During Unit 3's refueling outage, which was completed in May 1999, a complete
inspection of the steam generator tubes was performed. Results obtained were
within expectations. To date, 5.4% of Unit 3's tubes have been removed from
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service. During the refueling, follow-up inspections of the tube support
thinning problem first detected in 1997 were performed. These inspections
confirmed that corrective actions taken in 1997 were effective and the thinning
has been stabilized.
New Accounting Rules
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, requires all derivatives to be recognized on the balance sheet
at fair value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
Year 2000 Issue
Many of SCE's existing computer systems were originally programmed to represent
any date by using six digits (e.g., 12/31/99) rather than eight digits (e.g.,
12/31/1999). Accordingly, such programs, if not appropriately addressed, could
fail or create erroneous results when attempting to process information
containing dates after December 31, 1999. This situation has been referred to
generally as the Year 2000 Issue.
SCE has a comprehensive program in place to address potential Year 2000 impacts.
Edison International provides overall coordination of this effort. SCE divides
Year 2000 activities into five phases: inventory, impact assessment,
remediation, testing and implementation. SCE met its goal to have 100% of its
critical systems Year 2000-ready by July 1, 1999. A critical system is defined
as those applications and systems, including embedded processor technology,
which if not appropriately remediated, may have a significant impact on
customers, the health and safety of the public and/or personnel, the revenue
stream, or regulatory compliance. A system, application or physical asset is
deemed to be Year 2000-ready if it is determined by SCE to be suitable for
continued use through 2028 (or through the last year of the anticipated life of
the asset, whichever occurs first), even though it may not be fully Year
2000-compliant. A system, application, or physical asset is deemed to be Year
2000-compliant if it accurately processes date/time data, such as calculating,
comparing, and sequencing from, into, and between the 20th and 21st centuries,
1999 and 2000, and leap-year calculations.
SCE has structured the scope of the program to focus on three principal
categories: mainframe computing, distributed computing and physical assets (also
known as embedded processors). The mainframe and distributed computing assets
consist of computer application systems (software). Physical assets include
information technology infrastructure (hardware, operating system software) and
embedded processor technology in generation, transmission, distribution, and
facilities components.
Included among the critical applications that are Year 2000-ready are the
financial, customer information and billing, material management, and human
resource systems. Work has also been completed on critical physical assets in
the areas of information technology infrastructure, and embedded processor
technology in generation, transmission, distribution and facilities assets. SCE
filed a statement with the Nuclear Regulatory Commission (NRC) on June 28, 1999,
stating that its Year 2000 readiness program has been completed for those
systems within the scope of its operating license, NRC regulations and other
critical systems required for continued operation of San Onofre Units 2 and 3.
Ongoing efforts continue to focus on non-critical systems and on guarding
against reintroduction of components that are not Year 2000-ready into Year
2000-ready systems. SCE has adopted a technology production freeze beginning
November 15, 1999, and extending through January 15, 2000. During this period,
any changes to SCE's production environment will be tightly controlled. The
freeze covers changes to physical assets with embedded processors and
information technology infrastructure, and includes moves, adds and changes to
communications equipment, computers and software applications.
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The other essential component of the Year 2000 program is to identify and assess
vendor products and business partners for Year 2000 readiness, as these external
parties may have the potential to impact SCE's Year 2000 readiness. SCE has
implemented a process to identify and contact vendors and business partners to
determine their Year 2000 status. Evaluation of responses and other follow-up
activities are substantially complete. SCE's general policy requires that all
newly purchased products and services be Year 2000-ready or otherwise designed
to allow SCE to determine whether such products and services present Year 2000
issues. SCE is also working to address Year 2000 issues related to all ISO and
PX interfaces, as well as joint ownership facilities. SCE exchanges Year
2000-readiness information (including, but not limited to, test results and
related data) with its affiliates and other external parties as part of its Year
2000-readiness efforts.
SCE's current estimate of its Year 2000 costs, including the costs of new
hardware and software application modification, work on contingency planning
efforts discussed below and continuing work on non-critical assets, is $69
million, about 38% of which is expected to be capital costs. SCE's Year 2000
costs expended through September 30, 1999, were $60 million. SCE expects current
rate levels for providing electric service to be sufficient to provide funding
for utility-related modifications.
Although SCE expects that its critical facilities, systems, information
technology infrastructure and physical assets will remain fully Year 2000-ready,
there can be no assurance that the facilities, systems, infrastructure and
physical assets of other companies on which the systems and operations of SCE
rely will be converted on a timely basis and will remain ready for 2000. SCE
believes that prudent business practices call for development of contingency
plans. These plans include provisions for monitoring, validating and managing
the continued performance of SCE Year 2000-sensitive systems and assets during
critical transition periods, development of work-arounds and expedited
fix-on-failure strategies. Where appropriate, contingency plans include
scheduling of key personnel, identification of alternate suppliers and securing
adequate on-site supplies of critical materials. SCE plans to have more than 500
additional personnel, over and above normal holiday staffing, at key facilities
for the Year 2000 rollover.
SCE has implemented a Year 2000 contingency planning process as a part of its
Year 2000 remediation program. Each SCE department is required to assess the
Year 2000 risks, including both internal and external risks and dependencies,
associated with critical systems and assets, that are date aware or date
sensitive. This includes assessment of Year 2000 risks for all indispensable or
critical business processes and key facilities.
Where appropriate, the plans utilize or supplement the existing Corporate
Emergency Response and Recovery Plan, and Information Technology disaster
recovery plan, for identified Year 2000-related events. SCE's Year 2000
contingency plans are designed to coordinate and interface with the California
ISO and the PX and to satisfy Western System Coordinating Council (WSCC) and
North American Electric Reliability Council (NERC) recommendations and Nuclear
Energy Institute guidelines. SCE will continue to work with these industry
groups, as well as the Electric Power Research Institute and other major
interconnecting utilities, regarding its contingency plans. Initial development
of these plans was completed in June 1999. SCE filed a report on its contingency
plans, as required, with the CPUC on July 1, 1999. Contingency plans have been
used in conducting SCE and electric industry drills and will continue to be used
to conduct internal exercises during the fourth quarter of 1999. SCE expects
that its contingency plans will continue to be revised and enhanced as 2000
approaches.
Although SCE's Year 2000 contingency plans use risk-based methods, the plans are
being evaluated against the NERC/WSCC suggested "More Probable" and "Credible
Worst Case Scenarios." SCE believes that the most reasonably likely worst case
Year 2000 scenario would be small, localized interruptions of service which
would be restored in a timeframe that is within normal service levels.
SCE does not expect the Year 2000 Issue to have a material adverse effect on its
results of operation or financial position; however, if not effectively
remediated, and despite the adoption of contingency plans, negative effects from
Year 2000 issues, including those related to internal systems, vendors, business
partners, the ISO, the PX or customers, could cause results to differ.
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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 further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business and other energy-related businesses, including direct customer access
to retail energy suppliers and the unbundling of revenue cycle services such as
metering and billing; changes in prices of electricity and fuel costs; the terms
of divestiture of utility generation assets; changes in market interest rates;
new or increased environmental liabilities; the ability to create and expand new
businesses such as telecommunications; the effects of the Year 2000 Issue;
municipalization and other unforeseen events.
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PART II OTHER INFORMATION
Item 1. Legal Proceedings
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties routinely vented highly toxic hydrogen
sulfide gas from unmonitored release points beginning in 1990 and continuing
through at least 1994, in violation of applicable federal, state, and local
environmental law. According to SCE, these violations constituted material
breaches by the Coso parties of their obligations under their contracts with SCE
and applicable law. The complaint sought termination of the contracts and
damages for excess power purchase payments made to the Coso parties. The Coso
parties' motion to transfer venue to Inyo County Superior Court was granted on
August 31, 1997. On June 1, 1998, the Court struck SCE's request for termination
of the contracts, leaving SCE with its claim for damages and other relief. On
February 16, 1999, the Court denied the Coso parties' motion for judgment on the
pleadings directed to SCE's first amended complaint.
The Coso parties have also asserted various claims against SCE, The Mission
Group, and Mission Power Engineering Company (Mission parties) in a cross
complaint filed in the action commenced by SCE as well as in a separate action
filed against SCE by three of the Coso parties in Inyo County Superior Court. In
November 1997, the Court struck all but two causes of action asserted in the
separate action on the grounds that they should have been raised as part of the
Coso parties' cross-complaint, and ordered the remaining two causes of action
consolidated for all purposes with the action filed by SCE.
The Coso parties subsequently filed second and third amended cross-complaints.
The third amended cross-complaint names SCE, the Mission parties and Edison
International. As against SCE, the third amended cross-complaint purports to
state causes of action for declaratory relief, breach of the covenant of good
faith and fair dealing; inducing breach of agreements between the Coso parties
and their former employees; breach of an earlier settlement agreement between
the Mission parties and the Coso parties; slander and disparagement, injunctive
relief and restitution for unfair business practices; anticipatory breach of the
contracts; and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As
against the Mission parties, the third amended cross-complaint seeks damages for
breach of warranty of authority with respect to the settlement agreement, and
for equitable indemnity. The Coso parties voluntarily dismissed Edison
International from the third amended cross-complaint on December 4, 1998. As
against SCE, the third amended cross-complaint seeks restitution, compensatory
damages in excess of $115 million, punitive damages in an amount not less than
$400 million, interest, attorney's fees, declaratory relief, and injunctive
relief.
