PAGE
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1997
---------------------------------------
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 November 6, 1997
- -------------------------- --------------------------------
Common Stock, no par value 434,888,104
PAGE
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 2
Consolidated Statements of Income--Three, Nine and
Twelve Months Ended September 30, 1997, and 1996 3
Consolidated Balance Sheets--September 30, 1997,
December 31, 1996, and September 30, 1996 4
Consolidated Statements of Cash Flows--
Three, Nine and Twelve Months Ended
September 30, 1997, and 1996 6
Consolidated Statements of Retained Earnings--
Three, Nine and Twelve Months Ended
September 30, 1997, and 1996 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 31
Part II. Other Information:
Item 1. Legal Proceedings 44
Item 6. Exhibits and Reports on Form 8-K 49
page 1
<PAGE>
PART I--FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE, a California corporation) and its
subsidiaries as of September 30, 1997, December 31, 1996, and September
30, 1996, and the related consolidated statements of income, retained
earnings and cash flows for each of the three-, nine- and twelve-month
periods ended September 30, 1997, and 1996. These financial
statements are the responsibility of SCE's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of SCE and its
subsidiaries as of September 30, 1997, December 31, 1996, and September
30, 1996, and the results of their operations and their cash flows for
each of the three-, nine- and twelve-month periods ended September 30,
1997, and 1996, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 4, 1997
page 2
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
----------------------- ------------------------- ------------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating revenue $2,433,589 $2,346,229 $5,973,024 $5,717,637 $7,838,766 $7,620,798
---------- ---------- ---------- ---------- ---------- ----------
Fuel 423,272 220,563 714,078 461,917 882,673 613,067
Purchased power 900,781 938,588 2,117,116 2,026,762 2,796,234 2,654,271
Provisions for regulatory
adjustment clauses--net (185,416) (66,531) (277,439) (170,214) (333,133) (132,387)
Other operating expenses 303,240 263,417 835,801 876,705 1,137,411 1,211,970
Maintenance 89,679 66,933 302,255 217,622 414,004 306,492
Depreciation and decommissioning 313,377 278,181 930,445 795,068 1,198,882 1,040,475
Income taxes 208,492 218,278 437,373 460,234 555,468 584,097
Property and other taxes 31,169 45,182 101,388 147,748 143,925 195,465
---------- ---------- ---------- ---------- ---------- ----------
Total operating expenses 2,084,594 1,964,611 5,161,017 4,815,842 6,795,464 6,473,450
---------- ---------- ---------- ---------- ---------- ----------
Operating income 348,995 381,618 812,007 901,795 1,043,302 1,147,348
---------- ---------- ---------- ---------- ---------- ----------
Provision for rate phase-in plan (13,218) (22,021) (35,908) (69,966) (50,230) (101,252)
Allowance for equity funds
used during construction 1,691 3,466 5,591 10,934 10,236 15,100
Interest and dividend income 10,875 9,056 27,034 26,691 38,200 36,559
Other nonoperating income
(deductions)--net (12,527) (6,534) (2,032) (1,792) (3,864) 11,911
---------- ---------- ---------- ---------- ---------- ----------
Total other deductions--net (13,179) (16,033) (5,315) (34,133) (5,658) (37,682)
---------- ---------- ---------- ---------- ---------- ----------
Income before interest expense 335,816 365,585 806,692 867,662 1,037,644 1,109,666
---------- ---------- ---------- ---------- ---------- ----------
Interest on long-term debt 77,758 94,386 259,503 286,252 354,062 383,037
Other interest expense 27,104 18,277 72,879 55,008 91,783 73,751
Allowance for borrowed funds
used during construction (2,036) (2,179) (6,733) (6,874) (9,653) (10,038)
Capitalized interest (265) (479) (2,320) (647) (3,383) (734)
---------- ---------- ---------- ---------- ---------- ----------
Total interest expense--net 102,561 110,005 323,329 333,739 432,809 446,016
---------- ---------- ---------- ---------- ---------- ----------
Net income 233,255 255,580 483,363 533,923 604,835 663,650
Dividends on preferred stock 6,758 8,599 22,729 25,796 31,328 34,395
---------- ---------- ---------- ---------- ---------- ----------
Earnings available for
common stock $ 226,497 $ 246,981 $ 460,634 $ 508,127 $ 573,507 $ 629,255
========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 3
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
-------------- ------------ --------------
ASSETS
Transmission and distribution utility plant,
at original cost, subject to cost-based
<S> <C> <C> <C>
rate regulation $11,087,199 $10,973,311 $10,851,434
Accumulated provision for depreciation (5,294,706) (5,128,652) (4,978,909)
Construction work in progress 461,850 461,048 532,261
----------- ----------- -----------
6,254,343 6,305,707 6,404,786
----------- ----------- -----------
Generation utility plant, at original cost,
not subject to cost-based rate regulation 9,502,679 9,427,076 9,408,323
Accumulated provision for depreciation
and decommissioning (4,800,890) (4,302,419) (4,171,009)
Construction work in progress 71,598 95,597 73,513
Nuclear fuel, at amortized cost 167,682 176,827 150,092
----------- ----------- -----------
4,941,069 5,397,081 5,460,919
----------- ----------- -----------
Total utility plant 11,195,412 11,702,788 11,865,705
----------- ----------- -----------
Nonutility property--less accumulated provision
for depreciation of $24,450, $25,102 and $26,129 at
respective dates 67,192 63,931 81,585
Nuclear decommissioning trusts 1,608,465 1,485,525 1,401,553
Other investments 124,093 103,973 82,456
----------- ----------- -----------
Total other property and investments 1,799,750 1,653,429 1,565,594
----------- ----------- -----------
Cash and equivalents 96,051 319,942 649,450
Receivables, including unbilled revenue, less
allowances of $21,981, $26,079 and $25,863 for
uncollectible accounts at respective dates 1,208,001 921,083 1,122,248
Fuel inventory 57,027 72,480 76,202
Materials and supplies, at average cost 148,762 154,266 153,820
Accumulated deferred income taxes--net 191,563 240,429 458,411
Regulatory balancing accounts--net 100,935 -- --
Prepayments and other current assets 126,174 105,137 143,230
----------- ----------- -----------
Total current assets 1,928,513 1,813,337 2,603,361
----------- ----------- -----------
Unamortized debt issuance and reacquisition
expense 353,060 346,834 354,684
Rate phase-in plan 16,220 50,703 65,912
Income tax-related deferred charges 1,581,243 1,741,091 1,730,821
Other deferred charges 684,958 428,370 314,723
----------- ----------- -----------
Total deferred charges 2,635,481 2,566,998 2,466,140
----------- ----------- -----------
Total assets $17,559,156 $17,736,552 $18,500,800
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 4
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
----------- ------------ -----------
CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
Common stock (434,888,104 shares outstanding
<S> <C> <C> <C>
at each date) $ 2,168,054 $ 2,168,054 $ 2,168,054
Additional paid-in capital and other 370,922 210,857 207,126
Retained earnings 2,559,319 2,665,612 2,748,983
----------- ----------- -----------
5,098,295 5,044,523 5,124,163
Preferred stock:
Not subject to mandatory redemption 183,755 283,755 283,755
Subject to mandatory redemption 275,000 275,000 275,000
Long-term debt 4,105,221 4,778,703 4,756,324
----------- ----------- -----------
Total capitalization 9,662,271 10,381,981 10,439,242
----------- ----------- -----------
Other long-term liabilities 504,734 423,925 347,766
----------- ----------- -----------
Current portion of long-term debt 276,575 501,470 501,470
Short-term debt 770,300 230,149 275,342
Accounts payable 459,142 392,779 409,425
Accrued taxes 803,253 484,688 918,044
Accrued interest 81,707 93,363 98,136
Dividends payable 101,136 108,563 110,797
Regulatory balancing accounts--net -- 181,488 206,053
Deferred unbilled revenue and other current liabilities 923,167 825,317 996,585
----------- ----------- -----------
Total current liabilities 3,415,280 2,817,817 3,515,852
----------- ----------- -----------
Accumulated deferred income taxes--net 2,957,710 3,170,696 3,224,766
Accumulated deferred investment tax credits 331,890 347,118 352,242
Customer advances and other deferred credits 687,271 595,015 620,932
----------- ----------- -----------
Total deferred credits 3,976,871 4,112,829 4,197,940
----------- ----------- -----------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $17,559,156 $17,736,552 $18,500,800
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 5
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------------- --------------------- ------------------------
1997 1996 1997 1996 1997 1996
--------- --------- ---------- --------- --------- ----------
Cash flows from operating activities:
<S> <C> <C> <C> <C> <C> <C>
Net income $ 233,255 $ 255,580 $ 483,363 $ 533,923 $ 604,835 $ 663,650
Adjustments for non-cash items:
Depreciation and
decommissioning 313,377 278,181 930,445 795,068 1,198,882 1,040,475
Amortization 23,088 24,428 55,069 78,017 67,983 102,876
Rate phase-in plan 12,899 17,797 34,483 63,802 49,692 93,018
Deferred income taxes and
investment tax credits (11,481) (156,065) (19,500) (112,021) 138,645 (120,692)
Other long-term liabilities (1,332) 13,859 80,809 3,574 156,968 2,737
Other--net (120,958) 3,333 (188,315) 8,841 (350,191) 55,251
Changes in working capital:
Receivables (225,991) (468,193) (286,918) (210,285) (85,753) 52,509
Regulatory balancing accounts (187,451) (20,775) (282,423) (131,814) (306,988) (90,711)
Fuel inventory, materials
and supplies 9,243 27,052 20,957 35,515 24,233 45,061
Prepayments and other
current assets (108,896) (113,745) (21,037) (28,941) 17,056 (1,269)
Accrued interest and taxes 137,103 445,269 306,909 379,302 (131,220) 70,563
Accounts payable and other
current liabilities 226,626 313,515 164,213 281,276 (23,701) 108,229
--------- --------- --------- --------- --------- ---------
Net cash provided by
operating activities 299,482 620,236 1,278,055 1,696,257 1,360,441 2,021,697
--------- --------- --------- --------- --------- ---------
Cash flows from financing activities:
Long-term debt issued -- -- -- 396,232 -- 396,139
Long-term debt repayments (716,090) 1,040 (916,145) (403,958) (916,068) (404,267)
Preferred stock redemptions -- -- (100,000) -- (100,000) --
Nuclear fuel financing--net (5,567) 25,967 (12,628) 20,510 8,665 8,869
Short-term debt financing--net 625,056 (116,998) 540,151 (84,166) 494,958 (156,959)
Capital transfer 153,000 -- 153,000 -- 153,000 --
Dividends paid (297,306) (188,507) (595,448) (592,517) (802,524) (737,458)
--------- --------- --------- --------- --------- ---------
Net cash used
by financing activities (240,907) (278,498) (931,070) (663,899) (1,161,969) (893,676)
--------- --------- --------- --------- --------- ---------
Cash flows from investing activities:
Additions to property and plant (160,142) (146,751) (443,788) (487,673) (572,542) (687,397)
Funding of nuclear decommissioning
trusts (34,629) (37,609) (109,202) (110,242) (147,119) (148,940)
Unrealized gain in equity
investments--net 7,330 448 21,778 11,246 25,432 12,469
Other--net (14,464) (23,421) (39,664) (58,006) (57,642) (62,598)
--------- --------- --------- --------- --------- ---------
Net cash used by
investing activities (201,905) (207,333) (570,876) (644,675) (751,871) (886,466)
--------- --------- --------- --------- --------- ---------
Net increase (decrease) in cash
and equivalents (143,330) 134,405 (223,891) 387,683 (553,399) 241,555
Cash and equivalents, beginning
of period 239,381 515,045 319,942 261,767 649,450 407,895
--------- --------- --------- --------- --------- ---------
Cash and equivalents, end
of period $ 96,051 $ 649,450 $ 96,051 $ 649,450 $ 96,051 $ 649,450
========= ========= ========= ========= ========= =========
Cash payments for interest and taxes:
Interest--net of amounts capitalized $ 74,261 $ 84,221 $ 250,561 $ 255,907 $ 341,635 $ 380,939
Taxes 198,494 42,190 215,966 225,542 535,679 551,058
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 6
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
In thousands
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
---------------------- ---------------------- ------------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance at beginning of period $2,554,389 $2,680,388 $2,665,612 $2,780,058 $2,748,983 $2,794,832
Net income 233,255 255,580 483,363 533,923 604,835 663,650
Dividends declared on common
stock (216,738) (178,385) (562,099) (539,185) (758,342) (675,087)
Dividends declared on preferred
stock (6,758) (8,599) (22,729) (25,796) (31,328) (34,395)
Reacquired capital stock
expense and other (4,829) (1) (4,828) (17) (4,829) (17)
---------- ---------- ---------- ---------- ---------- ----------
Balance at end of period $2,559,319 $2,748,983 $2,559,319 $2,748,983 $2,559,319 $2,748,983
========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 7
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Southern California Edison Company's (SCE) outstanding common stock is
owned entirely by its parent company, Edison International. SCE is a
public utility which produces and supplies electric energy for its 4.2
million customers in Central and Southern California. SCE currently
operates in a highly regulated environment in which it has an obligation
to provide electric service to customers in return for an exclusive
franchise within its service territory. This regulatory environment is
changing, as further discussed in Note 2 of "Notes to Consolidated
Financial Statements."
