UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 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 Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California
(Address of principal 91770
executive offices) (Zip Code)
(626) 302-1212
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (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 August 9, 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, Six and
Twelve Months Ended June 30, 1999, and 1998 2
Consolidated Statements of Comprehensive Income --
Three, Six and Twelve Months Ended June 30, 1999,
and 1998 2
Consolidated Balance Sheets -- June 30, 1999,
December 31, 1998, and June 30, 1998 3
Consolidated Statements of Cash Flows --
Three, Six and Twelve Months Ended
June 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 37
Item 6. Exhibits and Reports on Form 8-K 40
<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) and its subsidiaries as of June 30, 1999,
December 31, 1998, and June 30, 1998, and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-, six- and
twelve-month periods ended June 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
June 30, 1999, December 31, 1998, and June 30, 1998, and the results of their
operations and their cash flows for each of the three-, six- and twelve-month
periods ended June 30, 1999, and 1998, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
August 3, 1999
1
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
In thousands
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- -----------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenue $1,720,831 $1,618,782 $3,397,535 3,241,473 $7,655,582 $7,655,424
- -----------------------------------------------------------------------------------------------------------------------
Fuel 45,122 59,184 105,430 177,868 251,278 768,534
Purchased power--contracts 422,754 525,355 1,032,660 1,101,862 2,556,698 2,739,529
Purchased power-- power exchange-- net 97,143 40,099 214,100 40,099 810,343 40,099
Provisions for regulatory
adjustment clauses-- net (81,718) 462,176 (360,748) 158,363 (991,629) (160,549)
Other operating expenses 446,019 400,055 850,297 687,629 1,643,312 1,368,546
Maintenance 106,149 98,492 195,017 200,362 405,222 393,330
Depreciation, decommissioning
and amortization 377,018 375,919 763,295 758,898 1,550,133 1,381,705
Income taxes 82,199 99,158 162,740 224,762 383,620 577,913
Property and other taxes 29,186 31,246 67,471 70,763 125,112 129,582
Net loss (gain) on sale of utility plant (724) (684,838) (2,925) (619,038) 73,502 (620,052)
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,523,148 1,406,846 3,027,337 2,801,568 6,807,591 6,618,637
- -----------------------------------------------------------------------------------------------------------------------
Operating income 197,683 211,936 370,198 439,905 847,991 1,036,787
- -----------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan -- -- -- -- -- (25,796)
Allowance for equity funds
used during construction 3,056 2,908 5,892 5,690 12,028 9,440
Interest and dividend income 16,664 15,411 30,811 33,723 63,813 62,200
Other nonoperating income
(deductions)--net 10,672 (4,310) 23,388 (7,900) 26,904 (41,434)
- -----------------------------------------------------------------------------------------------------------------------
Total other income (deductions)-- net 30,392 14,009 60,091 31,513 102,745 4,410
- -----------------------------------------------------------------------------------------------------------------------
Income before interest expense 228,075 225,945 430,289 471,418 950,736 1,041,197
- -----------------------------------------------------------------------------------------------------------------------
Interest and amortization
on long-term debt 99,819 91,511 198,460 215,868 404,451 379,716
Other interest expense 19,334 16,090 43,470 34,109 73,585 89,414
Allowance for borrowed funds used
during construction (2,652) (1,979) (5,113) (3,871) (9,288) (8,388)
Capitalized interest (272) (125) (1,068) (282) (2,080) (626)
- -----------------------------------------------------------------------------------------------------------------------
Total interest expense--net 116,229 105,497 235,749 245,824 466,668 460,116
- -----------------------------------------------------------------------------------------------------------------------
Net income 111,846 120,448 194,540 225,594 484,068 581,081
Dividends on preferred stock 5,609 6,648 11,808 13,407 23,032 26,925
- -----------------------------------------------------------------------------------------------------------------------
Earnings available for common stock $ 106,237 $ 113,800 $ 182,732 $212,187 $461,036 $ 554,156
- -----------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
Net income $ 111,846 $ 120,448 $ 194,540 $225,594 $484,068 $ 581,081
Unrealized gain (loss) on
securities--net (1,002) 1,332 (7,217) 12,442 (10,384) 12,635
Reclassification adjustment for gains
included in net income (14,874) -- (32,245) -- (50,081) --
- ------------------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 95,970 $ 121,780 $ 155,078 $238,036 $423,603 $ 593,716
- ------------------------------------------------------------------------------------------------------------------------------
</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>
June 30, December 31, June 30,
1999 1998 1998
- -------------------------------------------------------------------------------------------------------------------
ASSETS
Utility plant, at original cost:
<S> <C> <C> <C>
Transmission and distribution $11,975,779 $11,771,678 $11,454,066
Generation 1,705,009 1,689,469 2,021,636
Accumulated provision for depreciation
and decommissioning (7,175,966) (6,896,479) (6,862,735)
Construction work in progress 654,516 516,664 567,235
Nuclear fuel, at amortized cost 163,281 172,250 133,070
- -------------------------------------------------------------------------------------------------------------------
Total utility plant 7,322,619 7,253,582 7,313,272
- -------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated
provision for depreciation of $8,307, $25,682
and $24,990 at respective dates 73,225 56,681 66,251
Nuclear decommissioning trusts 2,357,155 2,239,929 2,056,275
Other investments 124,375 179,480 237,627
- -------------------------------------------------------------------------------------------------------------------
Total other property and investments 2,554,755 2,476,090 2,360,153
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents 72,439 81,500 830,942
Receivables, including unbilled revenue, less
allowances of $23,266, $22,230 and $20,754
for uncollectible accounts at respective dates 1,062,376 1,112,630 1,030,792
Fuel inventory 52,963 51,299 50,965
Materials and supplies, at average cost 116,191 116,259 116,678
Accumulated deferred income taxes-- net 92,795 274,833 313,360
Regulatory balancing accounts-- net 1,103,765 648,781 50,234
Prepayments and other current assets 17,470 91,992 15,140
- -------------------------------------------------------------------------------------------------------------------
Total current assets 2,517,999 2,377,294 2,408,111
- -------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net 1,763,390 2,161,998 2,561,325
Income tax-related deferred charges 1,440,617 1,463,256 1,559,336