On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting affirmative
defenses. In addition, SCE filed a cross-complaint for reformation of the
contracts alleging that if they are not susceptible to SCE's interpretation,
they should be reformed to reflect the parties' true intention. SCE subsequently
voluntarily filed a first amended cross-complaint. On February 26, 1999, after
the Court had sustained a demurrer to its first amended cross-complaint, SCE
filed a second amended cross-complaint for reformation.
Following various pre-trial motions filed by the Mission parties and Edison
International, the Coso parties purported to file a fourth amended
cross-complaint on December 23, 1998, against the Mission Parties only. The
Mission parties' demurrer to and motion to strike directed to the fourth amended
cross-complaint was heard and taken under submission on March 10, 1999.
On December 15, 1998, the Court granted the Coso parties leave to file a second
amended complaint in the separately filed (now consolidated) action. The second
amended complaint, which names SCE and Edison International, alleges that SCE
engaged in anti-competitive conduct, false advertising, and conduct proscribed
by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and
punitive damages. On January 20, 1999, SCE filed three motions to strike several
38
<PAGE>
portions of the second amended complaint on the grounds, among others, that the
CPUC or FERC have either exclusive or primary jurisdiction over the matters
asserted therein, and that SCE's alleged conduct was in furtherance of
constitutionally protected rights of free speech and petition and therefore not
actionable. These matters were heard on February 22, 1999, and taken under
submission at that time. Edison International also filed a demurrer and motion
to strike the second amended complaint. The Court denied the motion to strike
and overruled the demurrer on March 22, 1999.
On April 1, 1999, the Court signed a stipulation and order submitted by the
parties staying all proceedings to allow the parties to engage in settlement
discussions. The Court and the parties have continued the stay in effect through
and including November 30, 1999, in order to permit the continuation of
settlement discussions. As a result of the stay, all discovery has been
suspended. Furthermore, during the period of the stay, the Court will not issue
orders or rulings on matters taken under submission.
The Court has set a trial date of March 1, 2000, but, in light of the stay
currently in effect, has reserved jurisdiction to advance or to continue the
trial date. The materiality of net final judgments against SCE in these actions
would be largely dependent on the extent to which any damages or additional
payments which might result therefrom are recoverable through rates.
San Onofre Personal Injury Litigation
SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. On August 31, 1995, the wife
and daughter of a former San Onofre security supervisor sued SCE and SDG&E in
the U.S. District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering and the Institute of Nuclear Power Operations as
defendants. All trial court proceedings were stayed pending ruling of the Ninth
Circuit Court of Appeals, on an appeal of a lower court's judgment in favor of
SCE in two earlier cases raising similar allegations. On May 28, 1998, the Court
of Appeal affirmed these judgments. Pursuant to an agreement of the parties as
described below, all proceedings in this matter have been stayed.
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 Appeals.
Briefing on the appeal was completed in January 1999 and the parties are
awaiting a date for oral argument to be set by the Court. A decision is not
expected until at least early 2000.
On November 28, 1995, a former contract worker at San Onofre, her husband, and
her son, sued SCE in the U.S. District Court for the Southern District of
California. Plaintiffs also named Combustion Engineering. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in this matter have been stayed.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the
above cases currently pending at the U.S. District Court level to stay all
proceedings including trial, pending the results of the case currently before
the Ninth Circuit Court of Appeals. The parties agreed that if the plaintiffs in
that case do not receive a favorable determination on appeal, then the two cases
at the District Court level will be dismissed. If, however, those plaintiffs
receive a favorable determination on their appeal, then the two District Court
cases will be set for trial. On March 23, 1999, the District Court approved the
parties' stay agreement in both cases.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot be determined
at this time.
39
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Mohave Generating Station Environmental Litigation
On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in
the U.S. District Court of Nevada against SCE and the other three co-owners of
Mohave Generating Station (Mohave). The lawsuit alleges that Mohave has been
violating various provisions of the Clean Air Act (CAA), the Nevada state
implementation plan, certain Environmental Protection Agency orders, and
applicable pollution permits relating to opacity and sulfur dioxide emission
limits over the last five years. The plaintiffs seek declaratory and injunctive
relief as well as civil penalties. Under the CAA, the maximum civil penalty
obtainable is $25,000 per day per violation. SCE and the co-owners obtained an
extension to respond to the complaint pending the court's ruling on a motion to
dismiss filed by the defendants. The plaintiffs filed an opposition to the
defendants' motion to dismiss as well as a separate motion for partial summary
judgment on May 8, 1998.
On June 4, 1998, the plaintiffs served SCE and the other Mohave co-owners with a
60-day supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On November 12,
1998, the court bifurcated the liability and damage phases of the case and
granted plaintiffs' motion to amend the complaint to add the National Parks and
Conservation Association as a plaintiff.
On December 8, 1998, defendants filed a supplemental memorandum in support of
defendants' opposition to plaintiffs' motion for partial summary judgment. On
February 4, 1999, plaintiffs filed their first amended complaint to add the
National Parks and Conservation Association as a plaintiff in the action. On
March 10, 1999, defendants filed a motion for partial summary judgment. On March
11, 1999, plaintiffs filed a motion for partial summary judgment to establish
emission limit violations as alleged in certain of the causes of action in their
first amended complaint.
On March 8, 1999, the parties filed a stipulated request for a 60-day stay which
was granted and ordered, by the Court on March 9, 1999. A subsequent stay was
granted, which was to expire on July 6, 1999 before being extended to July 20,
1999. No further stay has been sought or is in effect at this time. On July 6,
1999, each party filed an opposition to the other parties' motion for summary
judgment. On August 2, 1999, defendants filed a reply to plaintiffs' opposition.
On August 5, 1999, plaintiffs filed a reply to defendant's opposition. On
October 6, 1999, the parties filed a consent decree with the Federal District
Court in Las Vegas, requesting the judge to approve the decree, and
simultaneously dismiss the lawsuit. The decree provides that certain
environmental control hardware (lime spray dryers, fabric filter baghouses and
low NOx burners) should be installed on the facility by December 31, 2005, in
order to continue to operate the plant as a coal-fired facility after that date.
Navajo Nation Litigation
On June 18, 1999, SCE, was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to Mohave. The
complaint claims that the defendants' actions prevented the Navajo Nation from
obtaining the full value in royalty rates for the coal. The complaint seeks
damages of not less than $600 million, trebling of that amount, and punitive
damages of not less than $1 billion, as well as a declaration that Peabody's
lease and contract rights to mine coal on Navajo Nation lands should be
terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint.
In addition, SCE and other defendants filed motions to dismiss, which will be
argued on February 11, 2000. In the meantime, the Court has stayed discovery.
40
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE
effective June 1, 1993 (File No. 1-2313, Form 10-K for the year ended December
31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated
June 23, 1997 (File No. 1-2313, Form 10-Q for the quarter ended September 30,
1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board
of Directors on April 15, 1999 (File No. 1-2313, Form 10-Q for the quarter ended
June 30, 1999)*
10.1 Executive Retirement Plan Restated Effective April 1, 1999
10.2 Executive Supplemental Benefit Program as Amended January 30, 1990
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
None
- ---------------------
* Incorporated by reference pursuant to Rule 12b-32.
41
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By THOMAS M. NOONAN
------------------------------
THOMAS M. NOONAN
Vice President and Controller
By KENNETH S. STEWART
------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
November 10, 1999
Southern California Edison Company
EXECUTIVE RETIREMENT PLAN
for Executives of Participating
EDISON INTERNATIONAL
Companies
As Restated Effective
April 1, 1999
<PAGE>
TABLE OF CONTENTS
PREAMBLE 1
I. DEFINITIONS 1
II. PARTICIPATION 3
2.01 Eligibility 3
2.02 Pre-1995 Participation 3
III. BENEFIT DETERMINATION AND VESTING 3
3.01 Overview 3
3.02 Benefit Features 3
3.03 Benefit Computation 4
3.04 Vesting 4
3.05 Benefit of Former Executives 5
IV. RETIREMENT BENEFITS 5
4.01 Forms of Benefit Payment 5
4.02 Interest 5
4.03 Commencement of Payments 6
V. TERMINATION BENEFITS 6
VI. SURVIVOR BENEFITS 6
6.01 Overview 6
6.02 Alternative Forms of Payment 6
VII. PAYMENT TERMS AND CONDITIONS 7
7.01 Benefits Nonassignable 7
7.02 I ncapacity 7
7.03 Hardship 7
7.04 No Fiduciary Relationship 8
VIII. TAXES 8
8.01 Taxes on Benefit Payments 8
8.02 Taxes on Benefit Accrual 8
IX. BENEFICIARY 8
X. PLAN ADMINISTRATION 8
10.01 Plan Interpretation 8
10.02 Day-to-Day Administration 9
10.03 Limited Liability 9
XI. AMENDMENT OR TERMINATION 9
11.01 Authority to Amend or Terminate 9
11.02 Limitations 9
XII. CLAIMS AND REVIEW PROCEDURES 9
12.01 Right To Arbitration 9
12.02 Arbitration Procedures 10
12.03 Enforcement of Award and Fees 10
XIII. MISCELLANEOUS11
13.01 Participation in Other Plans 11
13.02 Relationship to Qualified Plan 11
13.03 No Right to Employment 11
13.04 Forfeiture 11
13.05 Benefits Unsecured 12
13.06 Validity and Applicable Law 12
13.07 Captions 12
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
EXECUTIVE RETIREMENT PLAN
As Amended Effective April 1, 1999
I.