Accounting Principles
SCE's accounting policies conform with generally accepted accounting
principles (GAAP), including the accounting principles for rate-regulated
enterprises which reflect the rate-making policies of the California
Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring legislation
enacted by the State of California and a related change in the application
of accounting principles for rate-regulated enterprises adopted recently
by the Financial Accounting Standards Board's Emerging Issues Task Force
(EITF), during the third quarter of 1997 SCE began accounting for its
investment in generation facilities in accordance with GAAP applicable to
enterprises in general. Although this change did not result in any
adjustment of the carrying value of such investment, it is shown
separately on SCE's Balance Sheet under the caption "Generation utility
plant, at original cost, not subject to cost-based rate regulation." The
competitive market for electric generation in California is scheduled to
begin January 1, 1998.
Consolidation Policy
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated.
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 electric utility
restructuring, decommissioning and contingencies are further discussed in
Notes 2, 9 and 10, 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.
Nuclear
The CPUC authorized rate phase-in plans to defer the collection of $200
million in revenue for each unit at the Palo Verde Nuclear Generating
Station during the first four years of operation and recover the deferred
revenue (including interest) evenly over the following six years. The
phase-in plans ended in February 1996 and September 1996 for Units 1 and
2, respectively. The plan ends in January 1998 for Unit 3.
page 8
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under federal law, SCE is liable for its share of the estimated costs to
decommission three federal nuclear enrichment facilities (based on
purchases). These costs, which will be paid over 15 years, are recorded
as a fuel cost and recovered through customer rates.
In 1992, SCE discontinued operation of San Onofre Nuclear Generating
Station Unit 1, after the CPUC approved a settlement agreement between
SCE and the CPUC's Office of Ratepayer Advocates (ORA) to discontinue
operation of Unit 1 because operation of the unit was no longer cost-
effective. As part of the agreement, SCE recovered its remaining
investment over a four-year period ending August 1996, earning an 8.98%
rate of return on rate base.
In October 1994, the CPUC authorized accelerated recovery of SCE's nuclear
plant investments by $75 million per year, with a corresponding
deceleration in recovery of its transmission and distribution assets
through revised depreciation estimates over their remaining useful lives.
In April 1996, the CPUC authorized a further acceleration of the recovery
of SCE's remaining investment of $2.6 billion in San Onofre Units 2 and
3. The accelerated recovery will continue through December 2001, earning
a 7.35% fixed rate of return (compared to an authorized rate of 9.49% in
1997 for other assets). Future operating costs, including nuclear fuel
and nuclear fuel financing costs, and incremental capital expenditures at
San Onofre Units 2 and 3 are subject to an incentive pricing plan which
allows SCE to receive about 4 cents per kilowatt-hour through 2003. Any
differences between these costs and the incentive price will flow through
to the shareholders. Beginning January 1, 1998, the incentive pricing
plan is expected to become part of the competition transition charge (CTC)
mechanism. Beginning in 2004, SCE will be required to share equally with
ratepayers the net benefits received from operation of the units.
In January 1997, the CPUC authorized a further acceleration of the
recovery of its remaining investment of $1.2 billion in Palo Verde Units
1, 2 and 3. The accelerated recovery will continue through December 2001,
earning a 7.35% fixed rate of return (compared to 9.49% for other assets).
Future 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, the balancing
account is expected to become part of the CTC mechanism. The 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. Beginning in 2002, SCE will be required to
share equally with ratepayers the net benefits received from operation of
Palo Verde.
Reclassifications
Certain prior-period amounts were reclassified to conform to the September
30, 1997, financial statement presentation.
Regulatory Balancing Accounts
The differences between CPUC-authorized and actual base-rate revenue from
kilowatt-hour sales and CPUC-authorized and actual energy costs are
accumulated in balancing accounts until they are refunded to, or recovered
from, utility customers through authorized rate adjustments (with
interest). Income tax effects on balancing account changes are deferred.
page 9
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In January 1997, in compliance with the new restructuring legislation,
overcollections in the kilowatt-hour sales and energy cost balancing
accounts at December 31, 1996, were transferred to an interim balancing
account and are expected to be used as a credit to the CTC balancing
account beginning in January 1998.
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. RD&D expenses are recorded in a balancing account and, at the
end of the rate-case cycle, any authorized but unspent RD&D funds are
refunded to customers. RD&D expenses were $7 million, $19 million and
$25 million for the three, nine and twelve months ended September 30,
1997, respectively, and $6 million, $15 million and $23 million for the
three, nine and twelve months ended September 30, 1996, respectively.
Revenue
Operating revenue includes amounts for services rendered but unbilled at
the end of each period.
Utility Plant
Plant additions, including replacements and betterments, are capitalized.
Such costs include direct material and labor, construction overhead and
an allowance for funds used during construction (AFUDC). AFUDC represents
the estimated cost of debt and equity funds that finance utility-plant
construction. AFUDC is capitalized during plant construction and reported
in current earnings. AFUDC is recovered in rates through depreciation
expense over the useful life of the related asset. Depreciation of
utility plant is computed on a straight-line, remaining-life basis.
Replaced or retired property and removal costs less salvage are charged
to the accumulated provision for depreciation. Depreciation expense
stated as a percent of average original cost of depreciable utility plant
was 5.2%, 5.2% and 5.1% for the three, nine and twelve months ended
September 30, 1997, respectively, and 4.5%, 4.1% and 4.1% for the three,
nine and twelve months ended September 30, 1996.
During the third quarter of 1997, SCE discontinued accounting for its
investment in generation facilities using accounting principles applicable
to rate-regulated enterprises and began accounting for such investment
using GAAP applicable to enterprises in general. The carrying value of
such investment was unaffected by this change.
Note 2. Regulatory Matters
California Electric Utility Industry Restructuring
Restructuring Legislation - In September 1996, the State of California
enacted legislation to provide a transition to a competitive market
structure. The legislation substantially adopts the CPUC's December 1995
restructuring decision by addressing stranded-cost recovery for utilities
and providing a certain cost-recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which would
page 10
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
allow SCE to reduce rates by at least 10% to these customers, beginning
January 1, 1998. The financing would occur with securities issued by the
California Infrastructure and Economic Development Bank, or an entity
approved by the Bank. The legislation includes a rate freeze for all
other customers, including large commercial and industrial customers, as
well as 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 legislation mandates the
implementation of a non-bypassable CTC that provides utilities the
opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses.
Rate Reduction Bonds - In May 1997, SCE filed an application with the CPUC
requesting approval of the issuance of an aggregate amount of up to $3
billion of rate reduction bonds in one or more series or classes and a 10%
rate reduction for the period from January 1, 1998, through March 31,
2002. At the same time, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. On September 3, 1997, the CPUC approved SCE's
request. Subject to prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and FERC directives) for the
functional unbundling of its rates for electric service, beginning January
1, 1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates into separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The transmission component of this rate
unbundling process is being addressed at the FERC through a March 1997
filing. (See PX and ISO discussion below.) Hearings on SCE's rate
unbundling (also known as rate-setting) plan were concluded in April 1997.
On August 1, 1997, the CPUC issued a decision which adopted the
methodology for determining CTC residually (see CTC discussion below) and
adopted SCE's revenue requirement components for public benefit programs
and nuclear decommissioning. The decision also adjusted SCE's proposed
distribution revenue requirement by reallocating $76 million of it
annually to other functions such as generation and transmission. Under
the decision, SCE will be able to recover most of the annual $76 million
through market revenue, the CTC mechanism after petitioning the CPUC to
page 11
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
modify its prior decisions, or another review process later in the
transition period.
PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San
Diego Gas & Electric Company filed a proposal with the FERC regarding the
creation of the PX and the ISO. In November 1996, the FERC conditionally
accepted the proposal and directed the three utilities, the ISO, and the
PX to file more specific information. The filing was made in March 1997,
and included SCE's proposed transmission revenue requirement. On October
29, 1997, the FERC gave conditional, interim authorization for operation
of the PX and ISO to begin on January 1, 1998. Prior to January 2, 1998,
the chief executive officers of the PX, ISO and the three utilities must
certify that all the conditions are in place to ensure reliable electric
power operations. In addition, the FERC stated it would closely monitor
the PX and ISO, require further studies and make modifications, where
necessary. A comprehensive review will be performed by the FERC after
three years of operation of the PX and ISO. In July 1996, the three
utilities jointly filed an application with the CPUC requesting approval
to establish a restructuring trust which would obtain loans up to $250
million for the development of the ISO and PX through January 1, 1998.
The loans are backed by utility guarantees; SCE's share is 45%, or $113
million. The ISO and PX will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million, which will be used to build the hardware and software
systems for the ISO and PX. On October 17, 1997, the three utilities
jointly filed a petition to modify the CPUC decision that established the
restructuring trust and authorized the $250 million loan guarantees. The
petition requested an increase in the loan guarantees from $250 million
to $300 million; SCE's share of this new total would be $135 million. The
petition also requested that a one-time restructuring implementation
charge, to be paid to the PX by the utilities, be deemed a non-bypassable
charge to be recovered from all retail customers. The amount of the PX
charge is $85 million; SCE's share is 45%, or $38 million. A CPUC
decision on the petition is expected by year-end 1997.
Direct Customer Access - In May 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997,
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
page 12
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
maximum demand above 20 kW (primarily industrial and large commercial) can
choose SCE or any other supplier to provide their metering service. All
other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D) and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-
end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was
no longer critical to the restructuring process and asked SCE to make a
compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. SCE has proposed that the difference
between the CPUC-determined hydroelectric revenue requirement and the
market revenue from hydroelectric generation would flow through the CTC
mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; 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 service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all twelve of its oil- and gas-fueled
generation plants. This application builds on SCE's March 1996 plan which
outlined how SCE proposed to divest 50% of these assets. Under the new
proposal, SCE would continue to operate and maintain the divested power
plants for at least two years following their sale, as mandated by the
restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be
impacted by divestiture-related job reductions. SCE's proposal is
contingent on the overall electric industry restructuring implementation
process continuing on a satisfactory path. On September 3, 1997, the CPUC
approved SCE's proposal to auction the twelve plants. On September 5,
page 13
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1997, SCE began the auction of five plants by accepting indications of
interest from potential buyers. On October 3, 1997, SCE accepted
indications of interest from potential buyers on the other seven plants.
