<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 June 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 August 12, 1997
- -------------------------- ------------------------------
Common Stock, no par value 434,888,104<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Report of Independent Public Accountants 2
Consolidated Statements of Income--Three, Six and
Twelve Months Ended June 30, 1997, and 1996 3
Consolidated Balance Sheets--June 30, 1997,
December 31, 1996, and June 30, 1996 4
Consolidated Statements of Cash Flows--
Three, Six and Twelve Months Ended
June 30, 1997, and 1996 6
Consolidated Statements of Retained Earnings--
Three, Six and Twelve Months Ended
June 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 30
Part II. Other Information:
Item 1. Legal Proceedings 42
Item 6. Exhibits and Reports on Form 8-K 47
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 June 30, 1997, December 31, 1996, and June 30, 1996,
and the related consolidated statements of income, retained earnings and
cash flows for each of the three-, six- and twelve-month periods ended
June 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 June 30, 1997, December 31, 1996, and June 30, 1996,
and the results of their operations and their cash flows for each of the
three-, six- and twelve-month periods ended June 30, 1997, and 1996, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
August 1, 1997
page 2
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
In thousands
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
----------------------- ------------------------- ------------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating revenue $1,843,995 $1,611,276 $3,539,433 $3,371,408 $7,751,407 $7,784,447
---------- ---------- ---------- ---------- ---------- ----------
Fuel 146,190 129,663 290,806 241,354 679,964 588,770
Purchased power 587,660 560,742 1,216,335 1,088,174 2,834,041 2,633,230
Provisions for regulatory
adjustment clauses--net (3,850) (201,506) (92,023) (103,682) (214,249) 80,607
Other operating expenses 291,605 340,658 532,562 613,285 1,097,592 1,253,684
Maintenance 116,699 67,030 212,576 150,689 391,258 325,639
Depreciation and decommissioning 311,485 274,549 617,068 516,887 1,163,688 1,001,695
Income taxes 133,585 133,514 228,881 241,959 565,255 567,177
Property and other taxes 31,344 49,058 70,220 102,565 157,939 198,667
---------- ---------- ---------- ---------- ---------- ----------
Total operating expenses 1,614,718 1,353,708 3,076,425 2,851,231 6,675,488 6,649,469
---------- ---------- ---------- ---------- ---------- ----------
Operating income 229,277 257,568 463,008 520,177 1,075,919 1,134,978
---------- ---------- ---------- ---------- ---------- ----------
Provision for rate phase-in plan (11,381) (18,867) (22,690) (47,945) (59,033) (112,313)
Allowance for equity funds
used during construction 1,897 3,066 3,900 7,468 12,012 16,026
Interest and dividend income 9,303 7,431 16,159 17,635 36,384 37,495
Other nonoperating income
(deductions)--net 5,849 (8,186) 10,498 4,743 2,132 32,533
---------- ---------- ---------- ---------- ---------- ----------
Total other income
(deductions)--net 5,668 (16,556) 7,867 (18,099) (8,505) (26,259)
---------- ---------- ---------- ---------- ---------- ----------
Income before interest expense 234,945 241,012 470,875 502,078 1,067,414 1,108,719
---------- ---------- ---------- ---------- ---------- ----------
Interest on long-term debt 90,556 94,158 181,744 191,866 370,691 384,959
Other interest expense 18,283 17,635 45,774 36,732 82,957 76,242
Allowance for borrowed funds
used during construction (2,284) (1,927) (4,696) (4,695) (9,796) (11,193)
Capitalized interest (735) (95) (2,055) (168) (3,597) (749)
---------- ---------- ---------- ---------- ---------- ----------
Total interest expense--net 105,820 109,771 220,767 223,735 440,255 449,259
---------- ---------- ---------- ---------- ---------- ----------
Net income 129,125 131,241 250,108 278,343 627,159 659,460
Dividends on preferred stock 7,372 8,599 15,971 17,197 33,168 34,395
---------- ---------- ---------- ---------- ---------- ----------
Earnings available for
common stock $ 121,753 $ 122,642 $ 234,137 $ 261,146 $593,991 $ 625,065
========== ========== ========== ========== ========== ==========
</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>
June 30, December 31, June 30,
1997 1996 1996
-------------- ------------ --------------
ASSETS
<S> <C> <C> <C>
Utility plant, at original cost $20,486,816 $20,400,387 $20,120,028