PREAMBLE
The purpose of this Plan is to provide supplemental retirement benefits to
Participants and surviving spouses or other designated beneficiaries of such
Participants.
II.
DEFINITIONS
Capitalized terms in the text of the Plan are defined as follows:
Administrator means the Compensation and Executive Personnel Committee of the
Southern California Edison Company Board of Directors.
Affiliate means Edison International or any corporation or entity which along
with Edison International, is a component member of a "controlled group of
corporations" within the meaning of Section 414(b) of the Code.
Base Salary means the annual basic rate of pay as fixed by the Company
(excluding Incentive Awards, special awards, commissions, severance pay, and
other non-regular forms of compensation).
Beneficiary means the person designated as such in accordance with Article IX of
the Plan.
Benefit Feature means one of the levels of benefit under the Plan as described
in Section 3.02(a).
Code means the Internal Revenue Code of 1986, as amended.
Company means the Affiliate employing the Participant.
Financial Hardship means an unexpected and unforeseen financial disruption
arising from an illness, casualty loss, sudden financial reversal, or other such
unforeseeable occurrence as determined by the Administrator or its designee.
Needs arising from foreseeable events such as the purchase of a residence or
education expenses for children will not, alone, be considered a Financial
Hardship.
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Incentive Award means the dollar amount of incentive (bonus) awarded by the
Company to the Participant pursuant to the terms of an annual incentive award
plan.
Participant means a key employee of an Affiliate, who (i) is a U.S. employee or
an expatriate and is based and paid in the U.S., (ii) has been designated as an
executive by the Administrator, the Company Board or the Company CEO for
purposes of the Plan, and (iii) qualifies as a member of the "select group of
management or highly compensated employees" under the Employee Retirement Income
Security Act of 1974, as amended.
Plan means the Southern California Edison Company Executive Retirement Plan.
Qualified Plan means the Southern California Edison Company Retirement Plan, or
a successor plan, intended to qualify under Section 401(a) of the Code.
Retirement means separation from the Company upon attainment of at least age 55
with at least 5 Years of Service.
Senior Officer means (i) the CEO, President, Executive Vice Presidents, Senior
Vice Presidents and elected Vice Presidents of the Sponsor and Edison
International, (ii) any officer of other Affiliates who has been designated as a
Section 16 Officer by the Board of Directors of Edison International, and (iii)
any other Affiliate employee designated by the Administrator to be a Senior
Officer for purposes of the Plan.
Sponsor means the Southern California Edison Company.
Termination of Employment means the voluntary or involuntary cessation of the
Participant's employment with the Company for any reason other than death or
Retirement. Termination of Employment will not be deemed to have occurred for
purposes of this Plan if the Participant is reemployed by another Affiliate
within 30 days of ceasing work with the Company.
Total Compensation means (i) for non-Senior Officer Participants, the annualized
average Base Salary as fixed by the Company based on the Participant's 36
highest months of Base Salary, and (ii) for Senior Officers, the annualized
average of Base Salary plus Incentive Award based on the 36 months in which the
Participant had the highest combination of Base Salary and Incentive Award. The
36 months need not be consecutive. For purposes of determining the highest 36
months for Senior Officers, each of the Participant's annual Incentive Awards
will be spread evenly over the months worked in the years in which the Incentive
Awards were earned. In no event will Total Compensation be less than the dollar
amount determined under the terms of the Plan in effect on March 31, 1999 for
Employees who were Participants on that date.
2
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Year of Service means a calendar year in which the Participant is credited with
1,000 or more hours of service with the Company determined in accordance with
the terms of the Qualified Plan.
II.
PARTICIPATION
2.01 Eligibility
Individuals are eligible to participate in the Plan when they become Senior
Officers or are designated as executives by the Administrator, the Company Board
or the Company CEO for purposes of this Plan. Participation in the Plan will
continue as long as the individual remains a Senior Officer or a designated
executive (subject to any applicable Plan restrictions).
2.02 Pre-1995 Participation
Employees who were Participants in the Plan on December 31, 1994 will continue
to participate in the Plan as long as they remain designated as executives.
III.
BENEFIT DETERMINATION AND VESTING
3.01 Overview
Benefits under the Plan will be payable with respect to any vested Participant
upon Retirement to the extent the benefit payable under this Plan exceeds the
benefit payable under other specified plans as provided under Section 3.03(a).
3.02 Benefit Features
(a) The Plan provides a supplemental retirement benefit calculated in accordance
with Section 3.03 below. The Plan incorporates the following Benefit Features:
(i) Recognition of the amount of Base Salary that is not recognized for
purposes of calculating benefits under the Qualified Plan due to limits
imposed by the Code under Sections 415(b) or 401(a)(17).
(ii)Recognition of deferred salary that is not recognized for purposes of
calculating benefits under the Qualified Plan.
(iii) Recognition of Incentive Awards that are not recognized for purposes
of calculating benefits under the Qualified Plan.
3
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(iv)An additional 0.75% benefit accrual over that provided by the Qualified
Plan is earned for each Year of Service up to ten Years of Service.
Plan eligibility during those years is not required.
(b) Senior Officers are eligible for all four Benefit Features. Other
Participants are eligible for Benefit Features (i) and (ii) only.
(c) Participants in the Plan on December 31, 1994, are eligible for all four
Benefit Features as long as they remain eligible to participate in the Plan,
unless they were participants in the Plan on December 31, 1992 and did not elect
to participate in the Executive Disability and Survivor Benefit Program, in
which case they are not eligible for Benefit Feature (iv).
3.03 Benefit Computation
(a) The Sponsor will calculate the amount of any benefits payable under the Plan
for each Participant at the time of the Participant's Retirement, death, or
termination with a deferred vested benefit. The amount payable under this Plan
will be that dollar amount calculated pursuant to Section 3.03(b), reduced by
(i) the dollar amount payable to the Participant (or spouse or contingent
annuitant) under the terms of the Qualified Plan, or other Affiliate defined
benefit plan, after taking into account any applicable restrictions or
limitations as to such payments required by the Code or other applicable law or
the terms of the Qualified Plan, or other applicable Affiliate defined benefit
plan, and (ii) the actuarial single life annuity value, as defined in the
Qualified Plan, of the Participant's Profit Sharing Account under the Sponsor's
Stock Savings Plus Plan, or successor plan.
(b) The Participant's Total Compensation will be used to calculate benefit
amounts based on the formulas set forth in Section 4.02(a) of the Qualified
Plan, including Subsection (1) but excluding Subsection (2), and Section 4.12(b)
of the Qualified Plan, notwithstanding the Participant's eligibility for such
benefits under the terms of the Qualified Plan. The initial calculation of any
Plan benefits based on Total Compensation including Incentive Awards will assume
a target bonus for the final year of employment subject to adjustment based on
the actual Incentive Award made. If the final Incentive Award is made after
benefits under the Plan are paid or commenced under the Plan, the benefit will
be recalculated from inception, any increase to date will be paid in a one-time
adjustment to true-up payments already made, and future payments, if any, will
be adjusted accordingly. Any benefit decreases will be reflected in a one-time
adjustment in the account balance effective with the payment starting the
following January. Notwithstanding any other provision of the Plan to the
contrary, a maximum of 35 Years of Service will be recognized for purposes of
the benefit determination under Section 4.02(a) of the Qualified Plan for
Participants whose initial eligibility date under the terms of the Plan is after
April 1, 1999.
3.04 Vesting
The right to receive benefits under the Plan will vest when the Participant (i)
has completed five Years of Service with an Affiliate, (ii) is determined by the
Administrator
4
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to be permanently and totally disabled while employed with an Affiliate, or
(iii) dies while employed with an Affiliate.
3.05 Benefit of Former Executives
A vested Participant who remains employed with an Affiliate until Retirement but
is no longer a designated executive will retain a benefit in the Plan based on
the Participant's Total Compensation and service determined as of the last date
of the Participant's eligible status and reduced by the amounts specified in
Section 3.03(a) determined upon the Participant's Retirement.
IV.
RETIREMENT BENEFITS
4.01 Forms of Benefit Payment
(a) The normal form of benefit payout under this Plan is a joint and survivor
annuity which will commence upon Retirement of the Participant and be paid
monthly for the lifetime of the Participant. Upon the death of the Participant,
the survivor will be entitled to the benefits payments described in Article VI.