On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for
the divestiture of SCE's twelve generation plants which finds there will
be no significant environmental impact resulting from the sale of the
plants. The CPUC is expected to certify the Declaration when it approves
the divestiture of the plants. SCE plans to conclude both auctions and
receive CPUC approval of the divestiture by year-end 1997. Any
differences between the net book value and the market value of the oil-
and gas-fueled generation plants is expected to be recovered through a
non-bypassable CTC.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value) assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value) assuming
the fossil plants have no market value. These estimates are based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of prior legislative and regulatory mandates; and $5.6 billion to
$6.3 billion from costs pertaining to certain generating plants and
regulatory commitments consisting of costs incurred (whose recovery has
been deferred by the CPUC) to provide service to customers. Such
commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Nuclear Generating Station Units 2 and 3 and the
Palo Verde Nuclear Generating Station units, (as discussed in Note 1) and
certain other costs. In February 1997, SCE filed an update to the CTC
filing to reflect approval by the CPUC of settlements regarding ratemaking
for SCE's share of Palo Verde and the buyout of a power purchase
agreement, as well as other minor data updates. No substantive changes
in the total CTC estimates were included. This issue has been separated
into two phases: Phase 1 captures the rate-making issues and Phase 2 the
quantification issues. Hearings on Phase 1 were held in December 1996 and
a decision was issued in June 1997, which, among other things, required
the establishment of a transition cost balancing account and annual
transition cost proceedings, set a market rate forecast for 1998
transition costs, and required that generation-related regulatory assets
be amortized ratably over a 48-month period. Hearings on Phase 2 were
held in May and June 1997. On October 20, 1997, a proposed decision was
issued by the administrative law judge. Among other things, the proposed
decision would reduce SCE's authorized rate of return on certain assets
eligible for transition cost recovery (primarily fossil generation-related
assets) beginning July 1997. The proposed decision, if adopted, and
excluding the effects of other rate actions, will have a negative impact
on 1997 earnings of approximately $10 million. A final decision on Phase
2 is expected in the fourth quarter of 1997.
page 14
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC 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).
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the EITF during April 1997 and a final consensus
was reached at the July EITF meeting. During the third quarter of 1997,
SCE implemented the EITF consensus and discontinued application of
accounting principles for rate-regulated enterprises for its investment
in generation facilities.
However, SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $900 million
at September 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
rate phase-in plan. The consensus reached by the EITF also permits the
recording of new generation-related regulatory assets during the
transition period that are probable of recovery through the CTC mechanism.
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
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
page 15
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
opportunity to recover stranded costs associated with existing wholesale
customers, retail-turned-wholesale customers and retail wheeling when the
state regulatory body does not have authority to address retail stranded
costs. Even though the CPUC is currently addressing stranded cost
recovery through the CTC proceedings, the FERC has also asserted primary
jurisdiction over the recovery of stranded costs associated with retail-
turned-wholesale customers, such as a new municipal electric system or a
municipal annexation. However, the FERC did clarify that it does not
intend to prevent or interfere with a state's authority and that it has
discretion to defer to a state stranded-cost-calculation method. In
January 1997, the FERC accepted the open access transmission tariff SCE
filed in compliance with the April 1996 decision. The rates included in
the tariff are being collected subject to refund. In May 1997, SCE filed
a revised open access tariff to reflect the few revisions set forth in the
March 1997 order.
Canadian Gas Contracts
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA filed its report on the reasonableness of SCE's gas supply costs
for both the 1993 and 1994 record periods. The report recommends a
disallowance of $13 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding
SCE's Canadian supply and transportation agreements reasonable for the
duration of their terms and that the costs under these contracts be
reviewed on a yearly basis. In October 1996, the ORA issued its report
for the 1995 record period recommending a $38 million disallowance for
excessive costs incurred from April 1994 through March 1995. Both
proposed disallowances have been consolidated into one proceeding. SCE
and the ORA filed several rounds of testimony on this issue. Hearings
concluded in February 1997. On July 11, 1997, SCE and the ORA executed
an agreement that settles all pending and future issues related to these
contracts. The settlement agreement, which was filed on July 16, 1997,
is subject to CPUC approval and has been fully reflected in the financial
statements. A decision is expected in late 1997.
Note 3. Financial Instruments
Cash Equivalents
Cash equivalents include tax-exempt investments ($87 million at September
30, 1997, $261 million at December 31, 1996, and $570 million at September
30, 1996), and time deposits and other investments ($3 million at
September 30, 1997, $43 million at December 31, 1996, and $73 million at
September 30, 1996) with maturities of three months or less.
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.
page 16
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE uses the hedge accounting method to record its derivative financial
instruments. Hedge accounting requires an assessment that the transaction
reduces risk, that the derivative be designated as a hedge at the
inception of the derivative contract, and that the changes in the market
value of a hedge move in an inverse direction to the item being hedged.
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.
Interest rate swaps and caps are used to reduce the potential impact of
interest rate fluctuations on floating-rate long-term debt. At the
balance sheet dates of December 31, 1996, and September 30, 1996, SCE had
an interest rate cap agreement which capped the interest rate at 6% for
$30 million of debt due 2027; it expired July 1, 1997. At the balance
sheet dates of September 30, 1997, December 31, 1996, and September 30,
1996, SCE had an interest rate swap agreement which fixed the interest
rate at 5.585% for $196 million of debt due 2008; it expires February 28,
2008. The interest rate swap agreement requires the parties to pledge
collateral according to bond rating and market interest rate changes. At
September 30, 1997, SCE had pledged $18 million as collateral due to a
decline in market interest rates. SCE is exposed to credit loss in the
event of nonperformance by the counterparty to the agreement, but does
not expect the counterparty to fail to meet its obligation.
Fair Value of Financial Instruments
Fair values of financial instruments were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
-------------------- ------------------- -----------------
Cost Fair Cost Fair Cost Fair
Instrument Basis Value Basis Value Basis Value
- ---------- -------- ------ -------- -------- ------- -----
(In millions)
Financial assets:
<S> <C> <C> <C> <C> <C> <C>
Decommissioning trusts $1,327 $1,609 $1,217 $1,484 $1,180 $1,402
Equity investments 9 85 11 68 11 61
Financial liabilities:
DOE decommissioning and
decontamination fees 54 45 54 45 58 47
Interest rate swap & cap -- 18 -- 16 -- 10
Long-term debt 4,105 4,353 4,779 5,001 4,756 4,908
Preferred stock subject to
mandatory redemption 275 293 275 286 275 279
</TABLE>
Financial assets are carried at their fair value based on quoted market
prices. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs for the interest
rate swap; brokers' quotes for long-term debt, preferred stock and the
cap; 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.
page 17
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gross unrealized holding gains on financial assets were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
------------ ------------ ------------
(In millions)
Decommissioning trusts:
<S> <C> <C> <C>
Municipal bonds $ 79 $ 79 $ 64
Stocks 118 138 115
U.S. government issues 55 39 29
Short-term and other 30 12 14
---- ---- ----
282 268 222
Equity investments 76 57 50
---- ---- ----
Total $358 $325 $272
==== ==== ====
</TABLE>
There were no unrealized holding losses on financial assets for all periods
presented.
Investments
Net unrealized gains (losses) in equity investments are recorded as a
separate component of shareholder's equity under "Additional paid-in
capital and other." 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.
Long-term debt maturities and sinking-fund requirements for the five
twelve-month periods following September 30, 1997, are: 1998--$277
million; 1999--$325 million; 2000--$325 million; 2001--$400 million; and
2002--zero.
page 18
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt consisted of:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
------------- ------------ -------------
(In millions)
First and refunding mortgage bonds:
<S> <C> <C> <C>
1998--2026 (5.45% to 8-3/8%) $1,825 $2,725 $2,725
Pollution-control bonds:
1999--2027 (5.4% to 7.2% and variable) 1,203 1,204 1,204
Funds held by trustees (2) (2) (2)
Debentures and notes:
1998--2006 (5.6% to 8-1/4%) 1,195 1,195 1,195
Subordinated debentures:
2044 (8-3/8%) 100 100 100
Commercial paper for nuclear fuel 99 112 90
Long-term debt due within one year (277) (501) (501)
Unamortized debt discount--net (38) (54) (55)
------ ------ ------
Total $4,105 $4,779 $4,756
====== ====== ======
</TABLE>
Short-Term Debt
SCE has lines of credit it can use at negotiated or bank index rates. At
September 30, 1997, available lines totaled $1.4 billion, with $900
million for short-term debt and $500 million 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, balancing account undercollections and general cash
requirements. Commercial paper outstanding at September 30, 1997,
December 31, 1996, and September 30, 1996, was $873 million, $345 million
and $368 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 5.6% at September 30, 1997,
and 5.5% at both December 31, 1996, and September 30, 1996.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may
pay Edison International. At September 30, 1997, SCE had the capacity to
pay $1.7 billion in additional dividends and continue to maintain its
authorized capital structure.
Authorized common stock is 560 million shares with no par value.
Authorized shares of preferred and preference stock are: $25 cumulative
preferred--24 million; $100 cumulative preferred--12 million; and
preference--50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund
provisions. When preferred shares are redeemed, the premiums paid are
charged to common equity.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1997, are: 1998 through 2001--zero and 2002--$105
million.
page 19
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
September 30, 1997
---------------------------
Shares Redemption September 30, December 31, September 30,
Outstanding Price 1997 1996 1996
----------- ---------- ------------ ------------ -------------
(In millions)
Not subject to mandatory redemption:
$25 Par value:
<S> <C> <C> <C> <C> <C>
4.08% Series 1,000,000 $25.50 $ 25 $ 25 $ 25
4.24 1,200,000 25.80 30 30 30
4.32 1,653,429 28.75 41 41 41
4.78 1,296,769 25.80 33 33 33
5.80 2,200,000 25.25 55 55 55
7.36 -- -- -- 100 100
---- ---- ----
Total $184 $284 $284
==== ==== ====
Subject to mandatory redemption:
$100 Par value:
6.05% Series 750,000 $100.00 $ 75 $ 75 $ 75
6.45 1,000,000 100.00 100 100 100
7.23 1,000,000 100.00 100 100 100
---- ---- ----
Total $275 $275 $275
==== ==== ====
</TABLE>
In the second quarter of 1997, 4,000,000 shares of Series 7.36% preferred
stock were redeemed. There were no other preferred stock issuances or
redemptions for the periods presented.
Note 5. Income Taxes
SCE and its subsidiaries will be included in Edison International's
consolidated federal income tax and combined state franchise tax returns.
Under income tax allocation agreements, each subsidiary calculates its own
tax liability.
Income tax expense includes the current tax liability from operations and
the change in deferred income taxes during the year. Investment tax credits
are amortized over the lives of the related properties.
page 20
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net accumulated deferred income tax liability were:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
------------- ------------ -------------
(In millions)
Deferred tax assets:
<S> <C> <C> <C>
Property-related $ 239 $ 247 $ 262
Investment tax credits 195 206 209
Regulatory balancing accounts 125 205 212
Decommissioning-related 110 208 87
Other 604 429 646
------ ------ ------
Total 1,273 1,295 1,416
------ ------ ------
Deferred tax liabilities:
Property-related 3,341 3,550 3,591
Other 698 676 592
------ ------ ------
Total 4,039 4,226 4,183
------ ------ ------
Accumulated deferred income taxes--net $2,766 $2,931 $2,767
====== ====== ======
Classification of accumulated deferred income taxes:
Included in deferred credits $2,958 $3,171 $3,225
Included in current assets 192 240 458
</TABLE>
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- -------------- ---------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
(In millions)
Current:
<S> <C> <C> <C> <C> <C> <C>
Federal $165 $279 $340 $399 $327 $497
State 40 76 95 128 96 158
---- ---- ---- ---- ---- ----
205 355 435 527 423 655
---- ---- ---- ---- ---- ----
Deferred--federal and state:
Accrued charges (11) 3 (24) (19) (19) (29)
Depreciation (15) (5) (38) (9) (43) (4)
Investment and energy tax credits--net (5) (6) (15) (19) (20) (25)
Pension reserves (1) - (3) - 49 -
Rate phase-in plan (5) (7) (15) (25) (20) (38)
Regulatory balancing accounts 74 (19) 112 14 131 -
Retirement of debt (3) (3) (8) (9) (11) (11)
State tax--privilege year (13) (26) 2 10 12 1
Unbilled revenue (34) (95) (41) (46) 5 5
Workforce management - 11 - (8) - (14)
Other (5) (9) (4) (8) (3) (14)
---- ---- ---- ---- ---- ----
(18) (156) (34) (119) 81 (129)
---- ---- ---- ---- ---- ----
Total income tax expense $187 $199 $401 $408 $504 $526
==== ==== ==== ==== ==== ====
Classification of income taxes:
Included in operating income $208 $218 $437 $460 $555 $584
Included in other income (21) (19) (36) (52) (51) (58)
</TABLE>
page 21
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The composite federal and state statutory income tax rate was 40.551%,
40.551% and 40.675% for the three, nine and twelve months ended September
30, 1997, respectively, and 41.045% for the three, nine and twelve months
ended September 30, 1996.