Unamortized debt issuance and reacquisition expense 343,126 348,816 362,125
Other deferred charges 1,032,117 865,892 816,595
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 4,579,250 4,839,962 5,299,381
- -------------------------------------------------------------------------------------------------------------------
Total assets $16,974,623 $16,946,928 $17,380,917
- -------------------------------------------------------------------------------------------------------------------
</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>
June 30, December 31, June 30,
1999 1998 1998
- -------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
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 334,031 334,031 334,032
Accumulated other comprehensive income - 39,462 60,465
Retained earnings 694,161 793,625 1,078,982
- -------------------------------------------------------------------------------------------------------------------
3,196,246 3,335,172 3,641,533
- -------------------------------------------------------------------------------------------------------------------
Preferred stock:
Not subject to mandatory redemption 128,755 128,755 128,755
Subject to mandatory redemption 255,700 255,700 256,700
Long-term debt 5,297,014 5,446,638 5,540,461
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 8,877,715 9,166,265 9,567,449
- -------------------------------------------------------------------------------------------------------------------
Other long-term liabilities 742,298 467,109 495,703
- -------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt 569,229 400,810 610,332
Short-term debt 407,115 469,565 121,555
Accounts payable 385,763 447,484 396,363
Accrued taxes 698,505 678,955 895,472
Accrued interest 115,456 89,828 94,448
Dividends payable 94,347 91,742 92,893
Deferred unbilled revenue and other current liabilities 1,159,488 1,096,332 1,049,308
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,429,903 3,274,716 3,260,371
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 2,877,011 2,993,142 2,956,964
Accumulated deferred investment tax credits 228,586 250,116 308,380
Customer advances and other deferred credits 818,785 795,266 790,980
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits 3,924,382 4,038,524 4,056,324
- -------------------------------------------------------------------------------------------------------------------
Minority interest 325 314 1,070
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $16,974,623 $16,946,928 $17,380,917
===================================================================================================================
</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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- ------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
<S> <C> <C> <C> <C> <C> <C>
Net income $111,846 $120,448 $194,540 $225,594 $484,068 $581,081
Adjustments for non-cash items:
Depreciation, decommissioning and
amortization 377,018 375,919 763,295 758,898 1,550,133 1,381,705
Other amortization 22,506 24,376 43,124 37,532 94,915 86,914
Deferred income taxes and
investment tax credits (15,549) (308,917) 67,016 (207,025) 179,537 (135,627)
Other long-term liabilities 28,788 1,333 81,311 16,066 52,717 (10,363)
Regulatory asset related to sale of
oil & gas plant -- (9,950) 241 (107,991) (112,000) (107,991)
Net loss (gain) on sale of oil & gas plant 14 (702,972) (1,110) (640,339) 74,606 (640,339)
Other-- net 4,117 (14,171) (20,202) (15,516) 2,912 (131,437)
Changes in working capital:
Receivables (14,272) (279,473) 50,254 (124,404) (31,584) (48,782)
Regulatory balancing accounts (129,575) 444,844 (454,984) 143,077 (1,053,531) (136,750)
Fuel inventory, materials and supplies 2,656 17,099 (1,596) 23,396 (1,511) 47,389
Prepayments and other current assets 37,395 39,299 74,522 77,958 (2,330) 2,138
Accrued interest and taxes 40,091 348,291 45,178 395,244 (175,959) 242,063
Accounts payable and other
current liabilities (5,187) 226,755 1,435 107,111 99,580 289,988
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 459,848 282,881 843,024 689,601 1,161,553 1,419,989
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 355,540 -- 355,540 -- 355,540 --
Long-term debt repaid (217,462) (150,014) (217,462) (604,455) (389,037) (1,320,545)
Rate reduction notes issued -- -- -- -- -- 2,444,127
Rate reduction notes repaid (49,229) (65,354) (119,760) (82,465) (288,886) (77,303)
Preferred stock redeemed -- (73,300) -- (73,300) (1,000) (73,300)
Nuclear fuel financing-- net (180) (10,248) (9,016) (18,871) 26,099 (31,950)
Short-term debt financing-- net (222,082) (223,686) (62,450) (200,473) 285,560 (23,689)
Capital transferred -- -- -- -- -- 153,000
Dividends paid (116,890) (451,938) (289,015) (553,022) (865,804) (2,126,825)
- ------------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (250,303) (974,540) (342,163) (1,532,586) (877,528) (1,056,485)
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (244,293) (169,068) (475,137) (337,046) (998,928) (738,720)
Proceeds from sale of oil and gas plant -- 1,115,238 -- 1,145,039 58,000 1,145,039
Funding of nuclear decommissioning trusts (29,298) (37,198) (66,424) (76,881) (152,467) (156,064)
Unrealized gain (loss) on securities-- net (15,876) 1,332 (39,462) 12,442 (60,465) 12,635
Other-- net 30,051 (1,178) 71,101 (31,899) 111,332 (34,833)
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by
investing activities (259,416) 909,126 (509,922) 711,655 (1,042,528) 228,057
- ------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash
and equivalents (49,871) 217,467 (9,061) (131,330) (758,503) 591,561
Cash and equivalents, beginning
of period 122,310 613,475 81,500 962,272 830,942 239,381
- ------------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 72,439 $830,942 $ 72,439 $830,942 $ 72,439 $830,942
- ------------------------------------------------------------------------------------------------------------------------
Cash payments for interest and taxes:
Interest-- net of amounts capitalized $ 49,695 $ 50,859 $117,313 $125,667 $255,390 $291,503
Taxes -- 416 12 426 407,919 420,956
</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 June 30, 1999, financial statement
presentation.
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 with the PX are reported as Purchased power - power exchange - net.
Generation sales through the PX were $360 million, $642 million and $1.7 billion
for the three, six and twelve months ended June 30, 1999, respectively, and $304
million for each of the same periods ended June 30, 1998. Purchases from the PX
were $457 million, $856 million and $2.5 billion for the three, six and twelve
months ended June 30, 1999, respectively, and $344 million for each of the same
periods ended June 30, 1998.
SCE's outstanding common stock is owned entirely by its parent company, Edison
International.
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.
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.
6
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 through 2002.
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 their 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
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.
7
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 through the CTC.