(b) If, at least 90 days prior to his or her Retirement, the Participant elects
an alternative form of payout, upon Retirement by the Participant (either early
or normal Retirement), the value of his or her benefits payable under this Plan
as of the date of Retirement will be paid in the manner elected by the
Participant in (i) a single lump-sum payment calculated using the rate of
interest determined pursuant to Section 4.02, and based upon the 1983 Group
Annuity Mortality actuarial tables, (ii) in monthly installments (of principal,
plus interest) over a period of 60 months, or (iii) in monthly installments (of
principal, plus interest) over a period of 120 months.
(c) If a Participant elects a payout in monthly installments of principal plus
interest over a period of 60 months or 120 months, monthly payments will be
calculated in such a way that equal monthly payments on the first day of each
month for the remainder of the payout period with interest would bring the
balance to zero by the end of that period. The account will be reamortized
annually effective January 1st based on the December 31st account balance and
the revised interest rate as determined pursuant to Section 4.02.
4.02 Interest
The annual reamortization of payments described in Section 4.01(c) will be
determined using a monthly rate of interest that is one-twelfth of the average
Moody's Corporate Bond Yield for Aa Public Utility Bonds for the twelve months
preceding November 1st of the prior year. This interest rate determined on an
annualized basis will also be used to calculate starting balances and lump sums
for purposes of Section 4.01(b).
5
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4.03 Commencement of Payments
Payments under this Plan on account of Retirement will be paid in full if the
lump-sum option is chosen, or will begin to be paid in monthly installments, if
a monthly payment option is chosen, within 30 days of the date on which the
Participant retires, or as soon thereafter as practicable. To the extent
reasonably practicable, monthly payments under this Plan will be made at a time
coincident with the payment of benefits under the Qualified Plan.
V.
TERMINATION BENEFITS
If the Participant terminates his or her employment with the Company prior to
Retirement (either early or normal), but with a deferred vested interest in the
Plan, benefits will be payable under this Plan reduced by the amounts specified
in Section 3.03(a) determined as of the benefit commencement date adjusted to
reflect any distributions from the Participant's Profit Sharing Account under
the Sponsor's Stock Savings Plus Plan, or successor plan, that occurred since
the employment termination date in a manner consistent with the Qualified Plan.
If the vested individual was not a designated executive at the time employment
was terminated, the Plan benefit determined before the Section 3.03(a)
reductions will be based on the Participant's Total Compensation and service
determined as of the last date of the Participant's status as a designated
executive. Notwithstanding any other provision in the Plan to the contrary, any
benefits payable under this Plan due to Termination of Employment will be paid
as an annuity only, beginning at age 55 and calculated as of the Participant's
Normal Retirement Age under the Qualified Plan, reduced by the early retirement
factors applicable to vested terminees under the Qualified Plan. A joint and
survivor annuity will be the normal form of benefit. The Participant may elect
another annuity option available under the Qualified Plan, subject to the same
terms and conditions as would apply to such an election under the Qualified
Plan.
VI.
SURVIVOR BENEFITS
6.01 Overview
In addition to the amount payable hereunder to a retired Participant, this Plan
will pay a benefit, similarly computed, to an eligible surviving spouse or to a
contingent annuitant under the "Spouse's Pension", the "Pre-retirement Survivor
Annuity Option", or the "Contingent Annuitant Option" provisions of the
Qualified Plan if such spouse's pension, survivor annuity or contingent annuity
is reduced or limited as required by currently applicable law or the terms of
the Qualified Plan.
6.02 Alternative Forms of Payment
(a) Upon the death of a Participant who has elected an alternative form of
benefit payment under the Plan prior to the receipt of the full amount credited
to his or her account, the balance of the account will be paid in accordance
with the Participant's previously elected method of payment to the Participant's
designated beneficiary or
6
<PAGE>
beneficiaries, as provided herein, over the remainder of the elected payout
period until the full amount has been paid.
(b) If the 60 or 120 month payout options have been chosen, and if no designated
beneficiary or beneficiaries survive the Participant, or if a designated
beneficiary dies before the balance of the account has been paid, the balance of
the account of the Participant or of the designated beneficiary will be paid in
one lump-sum payment to the estate of the Participant if no designated
beneficiaries survive him or her, or if such designated beneficiaries survive
the Participant, to the estate of whomever was last receiving benefit payments,
as soon as practicable following the Participant's or the designated
beneficiary's death.
(c) If the Participant dies while an active Employee, and a benefit is payable
under the Plan, the designated beneficiary or beneficiaries, or if no designated
beneficiaries survive the Participant, the Participant's estate may select any
of the benefit payout options described in Section 4.01(b).
VII
PAYMENT TERMS AND CONDITIONS
7.01 Benefits Nonassignable
Benefits under this Plan will be binding upon and inure to the benefit of the
heirs, legal representatives, successors and assigns of the parties.
Notwithstanding the foregoing, the right to receive payment hereunder is hereby
expressly declared to be personal, nonassignable and nontransferable, except by
will, intestacy, or as otherwise required by law, and in the event of any
attempted assignment, alienation or transfer of such rights contrary to the
provisions hereof, the Company will have no further liability for payments
hereunder.
7.02 Incapacity
If any person entitled to payments under this Plan is, in the opinion of the
Administrator or its designee, incapacitated and unable to use such payments in
his or her own best interest, the Administrator or its designee may direct that
payments (or any portion) be made to that person's legal guardian or
conservator, or that person's spouse, as an alternative to payment to the person
unable to use the payments. The Administrator or its designee will have no
obligation to supervise the use of such payments, and court-appointed
guardianship or conservatorship may be required.
7.03 Hardship
Upon written application made to the Administrator, the Participant or his or
her designated beneficiary or beneficiaries may request payment in some form
other than the method of payment originally elected. Such request must establish
to the satisfaction of the Administrator or its designee that special
circumstances, such as Financial Hardship, exist which require such a variation
in payment. The Administrator,
7
<PAGE>
or its designee, will exercise sole discretion in allowing or refusing such
requests, and the decision of the Administrator or its designee on such requests
will be final.
7.04 No Fiduciary Relationship
Nothing contained in this Plan, and no action taken pursuant to any of its
provisions, will create or be construed to create a trust of any kind, or a
fiduciary relationship, between the Company or Sponsor and the Participant, a
designated beneficiary, or any other beneficiaries of the Participant, or any
other person. To the extent that any person acquires a right to receive payments
from the Company under the provisions hereof, such right will be no greater than
the right of any unsecured general creditor of the Company.
VIII.
TAXES
8.01 Taxes on Benefit Payments
Any amounts paid under this Plan on account of termination, Retirement, death or
hardship (pursuant to Section 11) will be subject to any income tax withholding
or other deductions as may be required by federal, state, or local law.
8.02 Taxes on Benefit Accrual
A Participant's annual benefit accrual may be subject to federal, state or local
payroll taxes. Such taxes will be withheld from the Participant's salary as may
be required by federal, state or local law.
IX.
BENEFICIARY
At the time the Eligible Employee elects his or her payout method under this
Plan, he or she shall designate a beneficiary or beneficiaries. The designation
may be changed at any time by the Eligible Employee; however, the consent of a
spouse may be required.
X.
PLAN ADMINISTRATION
10.01 Plan Interpretation
The Administrator (either directly or through its designees) will have power and
authority to interpret, construe, and administer this Plan; provided that, its
authority to interpret this Plan will not cause its decisions in this regard to
be entitled to a deferential standard of review in the event that an Participant
or beneficiary seeks review of the Administrator's decision as described in
Article XII.
8
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10.02 Day-to-Day Administration
Day to day administration of the Plan has been delegated by the Administrator to
the Sponsor, under the direction of the officer responsible for Human Resources,
or such other individuals as may be authorized by him or her to perform such
duties. Such administration will include the power to interpret the Plan and
make such equitable adjustments as may be necessary to effectuate the purposes
thereof.
10.03 Limited Liability
Neither the Administrator, nor any of its members or designees, will be liable
to any person for any action taken or omitted in connection with the
interpretation and administration of this Plan.
XI.
AMENDMENT OR TERMINATION
11.01 Authority to Amend or Terminate
The Administrator will have full power and authority to prospectively modify or
terminate this Plan, and the Administrator's interpretations, constructions and
actions, including any valuation of the Participant's account or benefits, or
the amount or recipient of the payment to be made, will be binding and
conclusive on all persons for all purposes. Absent the consent of the
Participant, however, the Administrator will in no event have any authority to
modify this section. However, no such amendment or termination will apply to any
person who has then qualified for or is receiving benefits under this Plan.
11.02 Limitations
In the event of Plan amendment or termination which has the effect of
eliminating or reducing a benefit under the Plan, the benefit payable on account
of a retired Participant or survivor or other beneficiary will not be impaired,
and the benefits of other Participants will not be less than the benefit to
which each such Participant would have been entitled if he or she had retired
immediately prior to such amendment or termination.
XII.