The federal statutory income tax rate is reconciled to the effective tax
rate below:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- --------------- ---------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Capitalized software (0.4) (0.8) (0.6) (0.7) (0.7) (0.8)
Depreciation and other 4.5 4.1 5.5 4.0 5.9 4.9
Investment and energy tax credits (1.2) (1.3) (1.7) (2.0) (1.8) (2.1)
State tax--net of federal deduction 6.7 6.8 7.1 7.0 7.1 7.2
----- ----- ----- ----- ----- -----
Effective tax rate 44.6% 43.8% 45.3% 43.3% 45.5% 44.2%
===== ===== ===== ===== ===== =====
</TABLE>
Note 6. Employee Compensation and Benefit Plans
Stock Option Plans
Under its Long-Term Incentive Compensation Plan, SCE participates in the
use of 8.2 million shares of parent company 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 3.8 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. Edison International
stock options 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. The optionee has no
right to payment of these dividend equivalents until the underlying stock
options are exercised. For Edison International stock options issued
subsequent to 1993, dividend equivalents are subject to reduction unless
certain shareholder return performance criteria are met.
Edison International 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. The options are not transferable, except by will or domestic
relations order. If an optionee retires, dies or is permanently and
totally disabled during the three-year vesting period, the unvested
options will vest and be exercisable to the extent of 1/36 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 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
page 22
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $3 million, $18 million and $23 million
for the three, nine and twelve months ended September 30, 1997,
respectively, and $1 million, $3 million and $3 million for the three,
nine and twelve months ended September 30, 1996, respectively.
Stock-based compensation expense under the fair-value method of accounting
would have resulted in pro forma earnings of $227 million, $463 million
and $578 million for the three, nine and twelve months ended September 30,
1997, respectively, and $247 million, $507 million and $627 million for
the three, nine and twelve months ended September 30, 1996, respectively.
The weighted-average fair value of options granted during the twelve
months ended September 30, 1997, and September 30, 1996, was $7.68 per
share option and $6.27 per share option, respectively. The weighted-
average remaining life of options outstanding as of September 30, 1997,
December 31, 1996, and September 30, 1996, was seven years at each date.
The fair value for each option granted, reflecting the basis for the above
pro forma disclosures, was determined on the date of grant using the
Black-Scholes option-pricing model. The following assumptions were used
in determining fair value through the model:
12 Months Ended
September 30,
-------------------------------
1997 1996
-------------- --------------
Expected life 7 years 7 years
Risk-free interest rate 6.3% - 6.8% 5.5%
Expected volatility 17% 17%
The recognition of dividend equivalents results in no dividends assumed
for purposes of fair-value determination. 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.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers
employees meeting minimum service requirements. Benefits are based on
years of accredited service and average base pay. SCE funds the plan on
a level-premium actuarial method. These funds are accumulated in an
independent trust. Annual contributions meet minimum legal funding
requirements and do not exceed the maximum amounts deductible for income
taxes. Prior service costs from pension plan amendments are funded over
30 years. Plan assets are primarily common stocks, corporate and
government bonds, and short-term investments. In 1996, SCE recorded
pension gains from a special voluntary early retirement program.
page 23
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The plan's funded status was:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
-------------- ------------- --------------
(In millions)
Actuarial present value of benefit obligation:
<S> <C> <C> <C>
Vested benefits $1,529 $1,670 $1,741
Nonvested benefits 78 71 71
------ ------ ------
Accumulated benefit obligation 1,607 1,741 1,812
Value of projected future compensation levels 289 261 306
------ ------ ------
Projected benefit obligation $1,896 $2,002 $2,118
====== ====== ======
Fair value of plan assets $2,348 $2,165 $2,374
====== ====== ======
Projected benefit obligation less
than plan assets $ (452) $ (163) $ (256)
Unrecognized net gain 569 300 419
Unrecognized prior service cost (187) (199) (178)
Unrecognized net obligation (17-year amortization) (40) (43) (45)
------ ------ ------
Pension liability (asset) $ (110) $ (105) $ (60)
====== ====== ======
Discount rate 7.75% 7.75% 8.5%
Rate of increase in future compensation 5.0% 5.0% 5.0%
Expected long-term rate of return on assets 8.0% 8.0% 8.0%
</TABLE>
SCE recognizes pension expense calculated under the actuarial method used for
ratemaking.
The components of pension expense were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- --------------- ----------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Service cost for benefits earned $ 11 $ 11 $ 33 $ 44 $ 38 $ 58
Interest cost projected benefit obligation 35 46 105 133 150 174
Actual return on plan assets (152) (50) (384) (203) (524) (339)
Net amortization and deferral 116 -- 276 52 369 140
---- ---- ---- ---- ---- ----
Pension expense under accounting standards 10 7 30 26 33 33
Special termination benefits -- -- -- -- -- 3
Regulatory adjustment--deferred 3 4 9 13 18 19
---- ---- ---- ---- ---- ----
Net pension expense recognized 13 11 39 39 51 55
Settlement gain -- (8) -- (86) (35) (86)
---- ---- ---- ---- ---- ----
Total expense (gain) $ 13 $ 3 $ 39 $(47) $ 16 $(31)
==== ==== ==== ==== ==== ====
</TABLE>
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 (or those eligible for all benefits
under the 1996 special voluntary early retirement program) with at least
10 years of service, are eligible for postretirement health care, dental,
life insurance and other benefits. Health care benefits are subject to
deductibles, copayment provisions and other limitations.
page 24
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE funds these benefits (by contributions to independent trusts) up to
tax-deductible limits, in accordance with rate-making practices. In 1996,
SCE recorded special termination expenses due to a special voluntary early
retirement program. Any difference between recognized expense and amounts
authorized for rate recovery is not expected to be material (except for
the impact of early retirement program) and will be charged to earnings.
Trust assets are primarily common stocks, corporate and government bonds,
and short-term investments.
The funded status of these benefits is reconciled to the recorded
liability below:
<TABLE>
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
------------- ------------- -------------
(In millions)
Actuarial present value of benefit obligation:
<S> <C> <C> <C>
Retirees $ 934 $ 928 $ 571
Employees eligible to retire 37 35 49
Other employees 430 386 428
------ ------ -----
Accumulated benefit obligation $1,401 $1,349 $1,048
====== ====== ======
Fair value of plan assets $ 694 $ 617 $ 542
====== ====== ======
Plan assets less than accumulated benefit
obligation $ 707 $ 732 $ 506
Unrecognized transition obligation (20-year
amortization) (410) (430) (437)
Unrecognized net gain (loss) (226) (231) (20)
------ ------ ------
Recorded liability $ 71 $ 71 $ 49
====== ====== ======
Discount rate 7.75% 7.75% 8.5%
Expected long-term rate of return on assets 8.5% 8.5% 8.5%
</TABLE>
The components of postretirement benefits other than pensions expense
were:
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- --------------- ----------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
(In millions)
<S> <C> <C> <C> <C> <C> <C>
Service cost for benefits earned $ 7 $ 9 $ 22 $ 29 $ 25 $ 39
Interest cost on benefit obligation 25 19 77 59 108 80
Actual return on plan assets (13) (9) (40) (28) (55) (35)
Amortization of loss 2 2 5 5 6 7
Amortization of transition obligation 7 7 20 20 27 21
---- ---- ---- ---- ---- ----
Net expense 28 28 84 85 111 112
Special termination expense -- 11 -- 60 12 60
---- ---- ---- ---- ---- ----
Total expense $ 28 $ 39 $ 84 $145 $123 $172
==== ==== ==== ==== ==== ====
</TABLE>
page 25
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1997, gradually decreasing to 5% for 2004 and
beyond. Increasing the health care cost trend rate by one percentage
point would increase the accumulated obligation as of September 30, 1997,
by $206 million and annual aggregate service and interest costs by $24
million.
Employee Savings Plan
SCE has a 401(k) defined contribution savings plan designed to supplement
employees' retirement income. The plan received employer contributions
of $3 million, $11 million and $22 million for the three, nine and twelve
months ended September 30, 1997, respectively, and $4 million, $14 million
and $19 million for the three, nine and twelve months ended September 30,
1996, respectively.
Note 7. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems
for which each participant provides its own financing. SCE's share of
expenses for each project is included in the consolidated statements of
income.
The investment in each project, as included in the consolidated balance
sheet as of September 30, 1997, was:
<TABLE>
<CAPTION>
Plant in Accumulated Under Ownership
Service Depreciation Construction Interest
-------- ------------ ------------ ---------
(In millions)
Transmission systems:
<S> <C> <C> <C> <C>
Eldorado $ 30 $ 9 $ 1 60%
Pacific Intertie 230 75 11 50
Generating stations:
Four Corners Units 4 and 5 (coal) 459 244 1 48
Mohave (coal) 305 143 4 56
Palo Verde (nuclear) 1,600 605 7 16
San Onofre (nuclear) 4,205 2,119 26 75
------ ------ ---
Total $6,829 $3,195 $ 50
====== ====== ======
</TABLE>
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms,
provisions and expiration dates.
Estimated remaining commitments for noncancelable leases at September 30,
1997, were:
Year ended December 31, (In millions)
1997 $ 4
1998 15
1999 12
2000 10
2001 6
Thereafter 6
---
Total $53
===
page 26
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Commitments
Nuclear Decommissioning
SCE plans to decommission its nuclear generating facilities at the end of
each facility's operating license by a prompt removal method authorized
by the Nuclear Regulatory Commission. Decommissioning is estimated to
cost $2.0 billion in current-year dollars, based on site-specific studies
performed in 1993 for San Onofre and 1992 for 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. Decommissioning is scheduled to begin
in 2013 at San Onofre and 2024 at Palo Verde. San Onofre Unit 1, which
shut down in 1992, is expected to be secured until decommissioning begins
at the other San Onofre units.
Decommissioning costs, which are accrued and recovered through customer
rates over the term of each nuclear facility's operating license, are
recorded as a component of depreciation expense. Decommissioning expense
was $43 million, $118 million and $155 million for the three, nine and
twelve months ended September 30, 1997, respectively, and $38 million,
$111 million and $150 million for the three, nine and twelve months ended
September 30, 1996, respectively. The accumulated provision for
decommissioning was $1.1 billion at September 30, 1997, $949 million at
December 31, 1996, and $916 million at September 30, 1996. The estimated
costs to decommission San Onofre Unit 1 ($280 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 include:
<TABLE>
<CAPTION>
Maturity September 30, December 31, September 30,
Dates 1997 1996 1996
---------- ------------- --------------- -------------
(In millions)
<S> <C> <C> <C> <C>
Municipal bonds 1998-2021 $ 448 $ 400 $ 372
Stocks -- 390 549 545
U.S. government issues 1998-2023 341 212 181
Short-term and other 1997-2003 148 56 82
------ ------ ------
Total $1,327 $1,217 $1,180
====== ====== ======
</TABLE>
Trust fund earnings (based on specific identification) increase the trust
fund balance and the accumulated provision for decommissioning. Net
earnings were $18 million, $43 million and $57 million for the three, nine
and twelve months ended September 30, 1997, respectively, and $12 million,
$35 million and $49 million for the three, nine and twelve months ended
September 30, 1996, respectively. Proceeds from sales of securities
(which are reinvested) were $110 million, $371 million and $549 million
for the three, nine and twelve months ended September 30, 1997,
respectively, and $189 million, $776 million and $1.0 billion for the
three, nine and twelve months ended September 30, 1996, respectively.
Approximately 89% of the trust fund contributions were tax-deductible.
The Financial Accounting Standards Board has issued an exposure draft
related to accounting practices for removal costs, including
decommissioning of nuclear power plants. The exposure draft would require
SCE to report its estimated decommissioning costs as a liability, rather
than recognizing these costs over the term of each facility's operating
license (current industry practice). SCE does not believe that the
changes proposed in the exposure draft would have an adverse effect on its
page 27
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
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
(cogenerators and small power producers) and other utilities. The
qualifying facility 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.