Regulatory assets and liabilities included in the consolidated balance sheets
are comprised of:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
In millions 1999 1998 1998
- ----------------------------------------------------------------------------------------------------------------
Generation-related:
<S> <C> <C> <C>
Unamortized nuclear investment-- net $ 1,763 $ 2,162 $ 2,576
Flow-through taxes 407 614 768
Rate reduction notes-- transition cost deferral 515 315 209
Unamortized loss on sale of plant 152 183 101
Purchased-power settlements 311 130 138
Environmental remediation 16 16 16
Regulatory balancing accounts and other 634 354 (33)
- ----------------------------------------------------------------------------------------------------------------
Subtotal 3,798 3,774 3,775
- ----------------------------------------------------------------------------------------------------------------
Other:
Flow-through taxes 1,034 849 791
Unamortized loss of reacquired debt 303 308 319
Environmental 118 125 130
Regulatory balancing accounts and other 74 110 28
- ----------------------------------------------------------------------------------------------------------------
Subtotal 1,529 1,392 1,268
- ----------------------------------------------------------------------------------------------------------------
Total $ 5,327 $ 5,166 $5,043
- ----------------------------------------------------------------------------------------------------------------
</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. In accordance with asset impairment accounting
standards, SCE reduced its remaining nuclear plant investment by $2.6 billion
(as of June 30, 1998) and recorded a regulatory asset on its balance sheet for
the same amount. For this impairment assessment, the fair value of the
investment was calculated by discounting expected future net cash flows. This
reclassification had no effect on SCE's results of operations.
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 $1.8
billion, after tax, at June 30, 1999) as a one-time, non-cash charge against
earnings.
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
8
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 year.
Utility Plant
Plant additions, including replacements and betterments, are capitalized. Such
costs for utility property 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 3.7%, for the three,
six and twelve months ended June 30, 1999, and 3.5%, 5.5% and 5.9% for the
three, six and twelve months ended June 30, 1998, respectively.
SCE's net investment in generation-related utility plant was $1.1 billion at
June 30, 1999, and December 31, 1998, and $4.4 billion at June 30, 1998.
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. A final FERC decision is expected late 1999. SCE does not expect the final
decision to have a material effect on its results of operations or financial
position.
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
9
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Two proposed decisions issued in March 1999 rejected SCE's request for a
determination of eligibility for several major categories of such costs. In May
1999, SCE, the CPUC's Office of Ratepayer Advocates and several other parties
entered into a settlement agreement that would allow SCE to recover
substantially all (approximately $319 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. The CPUC has withdrawn its earlier proposed decisions
on SCE's application. On July 6, 1999, a proposed decision was issued that would
approve the settlement in its entirety. A final CPUC decision on the settlement
is expected in third quarter 1999.
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. 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 purchased from the PX. The options cover various periods from 1998
through 2001. Additionally, SCE has been granted CPUC approval to participate in
forward purchases through a PX block forward market.
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
mark-to-market gains or losses have no effect on earnings. Block forward
purchases will 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 June
30, 1999, December 31, 1998, and June 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 June 30, 1999, SCE had pledged $26 million as collateral due to
a decline in market interest rates. SCE is exposed to credit loss
10
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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>
June 30, December 31, June 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 $1,601 $2,357 $1,534 $2,240 $1,448 $2,056
Equity investments -- -- 7 72 9 110
Gas call options 34 21 39 31 44 56
Financial liabilities:
DOE decommissioning and
decontamination fees $ 45 $ 39 $ 45 $ 40 $ 50 $ 44
Interest rate swap -- 19 -- 28 -- 25
Long-term debt 5,297 5,337 5,447 5,699 5,540 5,708
Preferred stock subject to
mandatory redemption 256 264 256 274 257 273
==============================================================================================================
</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>
June 30, December 31, June 30,
In millions 1999 1998 1998
- ----------------------------------------------------------------------------------------------------------
Decommissioning trusts:
<S> <C> <C> <C>
Municipal bonds $190 $196 $163
Stocks 401 365 311
U.S. government issues 132 115 129
Short-term and other 34 30 5
- ----------------------------------------------------------------------------------------------------------
757 706 608
Equity investments -- 65 101
Gas call options (13) (8) 12
- ----------------------------------------------------------------------------------------------------------
Total $744 $763 $721
==========================================================================================================
</TABLE>
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
June 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
11
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 a separate
component of shareholder's equity under the caption: Accumulated other
comprehensive income. Unrealized gains and losses on decommissioning trust funds
are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged
first and refunding mortgage bonds as security for borrowed funds obtained from
pollution-control bonds issued by government agencies. SCE uses these proceeds
to finance construction of pollution-control facilities. Bondholders have
limited discretion in redeeming certain pollution-control bonds, and SCE has
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 June 30, 1999, are: 2000 -- $569 million; 2001 --
$648 million; 2002 -- $246 million; 2003 -- $572 million; and 2004 -- $247
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 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 liabilities
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.
12
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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>
June 30, December 31, June 30,
In millions 1999 1998 1998
- ---------------------------------------------------------------------------------------------------------------
First and refunding mortgage bonds:
<S> <C> <C> <C> \
2000 - 2026 (5.625% to 7.25%) $1,400 $1,550 $1,550
Rate reduction notes:
1999 - 2007 (6.14% to 6.42%) 2,096 2,217 2,385
Pollution-control bonds:
1999 - 2029 (5.4% to 7.2% and
variable) 1,201 1,201 1,202
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 99 108 73
Long-term debt due within one year (569) (401) (610)
Unamortized debt discount-- net (28) (26) (28)
- ---------------------------------------------------------------------------------------------------------------
Total $5,297 $5,447 $5,540
===============================================================================================================
</TABLE>
Short-Term Debt
SCE has lines of credit totaling $1.3 billion that can be used at negotiated or
bank index rates. At June 30, 1999, $300 million was available for short-term
debt and $500 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 June 30, 1999,
December 31, 1998, and June 30, 1998, was $508 million, $581 million and $196
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 5.0%, 5.3% and 5.6% at June 30, 1999, December 31, 1998, and June 30,
1998, respectively.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. At June 30, 1999, SCE had the capacity to pay $694 million
in additional dividends and continue to maintain its authorized capital
structure.