CLAIMS AND REVIEW PROCEDURES
12.01 Right To Arbitration
Because it is agreed that time will be of the essence in determining whether any
payments are due to an Participant or his or her beneficiary under this Plan, an
Participant or beneficiary may, if he or she desires, submit any claim for
payment under this Plan to arbitration. This right to select arbitration will be
solely that of the Participant or beneficiary and the Participant or beneficiary
may decide whether or not to arbitrate in his or her discretion. The "right to
select arbitration" is not mandatory on
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the Participant or beneficiary, and the Participant or beneficiary may choose in
lieu thereof to bring an action in an appropriate civil court. Once an
arbitration is commenced, however, it may not be discontinued without the mutual
consent of both parties to the arbitration. During the lifetime of the
Participant only he or she can use the arbitration procedure set forth in this
section.
12.02 Arbitration Procedures
(a) Any claim for arbitration may be submitted as follows: if an Participant or
beneficiary has submitted a request to be paid under this Plan and the claim is
finally denied by the Sponsor in whole or in part, such claim may be filed in
writing with an arbitrator of the Participant's or beneficiary's choice who is
selected by the method described in the next four sentences. The first step of
the selection will consist of the Participant or beneficiary submitting a list
of five potential arbitrators to the Sponsor. Each of the five arbitrators must
be either (1) a member of the National Academy of Arbitrators located in the
State of California or (2) a retired California Superior Court or Appellate
Court judge. Within one week after receipt of the list, the Sponsor will select
one of the five arbitrators as the arbitrator for the dispute in question. If
the Sponsor fails to select an arbitrator within one week after receipt of the
list, the Participant or beneficiary will then designate one of the five
arbitrators for the dispute in question.
(b) The arbitration hearing will be held within seven days (or as soon
thereafter as possible) after the picking of the arbitrator. No continuance of
said hearing will be allowed without the mutual consent of the Participant or
beneficiary and the Sponsor. Absence from or nonparticipation at the hearing by
either party will not prevent the issuance of an award. Hearing procedures which
will expedite the hearing may be ordered at the arbitrator's discretion, and the
arbitrator may close the hearing in his or her sole discretion when he or she
decides he or she has heard sufficient evidence to satisfy issuance of an award.
The arbitrator's award will be rendered as expeditiously as possible and in no
event later than one week after the close of the hearing.
(c) In the event the arbitrator finds that the Sponsor has breached this Plan,
he or she will order the Sponsor to pay to the Participant or beneficiary within
two business days after the decision is rendered the amount then due the
Participant or beneficiary, plus, notwithstanding anything to the contrary in
this Plan, an additional amount equal to 20% of the amount actually in dispute.
This additional amount will constitute an additional benefit under this Plan.
The award of the arbitrator will be final and binding upon the parties.
12.03 Enforcement of Award and Fees
The award may be enforced in any appropriate court as soon as possible after its
rendition. The Sponsor will be considered the prevailing party in a dispute if
the arbitrator determines (1) that the Sponsor has not breached this Plan and
(2) the claim by the Participant or his or her beneficiary was not made in good
faith. Otherwise, the Participant or his or her beneficiary will be considered
the prevailing party. In the event that the Sponsor is the prevailing party, the
fee of the arbitrator and all necessary expenses of the hearing (excluding any
attorneys' fees incurred by the Sponsor)
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including stenographic reporter, if employed, will be paid by the losing party.
In the event that the Participant or his or her beneficiary is the prevailing
party, the fee of the arbitrator and all necessary expenses of the hearing
(including all attorneys' fees incurred by the Participant or his or her
beneficiary in pursuing his or her claim), including the fees of a stenographic
reporter if employed, will be paid by the Sponsor.
XIII.
MISCELLANEOUS
13.01 Participation in Other Plans
The Participant will continue to be entitled to participate in all employee
benefit programs of the Company as may, from time to time, be in effect.
However, Total Compensation includable under this Plan will be deemed salary or
other compensation to the Participant for the purpose of computing benefits
under this Plan only, and will be used only under this Plan to calculate those
benefits to which the Participant would otherwise be entitled under the
Qualified Plan if such Total Compensation could have been included in the
determination of benefits under that Plan.
13.02 Relationship to Qualified Plan
This Plan will to the full extent possible under currently applicable law be
administered in accordance with, and where practicable according to the terms of
the Qualified Plan. Notwithstanding the foregoing, the terms of this Plan shall
control benefits payable under this Plan whenever the terms of the Qualified
Plan differ from this Plan.
13.03 No Right to Employment
Nothing contained herein will be construed as conferring upon the Participant
the right to continue in the employ of the Company, in any particular salary
grade, or in any other capacity. If the Participant ceases to be an Participant
in the Plan but remains in the employ of the Company, any benefits due the
Participant under the Plan will not be payable until such time as he or she
retires, or ceases to be an employee of the Company, and then only subject to
the terms and conditions contained in this Plan.
13.04 Forfeiture
The payments to be made pursuant to the Plan require the Participant, for so
long as the Participant remains in the active employ of the Company, to devote
substantially all of his or her time, skill, diligence and attention to the
business of the Company, and not to actively engage, either directly or
indirectly, in any business or other activity adverse to the best interests of
the business of the Company. In addition, the Participant will remain available
during Retirement for consultation in any matter related to the affairs of the
Company. Any breach of these conditions will result in complete forfeiture of
any further benefits under the Plan. If the Participant will fail to observe any
of the above conditions, or if he or she will be discharged by the Company for
malfeasance or willful neglect of duty, then in any of said events, the payments
under this Plan will not be paid, and the Sponsor and the Company will have no
further liability therefor.
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13.05 Benefits Unsecured
All Plan benefits will be unsecured and will be paid in cash from the general
funds of the Company. No special or separate fund will be established and no
other segregation of assets will be made to assure the payment of any benefits
hereunder. No person will have by virtue of the provisions of this Plan, any
interest in such assets. In the event that, in its discretion, the Company
purchases an insurance policy or policies insuring the life of the Participant
to allow the Company to recover, in whole, or in part, the cost of providing the
benefits hereunder, neither the Participant, the survivor or other designated
beneficiary(ies) nor any other beneficiary will have any rights whatsoever
therein; the Company will be the sole owner and beneficiary thereof and will
possess and may exercise all incidents of ownership therein.
13.06 Validity and Applicable Law
f any of the provisions of this Plan will be held invalid, or be held to violate
any law, the remainder of this Plan will not be affected thereby and will remain
in full force and effect. This Plan will be governed by the laws of the State of
California.
13.07 Captions
The captions of the articles and sections of the Plan are for convenience only
and shall not control or affect the meaning or construction of any of its
provisions.
SOUTHERN CALIFORNIA EDISON COMPANY
Lillian R. Gorman
-----------------------------------------------------
Lillian R. Gorman, Senior Vice President
SOUTHERN CALIFORNIA EDISON COMPANY
EXECUTIVE SUPPLEMENTAL BENEFIT PROGRAM
As Amended January 30, 1990
This Executive Supplemental Benefit Program ("Program") was originally effective
March 15, 1978, and as thereafter amended consists of several parts or plans,
each paid for by the Company: Part (A) "Survivor Income Continuation", Part (B)
"Supplemental Survivor Income", Part (C) "Supplemental Survivor
Income/Retirement Income", and Part (D) "Supplemental Long-Term Disability".
Eligible members (hereinafter referred to as "Participants") are automatically
provided coverage under the "Survivor Income Continuation" and the "Supplemental
Long-Term Disability" parts of the Program. The "Supplemental Survivor Income"
and the "Supplemental Survivor Income/Retirement Income" parts are in the
alternative and an employee who becomes eligible to participate may irrevocably
elect coverage under one or the other, but not both. It is the intention of the
Company to continue these plans indefinitely, but they are subject to
cancellation or amendment as may be required by law or as deemed appropriate by
the Board of Directors except with respect to rights which have matured by
reason of death, disability, or retirement of a Participant.
Individual eligibility and participation in these plans are subject to the terms
and conditions set forth below and are only available to those employees who are
in salary grade 13 or above who are members of the executive payroll of the
Company and whose participation in the plans has been approved by the Chairman
of the Board and Chief Executive Officer, or such other employees as may be
designated as eligible to participate by the Chairman of the Board and Chief
Executive Officer. An employee shall be deemed to be in a salary grade as of the
date he or she commences accruing salary in such salary grade. No benefits will
be paid with respect to any employee who terminates his or her employment with
the Company prior to retirement. Further, an employee shall be removed from
participation in the Program if, for any reason other than death, disability, or
retirement, he or she ceases to be in salary grade 13 or above.
Part A.
Survivor Income Continuation Plan
1. The basic Survivor Income Continuation benefit for Participants prior to
retirement shall be an annual amount equal to 63% of the Participant's total
compensation, including final annual base salary and any Executive Incentive
Compensation Awards. For purposes of the Executive Supplemental Benefit Program,
the dollar amount of any Executive Incentive Compensation Awards shall be
determined by applying the average percentage awards received in the three (3)
highest years out of the last five (5) years (except for periods of less than
three (3) years, in which case the highest percentage award received will be
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used). This percentage will then be applied to the Participant's final annual
base salary to arrive at a dollar amount which will be added to the
Participant's final annual base salary. This total dollar amount, rounded to the
next highest thousand dollars, will be the Participant's "Total Compensation"
for purposes of the Executive Supplemental Benefit Program.