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. The purchased-power contract is not expected to provide
more than 5% of current or estimated future operating capacity. SCE's
minimum commitment under both contracts is approximately $205 million
through 2017.
Certain commitments for the years 1997 through 2001 are estimated below:
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
(In millions)
<S> <C> <C> <C> <C> <C>
Projected construction expenditures $ 822 $ 956 $ 807 $ 763 $ 721
Fuel supply contracts 217 160 148 167 153
Purchased-power capacity payments 706 708 711 713 711
Unconditional purchase obligations 9 10 10 10 10
</TABLE>
Note 10. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in
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 proceedings will not
materially affect its results of operations or liquidity.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which
require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect
of past operations on the environment.
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing
technology, presently enacted laws and regulations, experience gained at
similar sites, and the probable level of involvement and financial
condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and
maintenance, monitoring and site closure. Unless there is a probable
amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities at undiscounted amounts).
While SCE has numerous insurance policies that it believes may provide
coverage for some of these liabilities, it does not recognize recoveries
in its financial statements until they are realized.
page 28
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached an agreement with the California Coastal Commission
in 1991 to restore certain marine mitigation sites. The restorations
include two sites: designated wetlands and the construction of an
artificial kelp reef off the California coast. After SCE requested
certain modifications to the agreement, the Coastal Commission issued a
final ruling in April 1997 to reduce the scope of remediation required at
these two sites. SCE elected to pay for the costs of marine mitigation
in lieu of placing the funds into a trust. Rate recovery of these costs
is occurring through the San Onofre incentive pricing plan discussed in
Note 1.
SCE's recorded estimated minimum liability to remediate its 52 identified
sites is $185 million, which includes $75 million for the two sites
discussed above. 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 $246
million. The upper limit of this range of costs was estimated using
assumptions least favorable to SCE among a range of reasonably possible
outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $97 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 $159
million for its estimated minimum environmental-cleanup costs expected to
be recovered through customer rates. This amount includes $60 million of
marine mitigation costs remaining to be recovered through the San Onofre
incentive pricing plan.
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 $4 million to $10 million. Recorded costs for the twelve
months ended September 30, 1997, were $9 million.
Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not materially
affect its results of operations or financial position. There can be no
assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will
not require material revisions to such estimates.
page 29
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
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 $79 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 $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability
claims and are subject to adjustment for inflation. If the public
liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
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 $32 million per year.
Insurance premiums are charged to operating expense.
page 30
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
In the following 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 the outcome of
state and federal regulatory proceedings affecting the restructuring of
the electric utility industry, the impacts of new laws and regulations
relating to restructuring and other matters, the effects of increased
competition in the electric utility business, and changes in prices of
electricity and costs for fuel.
RESULTS OF OPERATIONS
Earnings
Southern California Edison Company's (SCE) earnings for the three, nine
and twelve months ended September 30, 1997, were $226 million, $461
million and $574 million, respectively, compared with $247 million, $508
million and $629 million for the same periods in 1996. One-time
adjustments (after-tax) in 1996 for workforce management costs were: a
$32 million charge in the second quarter, a $17 million benefit in the
third quarter and a $3 million charge in the fourth quarter. Excluding
these special items, SCE's earnings for the three, nine and twelve months
ended September 30, 1997, were down $4 million, $62 million and $67
million, respectively, compared to the year-earlier periods. The
decreases in earnings are primarily due to the refueling outages at the
San Onofre Nuclear Generating Station (see discussion in Regulatory
Matters) and the new rate-making treatment for the Palo Verde Nuclear
Generating Station, partially offset by improved overall operating
performance.
Operating Revenue
Operating revenue increased slightly for the three, nine and twelve months
ended September 30, 1997, compared with the same periods in 1996. The
quarterly increase is primarily due to an increase in non-residential
retail rates, partially offset by a decrease in resale sales volume. The
year-to-date and twelve-months ended increases are due to a 3% increase
in sales volume from commercial and agricultural customers (due to an
improving Southern California economy), as well as a slight increase in
resale rates. Over 98% of operating revenue is 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).
In March 1995, SCE announced a five-year goal to reduce system average
rates by 25% on an inflation-adjusted basis (from 10.7 cents per kilowatt-
hour to below 10 cents per kilowatt-hour). In February 1996, the CPUC
approved a system-wide rate reduction which lowered the average price per
kilowatt-hour from 10.7 cents to 10.1 cents, effective June 1996.
Legislation enacted in September 1996 provides for, among other things,
at least a 10% rate reduction (financed through the issuance of rate
reduction bonds) for residential and small commercial customers beginning
in 1998 (see discussion in Competitive Environment).
page 31
<PAGE>
Operating Expenses
Fuel expense increased 92%, 55% and 44%, respectively, for the three, nine
and twelve months ended September 30, 1997. The increases are primarily
due to a $174 million gas contract termination payment during the third
quarter, combined with higher gas prices and the extended refueling
outages at San Onofre. San Onofre Unit 2 was shut down during the entire
first quarter of 1997, Unit 3 was shut down 80 days of the second quarter
and both units had a combined outage time of 30 days during the third
quarter, resulting in an overall increase in gas-powered generation for
all periods presented. There were no comparable outages for the same
periods in 1996.
Purchased-power expense decreased 4% during the third quarter, as cost
increases in spot market purchases were more than offset by decreases in
federally mandated contract payments. For the nine and twelve months
ended September 30, 1997, purchased-power expense increased 5% due to
increased power purchases in the open market and increases in power
purchased under federally-mandated contracts. SCE is required under
federal law to purchase power delivered by certain nonutility generators
(up to a project's rated capacity) even though energy prices under these
contracts are generally higher than other sources. For the twelve months
ended September 30, 1997, 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. The CPUC has mandated the prices for
these contracts.
Provisions for regulatory adjustment clauses decreased substantially for
all periods presented compared with the year-earlier periods. The
quarterly decrease is primarily due to undercollections in the energy cost
balancing account resulting from gas contract termination payments made
in third quarter 1997, as well as a lesser amount of actual base-rate
revenue from kilowatt-hour sales exceeding CPUC-authorized estimates.
These quarterly undercollections were partially offset by a net
overcollection resulting from the San Onofre units operating at a lower
capacity in third quarter 1997 (30 days of refueling and inspection
outages) compared to third quarter 1996 when the San Onofre units operated
at a higher capacity than estimated. Another offset to the quarterly
decrease is an overcollection due to the accelerated recovery of SCE's
remaining investment at San Onofre. The year-to-date and twelve-months-
ended decreases are mainly due to an undercollection related to the gas
contract termination payments made in 1997 and actual energy costs
exceeding CPUC-authorized fuel and purchased-power cost estimates. This
undercollection was partially offset by overcollections related to:
actual base-rate revenue from kilowatt-hour sales exceeding CPUC-
authorized estimates; the effects of the San Onofre refueling outages in
1997 and the acceleration of SCE's remaining investment at San Onofre.
Other operating expenses increased 15% for the three months ended
September 30, 1997, compared with the year-earlier period, due to
increased operating costs at San Onofre for inspections associated with
the earlier Unit 2 and 3 outages, along with increased expenses associated
with meter reading, customer records and interim direct access activities.
For the nine and twelve months ended September 30, 1997, other operating
expenses decreased 5% and 6%, respectively, as reductions in pension-
related expenses associated with SCE's voluntary retirement programs in
1996 more than offset the quarterly increases previously discussed.
Maintenance expense increased in all periods presented compared with the
year-earlier periods, due to increased maintenance costs for electric
plant assets and the scheduled refueling outages at the San Onofre units.
Depreciation and decommissioning expense increased 13%, 17% and 15%,
respectively, for the three-, nine- and twelve-month periods ended
September 30, 1997, due to increases in plant assets and the accelerated
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recovery of the Palo Verde Nuclear Generating Station units effective
January 1997. The accelerated recovery of the San Onofre units, effective
April 1996, also contributed to the year-to-date and twelve-months-ended
increases.
Property and other taxes decreased 31% for both the three and nine months
ended September 30, 1997, and decreased 26% for the twelve-month period
ended September 30, 1997, due to a reclassification of payroll taxes to
operation and maintenance expense in 1997.
Other Income and Deductions
The provision for rate phase-in plan reflects 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) is being collected evenly over the final six
years of each unit's plan. The plan ended in February 1996 and September
1996 for Units 1 and 2, respectively. The plan ends in January 1998 for
Unit 3. The provision is a non-cash offset to the collection of deferred
revenue.
Other nonoperating income decreased for the three, nine and twelve months
ended September 30, 1997, compared to the same periods in 1996, primarily
due to additional accruals for regulatory matters and increased costs
resulting from the effect of a rise in Edison International's stock price
on SCE's stock option plan.
Interest Expense
Interest on long-term debt decreased 18% for the quarter ended
September 30, 1997, compared to the same period in 1996, due to the early
retirement of $400 million of long-term debt in July 1997.
Other interest expense increased substantially for the three, nine and
twelve months ended September 30, 1997, respectively, compared to the same
periods in 1996, due to higher levels of short-term debt used to retire
first and refunding mortgage bonds discussed above.
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 $2.3 billion of its outstanding shares of common stock. Edison
International has repurchased 68.4 million shares ($1.5 billion) between
January 1995 and November 4, 1997, funded by dividends from its
subsidiaries and its lines of credit. As excess cash becomes available,
SCE intends to pay cash dividends to Edison International, while
maintaining its CPUC-authorized capital structure.
SCE's cash flow coverage of dividends for the three, nine and twelve
months ended September 30, 1997, was 1.0 times, 2.1 times and 1.7 times,
respectively, compared to 3.3 times, 2.9 times and 2.7 times for the year-
earlier periods, due to the additional cash needs for the repayment of
long-term debt and redemption of preferred stock.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $299 million, $1.3
billion and $1.4 billion, respectively, for the three, nine and twelve
months ended September 30, 1997, compared with $620 million, $1.7 billion
and $2.0 billion for the same periods in 1996. Cash from operations
exceeded capital requirements for all periods presented.
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Cash Flows from Financing Activities
Short-term debt is used to finance fuel inventories, balancing account
undercollections 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 its articles of incorporation and trust indenture. As of
September 30, 1997, SCE could issue approximately $9.5 billion of
additional first and refunding mortgage bonds and $5.2 billion of
preferred stock at current interest and dividend rates.
At September 30, 1997, SCE had $1.8 billion of borrowing capacity under
lines of credit, with $400 million available for general purpose, short-
term debt and $500 million for the long-term refinancing of its variable-
rate pollution-control bonds. These unsecured lines of credit are at
negotiated or bank index rates with various expiration dates; the majority
have five-year terms.
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
September 30, 1997, SCE had the capacity to pay $1.7 billion in additional
dividends and continue to maintain its authorized capital structure.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant and funding of nuclear decommissioning trusts. As
further discussed in Note 9 of "Notes to Consolidated Financial
Statements," decommissioning costs are accrued and recovered in rates over
the term of each nuclear generating facility's operating license through
charges to depreciation expense. SCE estimates that it will spend
approximately $12.7 billion to decommission its nuclear facilities,
primarily between 2013-2070. This estimate is based on SCE's current-
dollar decommissioning costs ($2.0 billion), escalated using a 6.65%
annual rate. These amounts are expected to be funded from independent
decommissioning trusts which receive SCE contributions of approximately
$100 million per year (until decommissioning begins).
Projected Capital Requirements
SCE's projected construction expenditures for the next five years are:
1997--$822 million; 1998--$956 million; 1999--$807 million; 2000--$763
million; and 2001--$721 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1997, are: 1998--$277
million; 1999--$325 million; 2000--$325 million; 2001--$400 million; and
2002--zero.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1997, are: 1998 through 2001--zero and 2002--$105
million.
REGULATORY MATTERS
SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to the
legislation enacted in September 1996 which requires that rates remain
frozen at the June 10, 1996, level (system average of 10.1 cents per
kilowatt-hour). See further discussion in Competitive Environment.
The CPUC's 1997 cost-of-capital decision authorized an 11.6% return on
common equity and a 48% common equity ratio, both unchanged from 1996
levels. SCE's return on rate base was lowered from 9.55% to 9.49%. The
decision, excluding the effects of other rate actions, will have a
negative impact on 1997 earnings of approximately $5 million. On October
20, 1997, a proposed decision was issued by a CPUC administrative law
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judge in Phase 2 of the competition transition charge (CTC) proceeding.