13
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in SCE's common shareholder's equity were as follows:
Three months ended June 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>
Balance at March 31, 1998 $2,168 $ 334 $ 60 $1,408 $3,970
- ---------------------------------------------------------------------------------------------------------------------
Net income 120 120
Unrealized gain on securities 1 1
Dividends declared on common stock (442) (442)
Dividends declared on preferred stock (7) (7)
- ---------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1998 $2,168 $ 334 $ 61 $1,079 $3,642
- ---------------------------------------------------------------------------------------------------------------------
Balance at March 31, 1999 $2,168 $ 334 $ 16 $ 700 $3,218
- ---------------------------------------------------------------------------------------------------------------------
Net income 112 112
Unrealized gain on securities (2) (2)
Tax effect 1 1
Reclassified adjustment for gains
included in net income (25) (25)
Tax effect 10 10
Dividends declared on common stock (111) (111)
Dividends declared on preferred stock (6) (6)
Stock option appreciation (1) (1)
- ---------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1999 $2,168 $ 334 $ - $ 694 $3,196
- ---------------------------------------------------------------------------------------------------------------------
Six months ended June 30 1998, and 1999:
- ---------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 $2,168 $ 334 $ 48 $1,408 $3,958
- ---------------------------------------------------------------------------------------------------------------------
Net income 226 226
Unrealized gain on securities 20 20
Tax effect (7) (7)
Dividends declared on common stock (538) (538)
Dividends declared on preferred stock (13) (13)
Stock option appreciation (3) (3)
Required capital stock expense and other (1) (1)
- ---------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1998 $2,168 $ 334 $ 61 $1,079 $3,642
- ---------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $2,168 $ 334 $ 39 $794 $3,335
- ---------------------------------------------------------------------------------------------------------------------
Net income 195 195
Unrealized gain on securities (10) (10)
Tax effect 3 3
Reclassified adjustment for gains included
in net income (54) (54)
Tax effect 22 22
Dividends declared on common stock (280) (280)
Dividends declared on preferred stock (12) (12)
Stock option appreciation (3) (3)
- ---------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1999 $2,168 $ 334 $ - $694 $3,196
=====================================================================================================================
</TABLE>
14
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Twelve months ended June 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>
Balance at June 30, 1997 $2,168 $ 178 $ 48 $2,554 $4,948
- ---------------------------------------------------------------------------------------------------------------------
Net income 581 581
Unrealized gain on securities 20 20
Tax effect (7) (7)
Dividends declared on common stock (2,022) (2,022)
Dividends declared on preferred stock (27) (27)
Stock option appreciation (3) (3)
Required capital stock expense and other (4) (4)
Additional investment from parent company 156 156
- ----------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1998 $2,168 $ 334 $ 61 $1,079 $3,642
- ----------------------------------------------------------------------------------------------------------------------
Net income 484 484
Unrealized gain on securities (17) (17)
Tax effect 6 6
Reclassified adjustment for gains included
in net income (84) (84)
Tax effect 34 34
Dividends declared on common stock (843) (843)
Dividends declared on preferred stock (23) (23)
Stock option appreciation (3) (3)
- ---------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1999 $2,168 $ 334 $ - $694 $3,196
- ---------------------------------------------------------------------------------------------------------------------
</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 June 30, 1999, are: 2000 through 2001-- zero; 2002--$105 million;
2003-- $9 million; and 2004-- $9 million.
15
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
Dollars in millions, except per-share amounts 1999 1998 1998
- ------------------------------------------------------------------------------------------------------------------
June 30, 1999
---------------------------
Shares Redemption
Outstanding Price
---------------------------
Not subject to mandatory redemption:
$25 par value:
<S> <C> <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% 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 82
- ------------------------------------------------------------------------------------------------------------------
Total $ 256 $256 $ 257
- ------------------------------------------------------------------------------------------------------------------
</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 5.8%
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 its 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>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net accumulated deferred income tax liability were:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
In millions 1999 1998 1998
- ----------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
<S> <C> <C> <C>
Property-related $194 $197 $203
Unrealized gains or losses 402 387 326
Investment tax credits 140 152 156
Regulatory balancing accounts 122 96 77
Decommissioning-related 128 126 118
Unbilled revenue 103 117 48
Other 321 356 364
- ----------------------------------------------------------------------------------------------------------------------
Total $1,410 $1,431 $1,292
- ----------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $2,817 $3,005 $3,102
Capitalized software costs 221 196 156
Regulatory balancing accounts 337 162 --
Decommissioning-related 300 284 233
Other 519 502 445
- ----------------------------------------------------------------------------------------------------------------------
Total $4,194 $4,149 $3,936
- ----------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net $2,784 $2,718 $2,644
- ----------------------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $2,877 $2,993 $2,957
Included in current assets 93 275 313
The current and deferred components of income tax expense were:
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Current:
Federal $70 $331 $64 $355 $159 $554
State 21 74 18 78 41 123
- -------------------------------------------------------------------------------------------------------------------
91 405 82 433 200 677
- -------------------------------------------------------------------------------------------------------------------
Deferred -- federal and state:
Accrued charges (34) 17 15 (14) (14) (34)
Ad valorem lien date adjustment (2) (6) 4 2 (1) 2
Amortization of regulatory assets 9 (38) 12 (10) 86 (10)
Contributions in aid of construction (4) (4) -- 2 (8) (3)
Depreciation (50) (12) (96) (84) (181) (108)
Investment and energy tax credits-- net (11) (12) (22) (16) (80) (26)
Regulatory balancing accounts 92 (225) 137 (116) 430 (12)
State tax-- privilege year (7) (24) 28 7 20 (8)
Unbilled revenue 1 (12) 14 2 (55) 15
Other 1 8 -- 11 -- 31
- -------------------------------------------------------------------------------------------------------------------
(5) (308) 92 (216) 197 (153)
Total income tax expense $86 $ 97 $174 $217 $397 $524
===================================================================================================================
Classification of income taxes:
Included in operating income $82 $ 99 $163 $225 $384 $578
Included in other income 4 (2) 11 (8) 13 (54)
</TABLE>
The composite federal and state statutory income tax rate was 40.551% for the
three, six and twelve months ended June 30, 1999, and 1998.