Survivor Income Continuation payments shall continue for ten (10) years
following the Participant's death unless a shorter alternate payout method is
elected. Payments shall be made in equal monthly installments commencing with
the first day of the month following the month of death, or as soon thereafter
as practicable, and such payments shall be made to the Participant's then living
spouse or other designated beneficiary, if any. If, under this Survivor Income
Continuation Plan, a Participant or beneficiary dies under circumstances in
which benefits are payable but there is no beneficiary designation, or all other
beneficiaries predeceased such Participant or designated beneficiary, the
commuted value of any remaining payments shall be made to the estate of whomever
was last receiving benefit payments, as a single lump sum.
As an alternative form of payment to the ten year payout described above, the
Participant's surviving spouse or other designated beneficiary may elect to have
the basic benefit payments made (i) over a five (5) year period, or (ii) as a
single lump sum payable at the time of the Participant's death.
In determining the basic benefit of 63% of total compensation payable for 10
years, the Company has initially assumed a 10% nominal interest rate and a 50%
marginal federal income tax rate. The basic benefit percentage of 63% (or 31.5%
in the case of retired participants as described below) may be increased or
decreased at the sole discretion of the Company because of changes in the
interest rate assumption or in the tax rate assumption. However, any such
changes in the basic benefit percentage will be made by the Company so that the
after-tax dollar amount payable to the survivor(s) under this Part A will, as
much as possible, approximate the after-tax dollar benefits which would have
been paid under the prior plan before the Plan Amendment is made on December 20,
1984.
In the event either of the alternative payout methods are chosen, the total
payments will be adjusted to an equivalent dollar amount of the basic ten year
payout benefit (which recognizes the shorter payout period so elected), using
the interest rate assumption set forth above, in effect at the time of the
Participant's death.
2. For those employees who retire and are participating in this Part A, the
basic post-retirement Survivor Income Continuation benefit shall be an amount
equal to 31.5% of the employee's total compensation, including final annual base
salary and any Executive Incentive Compensation Award (determined pursuant to
Section 1 hereof) and shall become payable upon the death of the Participant.
Any such post-retirement payments shall be made over 10 years unless a 5 year or
lump-sum payout is elected, as described in Section 1, above.
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3. In addition to the basic benefit described in Section 1 above, a death
benefit may also be available (in addition to any other benefits) if death
occurs prior to retirement under circumstances which qualify as "accidental
death" as defined in any master accidental death and dismemberment insurance
policy which may be maintained by the Company. This accidental death benefit
will be in an amount equal to a basic benefit coverage of two times the sum of
the Participant's annual base salary, plus any awards under the Executive
Incentive Compensation Plan, determined according to Section 1 hereof.
Part B.
Supplemental Survivor Income Plan
1. Eligibility
Participation in this Part shall be available to employees who (i) are in salary
grade 13 or above, whose participation has been approved by the Chairman of the
Board and Chief Executive Officer, (ii) execute, on a form provided pursuant
hereto within the prescribed time limit, an election to be covered hereunder,
and (iii) have never elected to participate in Part C., the Supplemental
Survivor Income/Retirement Income Plan. An employee shall be deemed to be in the
above class as of the date he or she commences accruing salary in the applicable
grade. An eligible employee who is in salary grade 13 or above shall become a
Participant if he or she has elected coverage within fifteen days of the
effective date of his or her eligibility. Beneficiary designations shall be made
on a form provided pursuant hereto and may be modified at any time unless the
designation is specified as irrevocable, in which case, no subsequent
beneficiary designation shall be valid.
2. Preretirement Benefit
Upon the death prior to retirement of a Participant, an annuity shall be payable
as follows:
(a) If the designated beneficiary is the surviving spouse of the Participant (or
a spouse at the time of beneficiary designation, but not at death), the amount
of this benefit will be a lifetime monthly annuity payment. The monthly amount
of this benefit will be equal to one twelfth (1/12) of 25% of the sum of the
Participant's annual base salary at the time of death plus the amount of any
Executive Incentive Compensation awards (determined according to Section 1 of
Part A hereof). This monthly benefit shall be paid in equal monthly installments
commencing on the first of the month next following the date of death, or as
soon thereafter as practicable. Such payments will be for a minimum of ten years
and, should the surviving spouse die less than ten years after the Participant,
any remaining benefits will be payable to the successor beneficiary designated
by the Participant or, if there be none, to the spouse's designated beneficiary
in the same manner as the payments had been made to the spouse for the remainder
of any such ten year period. If the surviving spouse (or designated former
spouse) is more than three years younger than the Participant, the lifetime
monthly annuity benefit shall be calculated as follows: (i) the present value of
the benefit payable shall be calculated as if such spouse were three years
younger than the Participant; (ii) such present value shall be converted to a
monthly benefit amount based on the actuarial life expectancy of the actual
surviving spouse (or surviving designated former spouse) and shall be determined
using (i) the interest rate assumption determined pursuant to Section 1 of Part
A hereof, and (ii) 1983 Group Annuity Mortality table.
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(b) If the Participant designates a beneficiary or beneficiaries other than his
or her spouse (or a former spouse eligible for benefits under the preceding
paragraph) such beneficiary or beneficiaries will receive a monthly benefit to
be determined as follows. The amount of this monthly benefit will be equal to
one-twelfth (1/12) of 25% of the sum of the Participant's annual base salary at
the time of death plus the amount of any Executive Incentive Compensation awards
(determined according to Section 1 of Part A hereof). This monthly benefit shall
be paid in equal monthly installments commencing on the first of the month next
following the date of death, or as soon thereafter as practicable. Such payments
shall continue for a period equal to the assumed life expectancy of a spouse
three years younger than the Participant at the time of the Participant's death,
using the 1983 Group Annuity Mortality table. This benefit shall be payable for
a minimum of ten years, and should a beneficiary die less than ten years after
the death of the Participant, any unpaid benefits remaining for this ten-year
period shall be payable to the successor beneficiary designated by the
Participant or, if there be none, to whomever his or her beneficiary designates.
(c) If, under this Supplemental Survivor Income Plan, a Participant or
beneficiary dies under circumstances in which benefits are payable but there is
no beneficiary designation, or all other beneficiaries predeceased such
Participant or designated beneficiary, the commuted value of any remaining
payments shall be made to the estate of whomever was last receiving benefit
payments as a single lump sum using that rate of interest determined according
to Section 1 of Part A hereof.
3. Post-retirement Benefit
Upon the death after retirement of a Participant, his or her beneficiary shall
be paid a monthly benefit in an amount equal to one-twelfth (1/12) of 25% of the
sum of the Participant's annual base salary (immediately prior to retirement)
plus the amount of any Executive Incentive Compensation Awards (determined
according to Section 1 of Part A hereof). This monthly benefit shall be paid in
equal monthly installments commencing on the first of the month next following
the date of death, or as soon thereafter as practicable. This benefit will be
payable for ten years only and, should the designated beneficiary (or subsequent
beneficiary) die prior to the expiration of such ten year period, any remaining
payments will be continued, until exhausted, to the successor beneficiary
designated by the Participant or, if there be none, to whomever the beneficiary
designates.
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If, under this Supplemental Survivor Income Plan, a Participant or designated
beneficiary dies under circumstances in which benefits are payable but there is
no beneficiary designation, or all other beneficiaries have predeceased such
Participant or beneficiary, the commuted value of any remaining payments shall
be paid to the estate of whomever was last receiving benefit payments, as a
single lump sum calculated using the interest rate determined under Section 1 of
Part A.
Part C.
Supplemental Survivor Income/Retirement Income Plan
1. Eligibility
Participation in this part shall be available to employees who (i) are in salary
grade 13 or above, whose participation has been approved by the Chairman of the
Board and Chief Executive Officer, (ii) execute, on a form provided pursuant
hereto within the prescribed time limit, an election to be covered hereunder,
and (iii) have never elected to participate in Part B., the Supplemental
Survivor Income Plan. An Eligible Employee shall be deemed to be in the above
class as of the date he or she commences accruing salary in the applicable
class. An Eligible Employee who is in salary grade 13 or above shall become a
Participant if he or she has elected coverage within fifteen days of the
effective date of his or her eligibility. Beneficiary designations shall be made
on a form provided pursuant hereto and may be modified at any time unless the
designation is specified as irrevocable, in which case, no subsequent
beneficiary designation shall be valid.