Among other things, the proposed decision would reduce SCE's authorized
rate of return on certain assets eligible for transition cost recovery
(primarily fossil generation-related assets) beginning July 1997. The
proposed decision, if adopted, and excluding the effects of other rate
actions, will have a negative impact on 1997 earnings of approximately $10
million.
The CPUC has authorized revised rate-making plans for SCE's nuclear
facilities, which call for the accelerated recovery of its nuclear
investments in exchange for a lower authorized rate of return. SCE's
nuclear assets are now earning an annual rate of return of 7.35%, compared
to an authorized rate of 9.49% in 1997 for other assets. In addition, the
San Onofre plan authorizes a fixed rate of approximately 4 cents per
kilowatt-hour generated for incremental operating costs including
incremental capital costs, and nuclear fuel and nuclear fuel financing
costs. The San Onofre plan commenced in April 1996, and ends in December
2001 for the accelerated recovery portion and in December 2003 for the
incremental pricing portion. Palo Verde's incremental 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.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994 record
periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowances have been
consolidated into one proceeding. SCE and the ORA filed several rounds
of testimony on this issue. Hearings concluded in February 1997. On July
11, 1997, SCE and the ORA executed an agreement that settles all pending
and future issues related to these contracts. The settlement agreement,
which was filed on July 16, 1997, is subject to CPUC approval and has been
fully reflected in the financial statements. A decision is expected in
late 1997.
COMPETITIVE ENVIRONMENT
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing. The generation sector has experienced
competition from nonutility power producers and regulators are
restructuring California's electric utility industry.
California Electric Utility Industry Restructuring
Restructuring Legislation - In September 1996, the State of California
enacted legislation to provide a transition to a competitive market
structure. The legislation substantially adopts the CPUC's December 1995
restructuring decision by addressing stranded-cost recovery for utilities
and providing a certain cost-recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
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recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which would
allow SCE to reduce rates by at least 10% to these customers, beginning
January 1, 1998. The financing would occur with securities issued by the
California Infrastructure and Economic Development Bank, or an entity
approved by the Bank. The legislation includes a rate freeze for all
other customers, including large commercial and industrial customers, as
well as 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 legislation mandates the
implementation of a non-bypassable CTC that provides utilities the
opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses.
Rate Reduction Bonds - In May 1997, SCE filed an application with the CPUC
requesting approval of the issuance of an aggregate amount of up to $3
billion of rate reduction bonds in one or more series or classes and a 10%
rate reduction for the period from January 1, 1998, through March 31,
2002. At the same time, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. On September 3, 1997, the CPUC approved SCE's
request. Subject to prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and FERC directives) for the
functional unbundling of its rates for electric service, beginning January
1, 1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates into separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The transmission component of this rate
unbundling process is being addressed at the FERC through a March 1997
filing. (See PX and ISO discussion below.) Hearings on SCE's rate
unbundling (also known as rate-setting) plan were concluded in April 1997.
On August 1, 1997, the CPUC issued a decision which adopted the
methodology for determining CTC residually (see CTC discussion below) and
adopted SCE's revenue requirement components for public benefit programs
and nuclear decommissioning. The decision also adjusted SCE's proposed
distribution revenue requirement by reallocating $76 million of it
annually to other functions such as generation and transmission. Under
the decision, SCE will be able to recover most of the annual $76 million
through market revenue, the CTC mechanism after petitioning the CPUC to
modify its prior decisions, or another review process later in the
transition period.
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PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San
Diego Gas & Electric Company filed a proposal with the FERC regarding the
creation of the PX and the ISO. In November 1996, the FERC conditionally
accepted the proposal and directed the three utilities, the ISO, and the
PX to file more specific information. The filing was made in March 1997,
and included SCE's proposed transmission revenue requirement. On
October 29, 1997, the FERC gave conditional, interim authorization for
operation of the PX and ISO to begin on January 1, 1998. Prior to January
2, 1998, the chief executive officers of the PX, ISO and the three
utilities must certify that all the conditions are in place to ensure
reliable electric power operations. In addition, the FERC stated it would
closely monitor the PX and ISO, require further studies and make
modifications, where necessary. A comprehensive review will be performed
by the FERC after three years of operation of the PX and ISO. In July
1996, the three utilities jointly filed an application with the CPUC
requesting approval to establish a restructuring trust which would obtain
loans up to $250 million for the development of the ISO and PX through
January 1, 1998. The loans are backed by utility guarantees; SCE's share
is 45%, or $113 million. The ISO and PX will repay the trust's loans and
recover funds from future ISO and PX customers. In August 1996, the CPUC
issued an interim order establishing the restructuring trust and the
funding level of $250 million, which will be used to build the hardware
and software systems for the ISO and PX. On October 17, 1997, the three
utilities jointly filed a petition to modify the CPUC decision that
established the restructuring trust and authorized the $250 million loan
guarantees. The petition requested an increase in the loan guarantees
from $250 million to $300 million; SCE's share of this new total would be
$135 million. The petition also requested that a one-time restructuring
implementation charge, to be paid to the PX by the utilities, be deemed
a non-bypassable charge to be recovered from all retail customers. The
amount of the PX charge is $85 million; SCE's share is 45%, or $38
million. A CPUC decision on the petition is expected by year-end 1997.
Direct Customer Access - In May 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997,
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
maximum demand above 20 kW (primarily industrial and large commercial) can
choose SCE or any other supplier to provide their metering service. All
other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
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providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D) and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-
end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was
no longer critical to the restructuring process and asked SCE to make a
compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. SCE has proposed that the difference
between the CPUC-determined hydroelectric revenue requirement and the
market revenue from hydroelectric generation would flow through the CTC
mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; 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 service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all twelve of its oil- and gas-fueled
generation plants. This application builds on SCE's March 1996 plan which
outlined how SCE proposed to divest 50% of these assets. Under the new
proposal, SCE would continue to operate and maintain the divested power
plants for at least two years following their sale, as mandated by the
restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be
impacted by divestiture-related job reductions. SCE's proposal is
contingent on the overall electric industry restructuring implementation
process continuing on a satisfactory path. On September 3, 1997, the CPUC
approved SCE's proposal to auction the twelve plants. On September 5,
1997, SCE began the auction of five plants by accepting indications of
interest from potential buyers. On October 3, 1997, SCE accepted
indications of interest from potential buyers on the other seven plants.
On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for
the divestiture of SCE's twelve generation plants, which finds there will
be no significant environmental impact resulting from the sale of the
plants. The CPUC is expected to certify the Declaration when it approves
the divestiture of the plants. SCE plans to conclude both auctions and
receive CPUC approval of the divestiture by year-end 1997. Any
differences between the net book value and the market value of the oil-
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and gas-fueled generation plants is expected to be recovered through a
non-bypassable CTC.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value) assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value) assuming
the fossil plants have no market value. These estimates are based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of prior legislative and regulatory mandates; and $5.6 billion to
$6.3 billion from costs pertaining to certain generating plants and
regulatory commitments consisting of costs incurred (whose recovery has
been deferred by the CPUC) to provide service to customers. Such
commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Nuclear Generating Station Units 2 and 3 and the
Palo Verde Nuclear Generating Station units, (as discussed in Note 1) and
certain other costs. In February 1997, SCE filed an update to the CTC
filing to reflect approval by the CPUC of settlements regarding ratemaking
for SCE's share of Palo Verde and the buyout of a power purchase
agreement, as well as other minor data updates. No substantive changes
in the total CTC estimates were included. This issue has been separated
into two phases: Phase 1 captures the rate-making issues and Phase 2 the
quantification issues. Hearings on Phase 1 were held in December 1996 and
a decision was issued in June 1997, which, among other things, required
the establishment of a transition cost balancing account and annual
transition cost proceedings, set a market rate forecast for 1998
transition costs, and required that generation-related regulatory assets
be amortized ratably over a 48-month period. Hearings on Phase 2 were
held in May and June 1997. On October 20, 1997, a proposed decision was
issued by the administrative law judge. Among other things, the proposed
decision would reduce SCE's authorized rate of return on certain assets
eligible for transition cost recovery (primarily fossil generation-related
assets) beginning July 1997. The proposed decision, if adopted, and
excluding the effects of other rate actions, will have a negative impact
on 1997 earnings of approximately $10 million. A final decision on Phase
2 is expected in the fourth quarter of 1997.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC 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).
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting. During the third quarter of 1997,
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SCE implemented the EITF consensus and discontinued application of
accounting principles for rate-regulated enterprises for its investment
in generation facilities.
However, SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $900 million
at September 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed-through to customers,
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
rate phase-in plan. The consensus reached by the EITF also permits the
recording of new generation-related regulatory assets during the
transition period that are probable of recovery through the CTC mechanism.
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
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
opportunity to recover stranded costs associated with existing wholesale
customers, retail-turned-wholesale customers and retail wheeling when the
state regulatory body does not have authority to address retail stranded
costs. Even though the CPUC is currently addressing stranded cost
recovery through the CTC proceedings, the FERC has also asserted primary
jurisdiction over the recovery of stranded costs associated with retail-
turned-wholesale customers, such as a new municipal electric system or a
municipal annexation. However, the FERC did clarify that it does not
intend to prevent or interfere with a state's authority and that it has
discretion to defer to a state stranded-cost-calculation method. In
January 1997, the FERC accepted the open access transmission tariff SCE
filed in compliance with the April 1996 decision. The rates included in
the tariff are being collected subject to refund. In May 1997, SCE filed
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a revised open access tariff to reflect the few revisions set forth in the
March 1997 order.
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.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached agreement with the California Coastal Commission in
1991 to restore certain marine mitigation sites. The restorations include
two sites: designated wetlands and the construction of an artificial kelp
reef off the California coast. After SCE requested certain modifications
to the agreement, the Coastal Commission issued a final ruling in April
1997 to reduce the scope of remediation required at these two sites. SCE
elected to pay for the costs of marine mitigation in lieu of placing the
funds into a trust. Rate recovery of these costs is occurring through the
San Onofre incentive pricing plan discussed in Note 1 to the Consolidated
Financial Statements.
SCE's recorded estimated minimum liability to remediate its 52
identified sites is $185 million, which includes $75 million for the two
sites discussed above. One of SCE's sites, a former pole-treating
facility, is considered a federal Superfund site and represents 43% 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 $246 million. The upper limit of this
range of costs was estimated using assumptions least favorable to SCE
among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $97 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 $159 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates. This
amount includes $60 million of marine mitigation costs remaining to be
recovered through the San Onofre incentive pricing plan.
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 $4 million to $10 million. Recorded costs for the twelve-
month period ended September 30, 1997, were $9 million.
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Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental cleanup
costs, SCE believes that costs ultimately recorded will not materially
affect its results of operations or financial position. There can be no
assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will
not require material revisions to such estimates.
The 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 is in progress to
determine the specific impact of air contaminant emissions from the Mohave
Coal Generating Station on visibility in Grand Canyon National Park. The
potential effect of these studies on sulfur dioxide emissions regulations
for Mohave is unknown.
SCE's projected capital expenditures to protect the environment are $831
million for the 1997-2001 period, mainly for aesthetics treatment,
including undergrounding certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
scientific research. After many years of research, scientists have not
found that exposure to EMF causes disease in humans. Research on this
topic is continuing. However, the CPUC has issued a decision which
provides for a rate-recoverable research and public education program
conducted by California electric utilities, and authorizes these utilities
to take no-cost or low-cost steps to reduce EMF in new electric
facilities. SCE is unable to predict when or if the scientific community
will be able to reach a consensus on any health effects of EMF, or the
effect that such a consensus, if reached, could have on future electric
operations.
PALO VERDE STEAM TUBE RUPTURE
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in Unit 2 will have to be replaced within five to ten years.
SCE supports the purchase of spare steam generators that could be used,
if needed, in any of the Palo Verde units. SCE estimates its share of
the steam generator replacement costs to be between $16 million and $30
million, plus replacement power costs.