17
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The federal statutory income tax rate is reconciled to the effective tax rate
below:
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- ---------------------------------------------------------------------------------------------------------------------
In millions 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 (0.5) (0.6) 0.7 -- (0.5) --
Amortization of regulatory assets 4.0 (17.4) 3.0 (2.2) 9.5 (0.9)
Capitalized software (1.7) 2.0 (1.3) (1.0) (0.8) (1.0)
Property-related and other 1.9 19.2 6.9 12.0 2.9 9.3
Investment and energy tax credits (5.2) (2.0) (5.6) (2.0) (8.7) (1.7)
State tax-- net of federal deduction 9.9 8.2 8.2 6.7 7.5 6.6
- ---------------------------------------------------------------------------------------------------------------------
Effective tax rate 43.4% 44.4% 46.9% 48.5% 44.9% 47.3%
- ---------------------------------------------------------------------------------------------------------------------
</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 $7
million, $12 million and $21 million for the three, six and twelve months ended
June 30, 1999, respectively; and $5 million, $8 million and $15 million for the
three, six and twelve months ended June 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>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information on plan assets and benefit obligations is shown below:
<TABLE>
<CAPTION>
6 Months Ended Year Ended 6 Months Ended
June 30, December 31, June 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 34 59 28
Interest cost 76 141 70
Plan amendments (25) -- --
Actuarial loss -- 90 --
Benefits paid (66) (133) (68)
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $2,270 $ 2,251 $ 2,124
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $2,552 $ 2,298 $ 2,298
Actual return on plan assets 218 334 287
Employer contributions 34 53 30
Benefits paid (66) (133) (68)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $2,738 $ 2,552 $ 2,547
- -------------------------------------------------------------------------------------------------------------------
Funded status $ 468 $ 301 $ 423
Unrecognized net loss (gain) (490) (372) (498)
Unrecognized transition obligation (17-year amortization) 31 33 36
Unrecognized prior service cost 136 168 174
- -------------------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ 145 $ 130 $ 135
- -------------------------------------------------------------------------------------------------------------------
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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 16 $ 14 $ 34 $ 28 $ 65 $ 50
Interest cost 38 35 76 70 147 139
Expected return on plan assets (48) (45) (96) (90) (176) (170)
Net amortization and deferral 2 4 5 8 11 13
- -------------------------------------------------------------------------------------------------------------------
Pension expense under accounting standards 8 8 19 16 47 32
Regulatory adjustment-- deferred 5 5 7 10 8 20
- -------------------------------------------------------------------------------------------------------------------
Net pension expense recognized $ 13 $ 13 $ 26 $ 26 $ 55 $ 52
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
19
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Information on plan assets and benefit obligations is shown below:
<TABLE>
<CAPTION>
6 Months Ended Year Ended 6 Months Ended
June 30, December 31, June 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 22 41 18
Interest cost 52 99 52
Actuarial loss (gain) -- (74) --
Benefits paid (30) (54) (32)
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ 1,589 $ 1,545 $ 1,571
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period $ 1,029 $ 815 $ 815
Actual return on plan assets 38 147 32
Employer contributions 50 121 54
Benefits paid (30) (54) (32)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period $ 1,087 $ 1,029 $ 869
- -------------------------------------------------------------------------------------------------------------
Funded status $ (502) $ (516) $ (702)
Unrecognized net loss 84 84 242
Unrecognized transition obligation (20-year
amortization) 362 376 389
- -------------------------------------------------------------------------------------------------------------
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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
- --------------------------------------------------------------------------------------------------------------
In millions 1999 1998 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 11 $ 9 $ 22 $ 18 $ 45 $ 34
Interest cost 26 26 52 52 99 101
Expected return on plan assets (19) (16) (38) (32) (68) (56)
Amortization of loss (gain) -- 1 -- 2 (1) 2
Amortization of transition obligation 7 7 14 14 27 27
- --------------------------------------------------------------------------------------------------------------
Total expense $ 25 $ 27 $ 50 $ 54 $ 102 $ 108
- --------------------------------------------------------------------------------------------------------------
</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 June 30, 1999, by $268 million and
annual aggregate service and interest costs by $33 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of June 30, 1999, by $214 million and annual aggregate
service and interest costs by $25 million.
20
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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, six and twelve months ended June 30, 1999, respectively, and $1 million,
$2 million and $4 million for the three, six and twelve months ended June 30,
1998, respectively.
21
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-based compensation expense under the fair-value method of accounting would
have resulted in pro forma earnings of $106 million, $182 million and $460
million for the three, six and twelve months ended June 30, 1999, respectively;
and $114 million, $212 million and $553 million for the three, six and twelve
months ended June 30, 1998, respectively.
The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:
12 Months Ended
June 30,
- ----------------------------- -------------------------- --------------------
1999 1998
- ----------------------------- -------------------------- --------------------
Expected life 7 years 7 years
Risk-free interest rate 4.7% - 5.6% 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 June 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 $ 33 $ 6 $ 3 60%
Pacific Intertie 239 80 8 50
Generating stations:
Four Corners Units 4 and 5 (coal) 459 311 2 48
Mohave (coal) 319 199 6 56
Palo Verde (nuclear)(1) 1,608 1,030 14 16
San Onofre (nuclear)(1) 4,257 3,011 25 75
- ------------------------------------------------------------------------------------------------------------
Total $ 6,915 $4,637 $58
- ------------------------------------------------------------------------------------------------------------
(1) Reported as "Unamortized nuclear investment -- net."
</TABLE>
22
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.
Estimated remaining commitments for noncancellable leases at June 30,1999, were:
Year ended December 31, In millions
- -------------------------------------------------------------------------
1999 $ 7
2000 12
2001 9
2002 6
2003 4
Thereafter 7
- -------------------------------------------------------------------------
Total $45
- -------------------------------------------------------------------------
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. 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 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.