2. Preretirement Benefit
Upon the death, prior to retirement of a Participant, an annuity shall be
payable as follows:
(a) If the designated beneficiary is the surviving spouse of the Participant (or
a spouse at the time of beneficiary designation, but not at death), the amount
of this benefit will be a lifetime monthly annuity payment. The monthly amount
of this benefit will be equal to one-twelfth (1/12) of 25% of the sum of the
Participant's annual base salary at the time of death plus the amount of any
Executive Incentive Compensation Awards (determined according to Section 1 of
Part A hereof). This monthly benefit shall be paid in equal monthly installments
commencing on the first of the month next following the date of death, or as
soon thereafter as practicable. Such payments will be for a minimum of ten years
and, should the surviving spouse die less than ten years after the Participant,
any remaining unpaid benefits will be payable to the successor beneficiary
designated by the Participant or, if there be none, to the spouse's designated
beneficiary in the same manner as the payments had been made to the spouse for
the remainder of such ten-year period. If the surviving spouse (or designated
former spouse) is more than three years younger than the Participant, the
lifetime monthly benefit shall be calculated as follows: (i) the present value
of the benefit payable shall be calculated as if such spouse were three years
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younger than the Participant; (ii) such present value shall be converted to a
monthly benefit amount based on the actuarial life expectancy of the actual
surviving spouse (or surviving designated former spouse) and shall be determined
using (i) the interest rate assumption determined pursuant to Section 1 of Part
A hereof, and (ii) the 1983 Group Annuity Mortality table.
(b) If the Participant designates a beneficiary or beneficiaries other than his
or her spouse (or a former spouse eligible for benefits under the preceding
paragraph) such beneficiary or beneficiaries will receive a monthly benefit to
be determined as follows. The amount of this monthly benefit will be equal to
one-twelfth (1/12) of 25% of the sum of the Participant's annual base salary at
the time of death plus the amount of any Executive Incentive Compensation Awards
(determined according to Section 1 of Part A hereof). This monthly benefit shall
be paid in equal monthly installments commencing on the first of the month next
following the date of death, or as soon thereafter as practicable. Such payments
shall continue for a period equal to the assumed life expectancy of a spouse
three years younger than the Participant at the time of the Participant's death
using the 1983 Group Annuity Mortality table. This benefit shall be payable for
a minimum of ten years, and should a beneficiary die less than ten years after
the death of a Participant, any unpaid benefits remaining for this ten year
period shall be payable to the successor beneficiary designated by the
Participant or, if there be none, to whomever his or her beneficiary designates.
If, under this Supplemental Survivor Income/Retirement Income Plan, a
Participant or beneficiary dies under circumstances in which benefits are
payable but there is no beneficiary designation, or all other beneficiaries
predeceased such Participant or designated beneficiary, the commuted value of
any remaining payments shall be made to the estate of whomever was last
receiving benefit payments, as a single lump sum using that rate of interest
determined according to Section 1 of Part A hereof.
3. Post-retirement Benefit
Upon the death, after retirement, of a Participant, his or her beneficiary shall
be paid a monthly benefit in an amount equal to one-twelfth (1/12) of 25% of the
sum of the Participant's final annual base salary (immediately prior to
retirement) plus the amount of any Executive Incentive Compensation Awards
(determined according to Section 1 of Part A hereof). This monthly benefit shall
be paid in equal monthly installments commencing on the first of the month next
following the date of death, or as soon thereafter as practicable.
This benefit will be payable for ten years only and, should the designated
beneficiary (or subsequent beneficiary) die prior to the expiration of such ten
year period, any remaining payments will be continued, until exhausted, to the
successor beneficiary designated by the Participant or, if there be none, to
whomever his or her beneficiary designates.
If, under this Supplemental Survivor Income/Retirement Income Plan, a
Participant or designated beneficiary dies under circumstances in which benefits
are payable but there is no beneficiary designation, or all other beneficiaries
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predeceased such Participant or designated beneficiary, the commuted value of
any remaining payments shall be made to the estate of whomever was last
receiving benefit payments, as a single lump sum calculated using the interest
rate determined under Section 1 of Part A.
4. Supplemental Retirement Income Benefit
(a) At least 15 days prior to retirement, a Participant may apply for a
supplemental retirement annuity in lieu of the benefit which otherwise would be
made available to a beneficiary under Section 3 of this Part C. Such application
shall be in writing, directed to the Chairman of the Board and Chief Executive
Officer, or, in the case of the Chairman of the Board and Chief Executive
Officer, directed to the Chairman of the Compensation Committee of the Board of
Directors, and shall include a statement of the reasons for such application.
(b) Upon approval of the application by the Chairman of the Board Chief
Executive Officer, or the Board of Directors if the application is by the
Chairman of the Board and Chief Executive Officer, the Participant, if he or she
retires at or after age 61, shall receive a supplemental retirement annuity in a
monthly amount equal to one-twelfth (1/12) of 10% of the sum of the retired
Participant's final annual base salary plus the amount of any Executive
Incentive Compensation Awards (determined according to Section 1 of Part A,
hereof), payable monthly for ten years only, to the Participant or his or her
designated beneficiary (or subsequent beneficiary) should he or she die prior to
the exhaustion of benefits available under this option.
(c) Effective for eligible Participants retiring on or after September 1, 1983,
if the Participant's application for this optional benefit is approved and he or
she retires prior to age 61 but not earlier than age 60, the benefit described
under (b) shall be reduced by an amount equal to one-quarter of one percent
(1/4%) for each month between his or her early retirement date and the first day
of the month nearest his or her 61st birthday. For each month retirement
precedes age 60, the Participant's benefit amount shall be reduced an additional
one-third of one percent (1/3%). However, no such reduction shall be applied if
he or she elects to defer the commencement of the annuity to age 61 or later.
(d) Any Participant in this Supplemental Survivor Income/Retirement Income Plan
may at any time irrevocably waive the right to apply for the supplemental
retirement annuity benefit under this Section 4 of this Part C.
(e) If, under this Supplemental Survivor Income/Retirement Income Plan, a
Participant or beneficiary dies under circumstances in which benefits are
payable but there is no beneficiary designation, or all other beneficiaries have
predeceased such Participant or beneficiary(ies), the commuted value of any
remaining payments shall be made to the estate of whomever was last receiving
benefit payments, as a single lump sum. This lump sum shall be determined using
the interest rate calculated pursuant to Section 1 of Part A, hereof.
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Part D.
Supplemental Long-Term Disability Plan
1. To qualify for benefits under this Part D., a Participant must be (i)
eligible for and (ii) must qualify to receive monthly disability benefits under
the Company's Long-Term Disability Plan for Management Employees.
Eligibility for benefits under this Part D. will be determined according to the
eligibility standards and requirements set forth in the Company's Long-Term
Disability Plan for Management Employees.
2. The monthly income benefit payable under this Part D. to an eligible and
qualified participant shall be an amount equal to one-twelfth (1/12) of 60% of
the amount of any Executive Incentive Compensation Awards. For purposes of this
Part D., the dollar amount of any Executive Incentive Compensation Awards shall
be determined by applying the average percentage awards received in the three
(3) highest years out of the last five years (except for periods of less than
three (3) years, in which case the highest percentage award received will be
used). This percentage will then be applied to the Participant's final annual
base salary (before his or her disability) to arrive at a dollar amount of any
Executive Incentive Compensation Awards to which the 60% factor will be applied.
This monthly disability benefit will be calculated as of the first of the month
in which the total disability began.
3. Payment of benefits shall commence at the same time, or as soon thereafter as
practicable, as monthly income benefit payments begin under the Company's
Long-Term Disability Plan for Management Employees.
4. Payment of benefits under this Part D. shall continue until such time as
monthly benefits end under the Company's Long-Term Disability Plan for
Management Employees.
5. To the fullest extent possible, the Company intends to administer this Part
D. according to the provisions of its Long-Term Disability Plan for Management
Employees.
Part E.
Administration
1. The Executive Supplemental Benefit Program described herein (comprised of
Parts A, B, C and D) shall be administered by the Company, under the direction
of the Vice President, Human Resources, or such other individuals as may be
authorized by him to perform such duties. Such administration shall include the
power to interpret the various Parts of the Program, and make such equitable
adjustments as may be necessary to effectuate the purposes thereof.
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2. The payments to be made by the Company pursuant hereto require the
Participant, for so long as the Participant remains in the active employ of the
Company, to devote substantially all of his or her time, skill, diligence and
attention to the business of the Company, and not to actively engage, either
directly or indirectly, in any business or other activity adverse to the best
interests of the business of the Company.
3. In the event that the employment of the Participant by the Company is
terminated for any reason other than death, disability, or retirement, any
benefits under this Program shall thereupon terminate, and the Company shall
have no further obligation hereunder. Nothing contained herein shall be
construed to be a contract of employment for any term of years, nor as
conferring upon the Participant the right to continue in the employ of the
Company as a Management employee or in any other capacity. This Program relates
exclusively to Executive Supplemental Benefits and is not intended to be an
employment contract.