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, which was completed in Spring 1997, an
increased rate of tube degradation was identified, resulting in removing
1.8% of the tubes from service. The cumulative total of Unit 2's tubes
removed from service is now 5.5%, well below the maximum 10% allowed in
the steam generator design before the rating capacity of the unit must be
reduced. As a result of the increased degradation, a mid-cycle inspection
outage will be conducted in 1998 for Unit 2.
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<PAGE>
During Unit 3's refueling outage, which was completed in July 1997,
inspections of structural supports for steam generator tubes identified
several areas where the thickness of the supports had been reduced,
apparently by erosion during normal plant operation. As a result, a mid-
cycle inspection outage is planned for 1998. However, during Unit 2's
Spring 1997 inspection outage, similar tube supports showed no sign of
such erosion.
PROPOSED NEW ACCOUNTING STANDARD
During 1996, the Financial Accounting Standards Board issued an exposure
draft that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for the decommissioning of its nuclear power plants, obligations for coal
mine reclamation costs and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
page 43
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Qualifying Facilities (QF) Litigation
On May 20, 1993, four geothermal QFs filed a lawsuit against Southern
California Edison Company (SCE) in Los Angeles County Superior Court,
claiming that SCE underpaid, and continues to underpay, the plaintiffs for
energy. SCE denied the allegations in its response to the complaint. The
action was brought on behalf of Vulcan/BN Geothermal Power Company, Elmore
L.P., Del Ranch L.P. and Leathers L.P., each of which was partially owned
by a subsidiary of Edison Mission Energy (a subsidiary of Edison
International) at the time of filing. In April 1996, Edison Mission
Energy's 50% share in these projects was sold to CalEnergy. In October
1994, plaintiffs submitted an amended complaint to the court to add causes
of action for unfair competition and restraint of trade. In July 1995,
after several motions to strike had been heard by the court, the
plaintiffs served a fourth amended complaint, which omitted the previous
claims based on alleged restraint of trade. The plaintiffs allege in the
fourth amended complaint that past underpayments have totaled at least $21
million. In other court filings, plaintiffs contend that additional
contract payments owing from the beginning of the alleged underpayments
through the end of the contract term could total approximately $60
million. Plaintiffs also seek unspecified punitive damages and an
injunction to enjoin SCE from "future" unfair competition. After SCE's
motion to strike portions of the fourth amended complaint was denied, SCE
filed an answer to the fourth amended complaint which denies its material
allegations.
On May 1, 1996, the parties entered into an agreement for a settlement of
all claims in dispute. Pursuant to the agreement, the specific terms of
which are confidential, a settlement amount has been paid and the parties
have entered into mutual general releases, with respect to the period
before January 1, 1996. SCE intends to seek recovery of this payment
through rates. SCE has also agreed, subject to California Public
Utilities Commission (CPUC) approval, to increase payments to plaintiffs
for specified levels of energy deliveries for the period after December
31, 1995. Plaintiffs have reserved the right to continue the litigation
with respect to the period after December 31, 1995, if CPUC approval is
not obtained. On August 8, 1996, SCE filed its application with the CPUC
for approval of the settlement as it pertains to the period after 1995.
On December 20, 1996, the CPUC's Office of Ratepayer Advocates (ORA) filed
a protest to the application. In its protest, the ORA requests that the
CPUC not grant the application or, in the alternative, that the CPUC
conduct hearings on the application. On January 17, 1997, SCE filed a
reply to the ORA's request. On February 27, 1997, a prehearing conference
was held, at which time SCE's application was set for hearing to start on
April 23, 1997. This hearing date was subsequently vacated by the
assigned administrative law judge due to ongoing discussions to resolve
issues raised by ORA's protest. As a result of those discussions, SCE and
the ORA entered into a stipulation and agreement (Stipulation) effective
July 11, 1997. In the Stipulation, the ORA agrees to withdraw its protest
and support SCE's application in return for SCE's agreement that the cost
recovery issues presented in the application may be transferred for a
decision in SCE's 1992 Energy Cost Adjustment Clause (ECAC) proceeding,
where related issues are currently pending. The Stipulation further
provides for SCE and the ORA to file a joint motion for approval of the
Stipulation. The motion was filed on September 25, 1997. In light of the
Stipulation, plaintiffs and SCE have entered into two amendments to the
May 1, 1996, settlement agreement. The first amendment provides for the
post-1995 portion of the settlement to become effective through 1997 upon
CPUC approval consistent with the Stipulation. The second amendment
resulted in plaintiffs dismissing the lawsuit without prejudice pending
final CPUC resolution of the issues raised by SCE's application. On
October 15, 1997, the assigned administrative law judge issued a draft
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<PAGE>
decision on SCE's application and the motion for approval of the
Stipulation. The draft decision would approve the application subject to
the terms of the Stipulation. As of this date, the CPUC has not yet acted
on the draft decision.
Wind Generators' Litigation
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189 million in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
Superior Court case granted the plaintiffs' motion seeking summary
adjudication that the contract language in question is not reasonably
susceptible to SCE's position that there is only a single, 10-year period
of fixed payments. Following the March 1 ruling, a ninth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first eight. SCE subsequently responded to the complaint
in the new lawsuit by denying its material allegations. On April 5, 1995,
SCE filed a petition for Writ of Mandate, Prohibition or Other Appropriate
Relief, requesting that the Court of Appeal of the State of California,
Second Appellate District issue a writ directing the Los Angeles Superior
Court to vacate its March 1 order granting summary adjudication. In a
decision filed August 9, 1995, the Court of Appeal issued a writ directing
that the order be overturned, and a new order be entered denying the
motion. In light of the Court of Appeal decision in the lead Los Angeles
case, a summary adjudication motion in the Kern County case was withdrawn.
On March 25, 1996, pursuant to a court-approved stipulation, all but one
of the cases were consolidated for trial in Los Angeles Superior Court.
Shortly thereafter, on April 3, 1997, pursuant to stipulation of the
parties, the Kern County case was ordered to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. Trial of the
consolidated cases, beginning with the lead case, commenced on March 10,
1997. The consolidated cases are to be tried one after another in
bifurcated fashion, with the liability phase of each and all of the cases
to be tried before commencement of the damages phase, if applicable.
Testimony and arguments in the liability phase of the lead case concluded
on May 20, 1997. On July 7, 1997, the court issued a tentative decision
which effectively would resolve all liability issues in the lead case in
SCE's favor. A proposed Statement of Decision consistent with the
conclusions in the tentative decision has been submitted by SCE and
argument on the same took place at a hearing on October 31, 1997. The
hearing was not concluded at that time and further argument has therefore
been scheduled for November 19, 1997. In addition, a status conference
has been scheduled for December 17, 1997, at which time the court will
address scheduling of trial dates in the remaining cases and a date for
commencement of the damages phase of the lead case.
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles Superior Court
against another independent power producer of geothermal generation and
five of its affiliated entities (collectively the "Defendants"). SCE
alleges that in order to avoid power production plant shutdowns caused by
excessive noncondensable gas in the geothermal field brine, the Defendants
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
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<PAGE>
Defendants of their obligations under their contracts and applicable law.
The complaint seeks termination of the contracts and damages for excess
power purchase payments made to the Defendants. The Defendants' motion
to transfer venue to Inyo County Superior Court was granted on August 31,
1997. The Defendants have responded to SCE's allegations by filing both
a demurrer and a motion to strike. These matters are currently set for
hearing on November 20, 1997, in Inyo County Superior Court. In addition,
the Defendants have filed a motion for summary judgment on the grounds
that SCE's claims are time-barred or that such claims were released in
connection with the settlement of prior litigation between some of the
Defendants and SCE's affiliates, Mission Power Engineering Company, Edison
Mission Energy and The Mission Group.
The Defendants have also filed a cross-complaint which names SCE, Mission
Power Engineering, Edison Mission Energy and The Mission Group. In
response to SCE's demurrer, the Defendants withdrew their cross-complaint
and filed a first amended cross-complaint. The first amended cross-
complaint asserts twelve causes of action for alleged violation of certain
orders of the CPUC, declaratory relief with respect to the contracts,
breach of the implied covenant of good faith and fair dealing, inducing
breach of employment agreements, abuse of process, breach of settlement
agreements, disparagement and slander per se, and unfair business
practices under section 17200 of the California Business and Professions
Code. The first amended cross-complaint seeks damages in an unspecified
amount as well as exemplary damages and injunctive relief. SCE has
responded to the first amended cross-complaint by filing a demurrer, which
is set for hearing on November 20, 1997, in Inyo County Superior Court.
In addition to asserting the claims in the first amended cross-complaint,
three of the Defendants (collectively the "Related Plaintiffs") have filed
a separate lawsuit in Inyo County Superior Court. In a first amended
complaint in the separate lawsuit, the Related Plaintiffs allege causes
of action for breach of contract, breach of the implied covenant of good
faith and fair dealing, declaratory relief, violation of California Public
Utilities Code sections 702, 453 and 2106, unfair competition and false
advertising. In addition, the Related Plaintiffs claim that SCE
anticipatorily breached the contracts by asserting that all of the Related
Plaintiffs' facilities are subject to a single "first period." The
Related Plaintiffs seek recovery of $400,000,000 in alleged compensatory
damages as well as exemplary damages and unspecified injunctive relief.
SCE has demurred to the amended complaint and has also moved to strike or,
in the alternative, to consolidate the Related Plaintiffs' claims with the
Defendants' claims in the first lawsuit on the ground that the former
claims should have been asserted as part of the amended cross-complaint
in the original action. The hearing on SCE's demurrer and motion to
strike or to consolidate is also currently set for November 20, 1997. No
trial date in either of the two cases has been set.
Electric and Magnetic Fields (EMF) Litigation
SCE is involved in three lawsuits alleging that various plaintiffs
developed cancer as a result of exposure to EMF from SCE facilities. SCE
denied the material allegations in its responses to each of these
lawsuits.
The first lawsuit was filed in Orange County Superior Court and served on
SCE in June 1994. There are five named plaintiffs and six named
defendants, including SCE. Three of the five plaintiffs are presently or
were formerly employed by Grubb & Ellis, a real estate brokerage firm with
offices located in a commercial building known as the Koll Center in
Newport Beach. Two of the named plaintiffs are spouses of the other
plaintiffs. Grubb & Ellis and the owners and developers of the Koll
Center are also named as defendants in the lawsuit. This lawsuit alleges,
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<PAGE>
among other things, that the three plaintiffs employed by Grubb & Ellis
developed various forms of cancer as a result of exposure to EMF from
electrical facilities owned by SCE and/or the other defendants located on
Koll Center property. No specific damage amounts are alleged in the
complaint, but supplemental documentation prepared by the plaintiffs
indicates that plaintiffs allege compensatory damages of approximately $8
million, plus unspecified punitive damages. In December 1995, the court
granted SCE's motion for summary judgment and dismissed the case.
Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but
no date for oral argument has been set.
A second lawsuit was filed in Orange County Superior Court and served on
SCE in January 1995. This lawsuit arises out of the same fact situation
as the June 1994 lawsuit described above and involves the same defendants.
There are four named plaintiffs, two of whom were formerly employed by
Grubb & Ellis and now allegedly have various forms of cancer. The other
two plaintiffs are the spouses of those two individuals. No specific
damage amounts are alleged in the complaint, but supplemental
documentation prepared by the plaintiffs indicates that plaintiffs will
allege compensatory damages of approximately $13.5 million, plus
unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a
cross-complaint against the other co-defendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. Although stayed for a time pending
appellate review of sanctions imposed against plaintiffs' attorneys by the
trial court, the case has been remanded back to the trial court following
the Court of Appeal's decision modifying the sanctions order. To date,
no further proceedings have been scheduled.
A third case was filed in Orange County Superior Court and served on SCE
in March 1995. The plaintiff alleges, among other things, that he
developed cancer as a result of EMF emitted from SCE distribution lines
which he alleges were not constructed in accordance with CPUC standards.
No specific damage amounts are alleged in the complaint but supplemental
documentation prepared by the plaintiff indicates that plaintiff will
allege compensatory damages of approximately $5.5 million, plus
unspecified punitive damages. No trial date has been set in this case.