Decommissioning expense was $31 million, $70 million and $157 million for the
three, six and twelve months ended June 30, 1999, respectively, and $37 million,
$77 million and $157 million for the three, six and twelve months ended June 30,
1998, respectively. The accumulated provision for decommissioning, excluding San
Onofre Unit 1, was $1.3 billion at June 30, 1999, $1.2 billion at December 31,
1998, and $1.1 billion at June 30, 1998. The estimated costs to decommission San
Onofre Unit 1 ($368 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 June 30, December 31, June 30,
In millions Dates 1999 1998 1998
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Municipal bonds 2000 - 2033 $ 554 $ 547 $ 486
Stocks - 533 550 535
U.S. government issues 1999 - 2029 417 355 425
Short-term and other 1999 - 2030 97 82 2
- -----------------------------------------------------------------------------------------------------------------
Total $ 1,601 $ 1,534 $ 1,448
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
23
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $10
million, $24 million and $59 million for the three, six and twelve months ended
June 30, 1999, respectively; and $12 million, $27 million and $57 million for
the three, six and twelve months ended June 30, 1998, respectively. Proceeds
from sales of securities (which are reinvested) were $689 million, $1.1 billion
and $1.7 billion for the three, six and twelve months ended June 30, 1999,
respectively; and $362 million, $569 million and $903 million for the three, six
and twelve months ended June 30, 1998, respectively. Approximately 90% of the
trust fund contributions were tax-deductible.
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase.
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.
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 $963 $816 $716 $643 $641
Fuel supply contracts 161 137 124 141 133
Purchased-power capacity payments 654 629 627 625 620
Unconditional purchase obligations 9 10 10 9 10
- --------------------------------------------------------------------------------------------------------
</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,
24
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
experience gained at similar sites, and the probable level of involvement and
financial condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and maintenance,
monitoring and site closure. Unless there is a probable amount, SCE records the
lower end of this reasonably likely range of costs (classified as other
long-term liabilities at undiscounted amounts).
SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $167 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 $285 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 $86 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 $134 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 June
30, 1999, were $14 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
25
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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
Federal law requires the DOE to select and develop repositories for, and oversee
disposal of, spent nuclear fuel and high-level radioactive waste. The law
requires the DOE to provide for the disposal of spent nuclear fuel and
high-level radioactive waste from nuclear generation stations beginning January
31, 1998. However, the DOE did not meet its obligation. It is not certain when
the DOE will begin accepting spent nuclear fuel from San Onofre or from other
nuclear power plants.
SCE 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.
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.
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, six and
twelve months ended June 30, 1999, were $106 million, $183 million and $461
million, respectively, compared with $114 million, $212 million and $554 million
for the same periods in 1998. The decreases were mainly due to the scheduled
refueling outages at San Onofre Nuclear Generating Station Units 2 and 3 during
the first half of 1999. The twelve-months-ended decrease was also due to lower
authorized revenue, which resulted from reduced authorized returns on generation
assets and a lower earning asset base resulting from the accelerated recovery of
investments and divestiture of gas- and oil-fueled generation plants.
Operating Revenue
Operating revenue increased 6% and 5%, respectively, for the three and six
months ended June 30, 1999, compared to the year-earlier periods. The increases
resulted primarily from maintenance service SCE is providing the new owners of
the divested gas- and oil-fueled plants. 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 (financed through the issuance of rate reduction notes) 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 discussion in Regulatory Environment below.
Operating Expenses
Fuel expense decreased 24%, 41% and 67%, respectively, for the three, six and
twelve months ended June 30, 1999, compared with the same periods in 1998,
primarily due to the sale of the gas- and oil-fueled generation plants in 1998.
Since April 1, 1998, SCE has been required to sell all of its generated power
through the power exchange (PX) and acquire all of its power from the PX to
distribute to its retail customers. These transactions with the PX are reported
net. PX purchased-power expense increased for the quarter ended June 30, 1999,
compared to the year-earlier period, due to higher prices in May and June of
1999. 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 sold through the PX. Purchased-power expense --
contracts decreased for the three, six and twelve months ended June 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 prices under
these contracts are generally higher than other sources. For the twelve months
ended June 30, 1999, SCE paid about $1.6 billion (including energy and capacity
payments) more for these power purchases than the cost of power available from
other sources.
Provisions for regulatory adjustment clauses decreased for the three, six and
twelve months ended June 30, 1999, compared to the year-earlier periods, mostly
due to undercollections related to the difference between generation-related
revenue and generation-related costs. (See discussion in Revenue and
Cost-Recovery Mechanisms.)
Other operating expenses increased 11%, 24% and 20%, respectively, for the
three, six and twelve months ended June 30, 1999, primarily due to mandated
transmission service (known as must-run
27
<PAGE>
reliability services) payments to the independent system operator (ISO). The
six- and twelve-months-ended increases also reflect direct access activities,
and PX and other ISO costs incurred by SCE.
Depreciation, decommissioning and amortization expense increased 12% for the
twelve months ended June 30, 1999, compared to the prior-year period, primarily
due to the further acceleration of recovery of San Onofre Units 2 and 3 and the
Palo Verde Nuclear Generating Station units, accelerated recovery of the gas-
and oil-fueled generation plants (before their sale during 1998), and the
amortization of the loss on plant sales. The amortization of the loss on plant
sales, as well as the accelerated recoveries implemented in 1998 are part of the
competition transition charge (CTC) mechanism.
Income taxes decreased for the three, six and twelve months ended June 30, 1999,
compared to the same periods in 1998, primarily due to lower pre-tax income.
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 and Deductions
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 (deductions) increased for the three, six and twelve
months ended June 30, 1999, compared to the prior-year periods, primarily due to
the gains on sales of equity investments. The twelve-month-ended increase is
also due to 1997 accruals for regulatory matters.
Interest Expense
Other interest expense increased for the three and six months ended June 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. For the twelve months ended June 30, 1999, compared to the year-earlier
period, other interest expense decreased primarily due to lower overall
short-term debt balances, particularly short-term debt used to finance fuel
inventories. The majority of these fuel inventories are no longer needed because
of the divestiture of the gas- and oil-fueled plants in 1998.
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.
SCE's cash flow coverage of dividends for the three, six and twelve months ended
June 30, 1999, was 3.9 times, 2.9 times and 1.3 times, respectively, compared to
0.6 times, 1.2 times and 0.7 times for the year-earlier periods. The increases
in 1999 reflect the special dividends SCE paid to Edison International ($350
million in second quarter 1998 from the gas- and oil-fueled plant sales proceeds
and $1.2 billion in December 1997 from the rate reduction note proceeds).