4. All payments hereunder shall be paid in cash from the general funds of the
Company, and no special or separate fund shall be established and no other
segregation of assets shall be made to assure the payment of any benefits
hereunder. Nothing contained in this Program, and no action taken pursuant to
any of its provisions, shall create or be construed to create a trust of any
kind, or a fiduciary relationship, between the Company and the Participant, a
designated beneficiary, or any other beneficiaries of the Participant, or any
other person. Payments to the Participant or the Participant's survivor or other
designated beneficiary(ies) or any other beneficiary hereunder shall be made
from assets which shall continue, for all purposes, to be a part of the general
assets of the Company, and no person shall have by virtue of the provisions of
this Program, any interest in such assets. To the extent that any person
acquires a right to receive payments from the Company under the provisions
hereof, such right shall be no greater than the right of any unsecured general
creditor of the Company.
5. In the event that, in its discretion, the Company purchases an insurance
policy or policies insuring the life of the Participant to allow the Company to
recover, in whole, or in part, the cost of providing the benefits hereunder,
neither the Participant, the survivor or other designated beneficiary(ies), nor
any other beneficiary shall have any rights whatsoever therein; the Company
shall be the sole owner and beneficiary thereof and shall possess and may
exercise all incidents of ownership therein.
6. Benefits under this Program shall be binding upon and inure to the benefit of
the heirs, legal representatives, successors and assigns of the parties.
Notwithstanding the foregoing, the right to receive payment hereunder is hereby
expressly declared to be personal, nonassignable and nontransferrable, except by
will, intestacy, or as otherwise required by law, and in the event of any
attempted assignment, alienation or transfer of such rights contrary to the
provisions hereof, the Company shall have no further liability for payments
hereunder.
7. Subject to Section 8 of Part E, the Company shall make all determinations as
to rights to benefits under this Program. Any decision by the Company denying a
9
<PAGE>
claim by the Employee or his or her beneficiary for benefits under this Plan
shall be stated in writing and delivered or mailed to the Participant or such
beneficiary hereof. Such notice shall set forth the specific reasons for the
denial, written in a manner that may be understood without legal or actuarial
counsel. In addition, the Company shall afford a reasonable opportunity to the
Participant or such beneficiary for a full and fair review of the decision
denying such claim.
8. The Board (either directly or through its designees) will have power and
authority to interpret, construe, and administer this Program; provided that,
the Board's authority to interpret this Program shall not cause the Board's
decisions in this regard to be entitled to a deferential standard of review in
the event that a Participant or beneficiary seeks review of the Board's decision
as described below. In addition, the Board shall have the power to prospectively
modify or terminate this Program, provided that any such modification or
termination does not result in the elimination of any rights that the
Participant or beneficiary may have under this Program. Absent the consent of
the Participant, however, the Board shall in no event have any authority to
modify this section.
No member of the Board, nor its designee, shall be liable to any person for any
action taken or omitted in connection with the interpretation and administration
of this Program.
In the event of an amendment or termination of any Part of this Program, the
benefits payable on account of a retired or deceased Participant shall not be
impaired, and the benefits of other Participants shall not be less than the
benefits to which each such Participant would have been entitled immediately
prior to such amendment or termination of any Part (or Parts) of the Program.
Because it is agreed that time will be of the essence in determining whether any
payments are due to Participant or his or her beneficiary under this Program, a
Participant or beneficiary may, if he or she desires, submit any claim for
payment under this Program to arbitration. This right to select arbitration
shall be solely that of the Participant or beneficiary and the Participant or
beneficiary may decide whether or not to arbitrate in his or her discretion. The
"right to select arbitration" is not mandatory on the Participant or
beneficiary, and the Participant or beneficiary may choose in lieu thereof to
bring an action in an appropriate civil court. Once an arbitration is commenced,
however, it may not be discontinued without the mutual consent of both parties
to the arbitration. During the lifetime of the Participant only he or she can
use the arbitration procedure set forth in this section.
Any claim for arbitration may be submitted as follows: if Participant or
beneficiary has submitted a request to be paid under this Program and the claim
is finally denied by the Company in whole or in part, such claim may be filed in
writing with an arbitrator of Participant's or beneficiary's choice who is
selected by the method described in the next three sentences. The first step of
the selection shall consist of the Participant or beneficiary submitting a list
of five potential arbitrators to the Company. Each of the five arbitrators must
10
<PAGE>
be either (1) a member of the National Academy of Arbitrators located in the
State of California or (2) a retired California Superior Court or Appellate
Court judge. Within one week after receipt of the list, the Company shall select
one of the five arbitrators as the arbitrator for the dispute in question. If
the Company fails to select an arbitrator within one week after receipt of the
list, the Participant or beneficiary shall then designate one of the five
arbitrators for the dispute in question.
The arbitration hearing shall be held within seven days (or as soon thereafter
as possible) after the picking of the arbitrator. No continuance of said hearing
shall be allowed without the mutual consent of Participant or beneficiary and
the Company. Absence from or nonparticipation at the hearing by either party
shall not prevent the issuance of an award. Hearing procedures which will
expedite the hearing may be ordered at the arbitrator's discretion, and the
arbitrator may close the hearing in his or her sole discretion when he or she
decides he or she has heard sufficient evidence to satisfy issuance of an award.
The arbitrator's award shall be rendered as expeditiously as possible and in no
event later than one week after the close of the hearing.
In the event the arbitrator finds that the Company has breached this Program, he
or she shall order the Company to pay to Participant or beneficiary within two
business days after the decision is rendered the amount then due the Participant
or beneficiary, plus, notwithstanding anything to the contrary in this Program,
an additional amount equal to 20% of the amount actually in dispute. This
additional amount shall constitute an additional benefit under this Program. The
award of the arbitrator shall be final and binding upon the parties.
The award may be enforced in any appropriate court as soon as possible after its
rendition. The Company will be considered the prevailing party in a dispute if
the arbitrator determines (1) that the Company has not breached this Program and
(2) the claim by Participant or his or her beneficiary was not made in good
faith. Otherwise, the Participant or his or her beneficiary will be considered
the prevailing party. In the event that the Company is the prevailing party, the
fee of the arbitrator and all necessary expenses of the hearing (excluding any
attorneys' fees incurred by the Company) including stenographic reporter, if
employed, shall be paid by the losing party. In the event that the Participant
or his or her beneficiary is the prevailing party, the fee of the arbitrator and
all necessary expenses of the hearing (including all attorneys' fees incurred by
Participant or his or her beneficiary in pursuing his or her claim), including
the fees of a stenographic reporter if employed, shall be paid by the Company.
9. If any person entitled to payments under this Program is, in the opinion of
the Board or its designee, incapacitated and unable to use such payments in his
or her own best interest, the Board or its designee may direct that payments (or
any portion thereof) be made to that person's legal guardian or conservator, or
that person's spouse, as an alternative to payment to the person unable to use
11
<PAGE>
the payments. The Board or its designee shall have no obligation to supervise
the use of such payments, and court-appointed guardianship or conservatorship
may be required.
10. Upon written application made to the Board or to its designee, Participant
or his or her designated beneficiary or beneficiaries may request payment in
some form other than the method of payment originally elected. Such request must
establish to the Board's satisfaction that special circumstances, such as
financial hardship, exist which require such a variation in payment. The Board,
or its designee, shall exercise sole discretion in allowing or refusing such
requests, and the decision of the Board or its designee on such requests shall
be final.
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report included in this quarterly report on Form 10-Q for the
quarter ended September 30, 1999, of Southern California Edison Company into the
previously filed Registration Statements which follow:
Registration Form File No. Effective Date
Form S-3 33-53288 November 6, 1992
Form S-3 33-50251 September 21, 1993
Form S-3 333-00497 February 2, 1996
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 10, 1999
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
Exhibit 27
<ARTICLE> UT
<LEGEND>
SCE Financial Data Schedule - Exhibit 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7,419,954
<OTHER-PROPERTY-AND-INVEST> 2,580,655
<TOTAL-CURRENT-ASSETS> 2,098,687
<TOTAL-DEFERRED-CHARGES> 5,506,644
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 17,605,940
<COMMON> 2,168,054
<CAPITAL-SURPLUS-PAID-IN> 353,353
<RETAINED-EARNINGS> 585,375
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3,106,782
255,700
128,755
<LONG-TERM-DEBT-NET> 2,341,972
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 2,879,943
<COMMERCIAL-PAPER-OBLIGATIONS> 690,099
<LONG-TERM-DEBT-CURRENT-PORT> 568,009
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 7,634,680
<TOT-CAPITALIZATION-AND-LIAB> 17,605,940
<GROSS-OPERATING-REVENUE> 5,701,460
<INCOME-TAX-EXPENSE> 317,120
<OTHER-OPERATING-EXPENSES> 4,757,459
<TOTAL-OPERATING-EXPENSES> 5,074,579
<OPERATING-INCOME-LOSS> 626,881
<OTHER-INCOME-NET> 90,284
<INCOME-BEFORE-INTEREST-EXPEN> 717,165
<TOTAL-INTEREST-EXPENSE> 354,074
<NET-INCOME> 363,091
20,253
<EARNINGS-AVAILABLE-FOR-COMM> 342,838
<COMMON-STOCK-DIVIDENDS> 549,138
<TOTAL-INTEREST-ON-BONDS> 276,810
<CASH-FLOW-OPERATIONS> 1,439,331
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