San Onofre Nuclear Generating Station Personal Injury Litigation
An SCE engineer employed at San Onofre died in 1991 from cancer of the
abdomen. On February 6, 1995, his children sued SCE and San Diego Gas &
Electric (SDG&E), as well as Combustion Engineering, the manufacturer of
the fuel rods for the plant, in the U.S. District court for the Southern
District of California. Plaintiffs alleged that the former employee's
illness resulted from, and was aggravated by, exposure to radiation at San
Onofre, including contact with radioactive fuel particles released from
failed fuel rods. Plaintiffs sought unspecified compensatory and punitive
damages. On April 3, 1995, the court granted the defendants' motion to
dismiss 14 of the plaintiffs' 15 claims. Punitive damages are not
available under the remaining claim. SCE's April 20, 1995, answer to the
complaint denied all material allegations. On October 10, 1995, the court
granted plaintiffs' motion to include the Institute of Nuclear Power
Operations (an organization dedicated to achieving excellence in nuclear
power operations) as a defendant in the suit. On December 7, 1995, the
court granted SCE's motion for summary judgment on the sole outstanding
claim against it, basing the ruling on the worker's compensation system
being the exclusive remedy for the claim. Plaintiffs have appealed this
ruling to the Ninth Circuit Court of Appeals. Oral argument on the appeal
has been set for December 4, 1997. All trial court proceedings have been
stayed pending the ruling of the Court of Appeals. The impact on SCE, if
any, from further proceedings in this case against the remaining
defendants cannot be determined at this time.
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On July 5, 1995, a former SCE reactor operator and his wife sued SCE and
SDG&E in the U.S. District court for the Southern District of California.
Plaintiffs also named Combustion Engineering, the manufacturer of the fuel
rods for the plant, and the Institute of Nuclear Power Operations as
defendants. The former employee died of leukemia shortly after the
complaint was filed. Plaintiffs allege that the former operator's illness
resulted from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles released from failed
fuel rods. Plaintiffs seek unspecified compensatory and punitive damages.
On November 22, 1995, the complaint was amended to allege wrongful death
and added the former employee's two children as plaintiffs. On December
22, 1995, SCE filed a motion to dismiss or, in the alternative, for
summary judgment based on worker's compensation exclusivity. On March 25,
1996, the court granted SCE's motion for summary judgment. Plaintiffs
have appealed this ruling to the Ninth Circuit Court of Appeals. Oral
argument on the appeal has been set for December 4, 1997. All trial court
proceedings have been stayed pending the ruling of the Court of Appeals
in this case and in the case described in the above paragraph. The impact
on SCE, if any, from further proceedings in this case against the
remaining defendants cannot be determined at this time.
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, the
manufacturer of fuel rods for the plant, and the Institute of Nuclear
Power Operations as defendants. The security officer worked for a
contractor in 1982, worked for SCE as a temporary employee (1982-1984),
and later worked as an SCE security supervisor (1984-1994). The officer
died of leukemia in 1994. Plaintiffs allege that the former officer's
illness resulted from, and was aggravated by, his exposure to radiation
at San Onofre, including contact with radioactive fuel particles released
from failed fuel rods. Plaintiffs seek unspecified compensatory and
punitive damages. SCE's November 13, 1995, answer to the complaint denied
all material allegations. All trial court proceedings have been stayed
pending the rulings of the Court of Appeals in the cases described in the
above two paragraphs.
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 manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs allege that the employee transported radioactive
byproducts on his person, clothing and/or tools to his home where his wife
was then exposed to radiation that caused her leukemia. Plaintiffs seek
unspecified compensatory and punitive damages. SCE's December 19, 1995,
partial answer to the complaint denied all material non-employment related
allegations. SCE's motion to dismiss the employee's employment related
allegations based on worker's compensation exclusivity was granted on
March 19, 1996. The employee's wife died on August 15, 1996. On
September 20, 1996, the complaint was amended to allege wrongful death and
to add the employee's two children as plaintiffs. SCE's motion for
summary judgment was denied on April 9, 1997. The trial in this case is
scheduled to begin on January 27, 1998.
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, the
manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege
that the former contract worker transported radioactive byproducts on her
person and clothing to her home where her son was then exposed to
radiation that caused his leukemia. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's January 2, 1996, answer denied
all material allegations. On August 12, 1996, the Court dismissed the
claims of the former worker and her husband with prejudice. This case is
expected to go to trial in early 1998, after completion of the trial in
the case described in the preceding paragraph.
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Oil Pipeline Litigation
On November 1, 1996, plaintiff, a crude oil pipeline company, filed a
lawsuit against SCE and the City of Los Angeles (the City) in the United
States District Court for the Central District of California claiming that
SCE and the City had interfered with its attempt to construct a proposed
132-mile oil pipeline (Pacific Pipeline) designed to transport oil from
the San Joaquin Valley and Santa Barbara to the Los Angeles refineries.
Plaintiff alleges, among other things, that SCE and the City wrongfully
initiated administrative and other legal proceedings in an attempt to
derail and obstruct the construction of the Pacific Pipeline. Plaintiff
alleges that these acts constitute unfair competition, tortious
interference with economic advantage and violate state and federal
antitrust laws. Plaintiff further claims that because of the alleged
delays, it could suffer losses in excess of $300 million. Additionally,
plaintiff seeks treble and punitive damages.
On June 30, 1997, SCE filed an answer to the complaint denying the
substantive allegations and raising appropriate defenses.
Rubaii False Claims Act Litigation
In September 1997, SCE became aware of a complaint filed in the Southern
District of the U.S. District Court of California by a San Onofre
employee, acting at his own initiative on behalf of the United States
under the False Claims Act, against SCE and SDG&E. The complaint alleges
that SCE and SDG&E have submitted fraudulent claims to the United States
government, the State of California and their customers resulting in $491
million in overpayments ($383 million of which is attributed to SCE). The
employee alleges that SCE and SDG&E provided the CPUC with data which
inflated projected costs at San Onofre while minimizing projected
revenues, resulting in the CPUC setting inflated rates. The amount sought
in this complaint is subject to trebling, plus civil penalties of $10,000
per false claim submitted for payment (for an unspecified number of
claims). SCE filed a motion to dismiss this lawsuit on November 7, 1997.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3. Certificate of Correction of Restated Articles of
Incorporation of Southern California Edison Company
as amended through June 1, 1993
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
None
page 49
<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 R. K. BUSHEY
---------------------------------
R. K. BUSHEY
Vice President and Controller
By K. S. STEWART
---------------------------------
K. S. STEWART
Assistant General Counsel and
Assistant Secretary
November 13, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Southern California Edison Financial Data Schedule - Exhibt 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,195,412
<OTHER-PROPERTY-AND-INVEST> 1,799,750
<TOTAL-CURRENT-ASSETS> 1,928,513
<TOTAL-DEFERRED-CHARGES> 2,635,481
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 17,559,156
<COMMON> 2,168,054
<CAPITAL-SURPLUS-PAID-IN> 370,922
<RETAINED-EARNINGS> 2,559,319
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,098,295
275,000
183,755
<LONG-TERM-DEBT-NET> 2,810,221
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 1,295,000
<COMMERCIAL-PAPER-OBLIGATIONS> 869,509
<LONG-TERM-DEBT-CURRENT-PORT> 276,575
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 6,750,801
<TOT-CAPITALIZATION-AND-LIAB> 17,559,156
<GROSS-OPERATING-REVENUE> 5,973,024
<INCOME-TAX-EXPENSE> 437,373
<OTHER-OPERATING-EXPENSES> 4,723,644
<TOTAL-OPERATING-EXPENSES> 5,161,017
<OPERATING-INCOME-LOSS> 812,007
<OTHER-INCOME-NET> (5,315)
<INCOME-BEFORE-INTEREST-EXPEN> 806,692
<TOTAL-INTEREST-EXPENSE> 323,329
<NET-INCOME> 483,363
22,729
<EARNINGS-AVAILABLE-FOR-COMM> 460,634
<COMMON-STOCK-DIVIDENDS> 562,099
<TOTAL-INTEREST-ON-BONDS> 259,503
<CASH-FLOW-OPERATIONS> 1,278,055
<EPS-PRIMARY> $0
<EPS-DILUTED> $0
</TABLE>
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report included in this quarterly report on Form
10-Q for the quarter ended September 30, 1997, 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 33-59001 May 15, 1995
Form S-3 333-00497 February 2, 1996
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 12, 1997
<PAGE>
EXHIBIT 3(i)
CERTIFICATE OF CORRECTION
OF
RESTATED ARTICLES OF INCORPORATION
OF
SOUTHERN CALIFORNIA EDISON COMPANY
as amended through June 1, 1993
ALAN J. FOHRER and BEVERLY P. RYDER certify that:
1. They are the Executive Vice President and Chief Financial Officer
and the Corporate Secretary, respectively, of SOUTHERN CALIFORNIA
EDISON COMPANY.
2. The name of the corporation is SOUTHERN CALIFORNIA EDISON
COMPANY, and it is a California corporation.
3. The instrument being corrected is Exhibit I to the "RESTATED
ARTICLES OF INCORPORATION OF SOUTHERN CALIFORNIA EDISON COMPANY
as amended through June 1, 1993." Said instrument was filed with
the Secretary of State of the State of California on June 1,
1993.
4. Paragraph "5" of the Certificate of Determination of Preferences
of the $100 Cumulative Preferred Stock, 6.45% Series, which is
Exhibit I to said Restated Articles of Incorporation, as
corrected, should read as follows:
PAGE
<PAGE>
BE IT FURTHER RESOLVED, that the dividend rate, redemption prices, rights
and terms of redemption and the voluntary liquidation preferences of
shares of such Series be and the same are hereby fixed, respectively, as
follows:
(A) The dividend rate of shares of such Series shall be six and
45/100 per centum (6.45%) per annum of the par value of the shares
thereof. Dividends on shares of such Series, when and as declared,
shall be payable quarterly on the last day of March, June, September
and December, respectively, with the first such dividend payable on
September 30, 1992.
(B) The shares of such Series shall not be subject to redemption by
this corporation prior to June 30, 2002.
(C) The outstanding shares of such Series shall be mandatorily
redeemed in whole and not in part on June 30, 2002, at the redemption
price of $100.00 per share, together with an amount equal to all
accumulated and unpaid dividends thereon to and including the date of
redemption (this corporation's obligation above in this paragraph (C)
being hereinafter referred to as the "Mandatory Redemption Obligation")
in accordance with the provisions of the Articles of Incorporation.
(D) In no event, so long as any shares of such Series shall be
outstanding, shall any dividend, whether in cash or property, be
paid or declared, nor shall any distribution be made, on any
stock of this corporation ranking junior to shares of such Series
as to payment of dividends or liquidation preferences nor shall
any shares of such stock ranking junior to such Series be
purchased, redeemed or otherwise acquired for value by this
corporation, unless this corporation shall have redeemed,
pursuant to paragraph (C) above, the shares of such Series
required to have been theretofore redeemed pursuant to such
paragraph (C). The provisions of this paragraph (D) shall in no
manner limit the rights of holders of shares of such Series to
otherwise enforce the Mandatory Redemption Obligation.
(E) The liquidation preferences payable with respect to shares of
such Series in the event of any voluntary liquidation,
dissolution or winding up of the affairs of this corporation
shall be $100.00 per share, together with an amount equal to all
accumulated and unpaid dividends thereon to and including the
date fixed for such distribution or payment.
5. The Certificate of Determination of the $100 Cumulative Preferred
Stock, 6.45% Series, which was filed as Exhibit I to the Restated
Articles of Incorporation on June 1, 1993, was not the correct
attachment. Paragraph "5" of the Certificate of Determination as
corrected above, conforms the wording of Exhibit I to that which was
adopted by the Board of Directors on July 7, 1992, and was
previously filed with the Secretary of State on July 17, 1992.
PAGE
<PAGE>
6. This certificate does not alter the wording of any resolution or
written consent adopted by the Board of Directors or the
shareholders.
We further declare under penalty of perjury under the laws of the State
of California that the matters set forth in this certificate are true and
correct of our own knowledge.
Date: June 23, 1997 ALAN J. FOHRER
----------------------------------
ALAN J. FOHRER
Executive Vice President and
Chief Financial Officer
BEVERLY P. RYDER
----------------------------------
BEVERLY P. RYDER
Corporate Secretary