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $460 million, $843 million and
$1.2 billion, respectively, for the three, six and twelve months ended June 30,
1999, compared with $283 million, $690 million and
28
<PAGE>
$1.4 billion for the same periods in 1998. Cash from operations exceed capital
requirements for all periods presented.
Cash Flows from Financing Activities
At June 30, 1999, SCE had total credit lines of $1.3 billion, with $300 million
available for general purpose, short-term debt and $500 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 June 30, 1999, SCE could issue approximately $11.4 billion of
additional first and refunding mortgage bonds and $3.7 billion of preferred
stock at current interest and dividend rates.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure,
limiting the dividends it may pay Edison International. At June 30, 1999, SCE
had the capacity to pay $694 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
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, and bear interest at 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.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, proceeds from the sale of plant (see 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, effective June 3, 1999, receive SCE contributions of approximately $25
million per year.
29
<PAGE>
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 of $250/MW 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 of $250/MWh 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 ISO is in the process of replacing the price
caps currently used in its markets with a price volatility limit mechanism to be
implemented after the summer of 1999. This limit mechanism would act to prevent
unduly large day-to-day increases in prices. SCE has entered into hedges against
high natural gas prices, since increases in natural gas prices tend to raise the
price of electricity purchased from the PX. In July 1999, SCE began
participating in forward purchases through a PX block forward market. 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.
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 $18 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in an $11 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--
$963 million; 2000-- $816 million; 2001-- $716 million; 2002-- $643 million; and
2003-- $641 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 1999, are: 2000 -- $569 million; 2001 --
$648 million; 2002 -- $246 million; 2003 -- $572 million; and 2004 -- $247
million.
Preferred stock redemption requirements for the five twelve-month periods
following June 30, 1999, are: 2000 through 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
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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 detailed discussion below) that
provides utilities the opportunity to recover costs made uneconomic by electric
utility restructuring.
Revenue and Cost-Recovery Mechanisms
In 1999, revenue is being 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-only 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
of prior legislative and regulatory mandates, and $4.2 billion from costs
pertaining to certain generating assets (including the 1998 sale of SCE's gas-
and oil-fueled generation 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. Revenue related to fossil and hydroelectric generation
operations is recovered from two sources. The portion 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 will earn a 7.22%
return.
The CPUC authorized revised rate-making plans for SCE's nuclear facilities,
which call for the accelerated recovery of the nuclear investments 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
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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 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.
The CPUC considered unbundling SCE's cost of capital by authorizing separate
rates of return for generation, transmission and distribution operations. In May
1998, SCE filed an application on this issue and hearings were completed in
October 1998. On June 10, 1999, the CPUC issued a decision which retains SCE's
return on equity at 11.6%.
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 has filed comments
opposing the proposed decision. A final FERC decision is expected in late 1999.
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.
Two proposed decisions issued in March 1999 rejected SCE's request for a
determination of eligibility for several major categories of such costs. In May
1999, SCE, the CPUC's Office of Ratepayer Advocates and several other parties
entered into a settlement agreement that would allow SCE to recover
substantially all (approximately $319 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. The CPUC has withdrawn its earlier proposed decisions
on SCE's application. On July 6, 1999, a proposed decision was issued that would
approve the settlement in its entirety. A final CPUC decision on the settlement
is expected in third quarter 1999.
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
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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 $1.8
billion, after tax, at June 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 $167 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 $285
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 $86 million of its recorded liability, through an incentive
mechanism. Under this mechanism, SCE will recover 90% of cleanup costs through
customer rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. Costs
incurred at SCE's remaining sites are expected to be recovered through customer
rates. SCE has recorded a regulatory asset of $134 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 June
30, 1999, were $14 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
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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. On June 17,
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
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.
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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, working with
SCE and its departments. 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.
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 in 1999 will 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.
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 continuing. 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 certain of 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 $72
million, about 35% of which is expected to be capital costs. SCE's Year 2000
costs expended through June 30, 1999, were $54 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/or remain ready for the Year 2000.
SCE believes that prudent
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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 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 has worked with, and will continue to work
with, these industry groups, as well as the Electric Power Research Institute,
regarding its contingency plans. Initial development of these plans was
completed in June 1999. SCE filed a report on its contingency plans with the
CPUC on July 1, 1999. Contingency plans will be used in conducting SCE and
electric industry drills throughout the rest 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.
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, 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; changes in market interest rates; new or
increased environmental liabilities; 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
portions of the second
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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 stay is in effect through and including September 30, 1999. 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 was
successful in removing itself from those actions, and is no longer actively
involved in them, the impact on SCE, if any, from further proceedings in those
cases against the remaining defendants can not be determined at this time.
38
<PAGE>
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. Settement
discussions are ongoing.
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's response to the complaint is due on September 9, 1999.
39
<PAGE>
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 March 31, 1999)*
10.1 Form of Agreement for 1999 Director Awards under the Equity
Compensation Plan
10.2 Estate and Financial Planning Program as amended April 1, 1999
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
June 18, 1999 Item 5: Other Events: Navajo Nation Lawsuit*
- ---------------------
* Incorporated by reference pursuant to Rule 12b-32.
40
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By THOMAS M. NOONAN
--------------------------------------------------
THOMAS M. NOONAN
Vice President and Controller
By KENNETH S. STEWART
-------------------------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
August 12, 1999
EXHIBIT 10.1
EDISON INTERNATIONAL LOGO
EQUITY COMPENSATION PLAN
1999 DIRECTOR AWARD CERTIFICATE
This award is made by Edison International to __________________________
("Director"), as of April 15, 1999, pursuant to the Equity Compensation Plan
("Plan"). Edison International hereby grants to Director, as a matter of
separate arrangement and not in lieu of any other compensation for services, the
following:
--------------------------------------------------------------------
500 shares of Edison International Common Stock to be issued as soon
as practicable in accordance with the Director's instructions, and
300 Edison International deferred stock units to be credited under
the Director Deferred Compensation Plan.
--------------------------------------------------------------------
The deferred stock unit award is made subject to the terms and conditions
contained in the Director Deferred Compensation Plan which are incorporated
herein by reference.
Edison International
By: LILLIAN GORMAN
-------------------------
LILLIAN GORMAN
EXHIBIT 10.2
SOUTHERN CALIFORNIA EDISON COMPANY
ESTATE AND FINANCIAL PLANNING PROGRAM
As Amended April 23, 1999
I. PURPOSE
The purpose of this Estate and Financial Planning Program (the "Program") is to
provide independent professional estate planning, financial planning and income
tax preparation services to executives of Southern California Edison Company
(the "Company").
II. PARTICIPATION
Participation in the Program is voluntary. Participants may elect to participate
in the estate planning, the financial planning and/or the income tax preparation
portions of the Program.
III. ELIGIBILITY
1. Eligibility for this Program is limited to the Executive Officers of the
Company and such other Company executives whose participation has been approved
by the Chairman of the Board and Chief Executive Officer. For purposes of this
Program, "Executive Officer" means the Chairman of the Board and Chief Executive
Officer, President, Executive Vice Presidents, Senior Vice Presidents, Corporate
Vice Presidents and the Corporate Secretary. The spouse (other than the
surviving spouse of a deceased retired Participant) of a Participant will
receive services under this Program only to the extent that his/her estate plan,
financial plan, or tax plan or tax return is directly related to that of the
Participant.
2. Eligibility will continue as long as the Participant is an Executive Officer
of the Company, or an otherwise qualified and approved Participant, and for five
years after retirement as such.
3. Eligibility for this Program will end and benefits will cease upon
termination of employment with the Company, or resignation from the Company. If
a Participant becomes disabled, and because of such disability is unable to
continue to work as an executive of the Company, eligibility for this Program
will continue throughout the period of disability.
1
<PAGE>
IV. SERVICES PROVIDED
1. Services provided under this Program are paid for by the Company, including
any start-up fees and expenses. Services provided will include, but not be
limited to, all requested and necessary estate planning, preparation and
implementation of will and trust plans, financial planning and counseling, and
income tax and retirement tax planning and return preparation.
2. Services provided under this Program are the only services of this type paid
for by the Company. The Company will not pay for any services in lieu of the
services of this Program. A Participant may not elect to receive a cash payment
in lieu of services under this Program. Services provided are only those
services directly related to the estate planning, financial planning and income
tax needs of the Participant and his/her spouse as set forth in Section III
Paragraph 1 (above).
3. Invoices for services performed under this Program must be submitted with an
authorization for payment or reimbursement to the Company Controller.
V. SERVICE PROVIDERS
1. The Chairman of the Board and Chief Executive Officer of the Company will (a)
designate the professional providers of services for the Program and/or (b)
establish the qualification requirements of professional providers for those
instances when the Company gives Participants discretion to select their own.
2. The Company will periodically inform Participants who the approved
professional providers are under the Program. In addition, the Company will
specify the qualification requirements which must be met by professional
providers when Participants have selection discretion.
VI. SERVICES FOLLOWING RETIREMENT
Services under this Program to the Participant and his/her surviving spouse will
continue for five years after the retirement of the Participant, provided
however, that the surviving spouse and the Participant must have been married on
the date of the Participant's retirement. In the event of the re-marriage of the
surviving spouse of the Participant during the five-year period following
retirement, any benefits under this Program will cease as of the date of the
re-marriage. All benefits under this Program will cease on the anniversary of
the fifth year following the Participant's retirement from the Company.
VII. TAXES
1. Amounts paid on behalf of a Participant under this Program may be subject to
income tax withholding or other deductions as may be required from time-to-time
by federal, state or local law.
2
<PAGE>
2. Any taxes which may result because of the services provided under this
Program are the sole responsibility of the Participant.
VIII. CONFIDENTIALITY
Information obtained in the course of this Program will be held confidential
between the professional service providers and their individual clients, and
such information will not be made available to the Company unless required by a
court of competent jurisdiction, or unless such information is required to be
disclosed by law, or by the professional service provider's ethical standards of
conduct.
IX. ADMINISTRATION
1. This Program is administered by the Compensation and Executive Personnel
Committee of the Board of Directors or its designee. Day-to-day administration
of the Program has been delegated to the Executive Compensation Division. The
Committee will at all times have full power and authority to interpret,
construe, administer, and prospectively to modify, amend, or terminate this
Program. The Committee's interpretations, constructions and actions shall be
binding and conclusive on all persons for all purposes. No member of the
Committee, nor its designee, shall be liable to any person for any action taken
or omitted in connection with this Program.
2. Questions as to the extent of covered services or other routine
administrative matters, and questions regarding the scope of this Program will
be decided by the Company General Counsel in consultation with the Company
Controller, and as they deem necessary, with the Chairman of the Board and Chief
Executive Officer.
X. NO RIGHT TO CONTINUED EMPLOYMENT
Nothing contained in this document or the Program shall be construed as
conferring upon a Participant the right to continue in the employ of the Company
as an Executive Officer or in any other capacity. A Participant's eligibility to
participate in this Program will continue only so long as the Participant
remains an Executive Officer of the Company, an otherwise qualified and approved
Participant, or a retired Participant subject to the limitations of the Program.
XI. MISCELLANEOUS
1. If any of the provisions of this Program are held invalid, or held to violate
any law, the remainder of the Program may remain in full force and effect.
2. Any right to receive services under this Program is hereby expressly declared
to be a personal, nonassignable and nontransferable benefit of employment
related to the Participant's status as an Executive Officer or other executive
of the Company. In the event of any attempted assignment, alienation or transfer
of such rights contrary to the
3
<PAGE>
provisions of this Program, or upon determination by the Chairman of the Board
and Chief Executive Officer after consultation with the General Counsel and the
Controller that in their good faith opinion the Participant has abused his/her
services under the Program, and after written notice of such determination has
been given to the Participant, the Company will have no further liability for
the provision of or payment for services hereunder.
3. This Program shall be governed by the laws of the State of California.
4. This Program is effective on September 21, 1989.
SOUTHERN CALIFORNIA EDISON COMPANY
By: LILLIAN GORMAN
------------------------
LILLIAN GORMAN
CONSENT OF INDEPENDENT PUBLIC ACCOUNTS
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 June 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
August 3, 1999
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SCE Financial Data Schedule - Exhibit 27
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<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
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255,700
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0
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<OTHER-OPERATING-EXPENSES> 2,864,597
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11,808
<EARNINGS-AVAILABLE-FOR-COMM> 182,732
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