Less--accumulated provision for depreciation
and decommissioning 9,932,564 9,431,071 8,905,410
----------- ----------- -----------
10,554,252 10,969,316 11,214,618
Construction work in progress 529,040 556,645 644,791
Nuclear fuel, at amortized cost 174,216 176,827 124,621
----------- ----------- -----------
Total utility plant 11,257,508 11,702,788 11,984,030
----------- ----------- -----------
Nonutility property--less accumulated provision
for depreciation of $23,942, $25,102 and $26,241
at respective dates 68,054 63,931 88,606
Nuclear decommissioning trusts 1,670,747 1,485,525 1,342,500
Other investments 137,882 103,973 84,189
----------- ----------- -----------
Total other property and investments 1,876,683 1,653,429 1,515,295
----------- ----------- -----------
Cash and equivalents 239,381 319,942 515,045
Receivables, including unbilled revenue, less
allowances of $21,833, $26,079 and $22,550 for
uncollectible accounts at respective dates 982,010 921,083 654,055
Fuel inventory 63,046 72,480 105,821
Materials and supplies, at average cost 151,986 154,266 151,253
Accumulated deferred income taxes--net 193,749 240,429 341,224
Prepayments and other current assets 17,278 105,137 29,485
----------- ----------- -----------
Total current assets 1,647,450 1,813,337 1,796,883
----------- ----------- -----------
Unamortized debt issuance and reacquisition
expense 332,627 346,834 362,633
Rate phase-in plan 29,119 50,703 83,709
Unamortized nuclear plant--net - - 16,770
Income tax-related deferred charges 1,615,930 1,741,091 1,754,879
Other deferred charges 541,918 428,370 319,849
----------- ----------- -----------
Total deferred charges 2,519,594 2,566,998 2,537,840
----------- ----------- -----------
Total assets $17,301,235 $17,736,552 $17,834,048
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page4
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
June 30, December 31, June 30,
1997 1996 1996
----------- ------------ -----------
CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
<S> <C> <C> <C>
Common stock (434,888,104 shares outstanding
at each date) $ 2,168,054 $ 2,168,054 $ 2,168,054
Additional paid-in capital and other 225,703 210,857 206,677
Retained earnings 2,554,389 2,665,612 2,680,388
----------- ----------- -----------
4,948,146 5,044,523 5,055,119
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 4,498,782 4,778,703 5,030,731
----------- ----------- -----------
Total capitalization 9,905,683 10,381,981 10,644,605
----------- ----------- -----------
Other long-term liabilities 506,066 423,925 333,907
----------- ----------- -----------
Current portion of long-term debt 576,470 501,470 201,375
Short-term debt 145,244 230,149 392,340
Accounts payable 382,952 392,779 336,004
Accrued taxes 650,332 484,688 468,912
Accrued interest 97,525 93,363 101,999
Dividends payable 171,752 108,563 112,320
Regulatory balancing accounts--net 86,516 181,488 226,828
Deferred unbilled revenue and other current liabilities 772,731 825,317 756,491
----------- ----------- -----------
Total current liabilities 2,883,522 2,817,817 2,596,269
----------- ----------- -----------
Accumulated deferred income taxes--net 3,000,988 3,170,696 3,281,767
Accumulated deferred investment tax credits 336,966 347,118 358,177
Customer advances and other deferred credits 668,010 595,015 619,323
----------- ----------- -----------
Total deferred credits 4,005,964 4,112,829 4,259,267
----------- ----------- -----------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $17,301,235 $17,736,552 $17,834,048
=========== =========== ===========
</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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------------- --------------------- ------------------------
1997 1996 1997 1996 1997 1996
--------- --------- --------- --------- ---------- ----------
Cash flows from operating activities:
<S> <C> <C> <C> <C> <C> <C>
Net income $ 129,125 $ 131,241 $ 250,108 $ 278,343 $ 627,159 $ 659,460
Adjustments for non-cash items:
Depreciation and
decommissioning 311,485 274,549 617,068 516,887 1,163,686 1,001,695
Amortization 19,817 25,701 31,981 53,589 69,323 99,854
Rate phase-in plan 10,894 17,660 21,584 46,005 54,590 105,756
Deferred income taxes and
investment tax credits (51,573) 76,523 (8,019) 44,042 (5,939) (105,262)
Other long-term liabilities 54,018 (39,895) 82,141 (10,285) 172,159 (5,110)
Other--net (46,314) 8,315 (67,357) 5,510 (225,899) 54,731
Changes in working capital:
Receivables (149,887) 210,287 (60,927) 257,908 (327,955) 219,287
Regulatory balancing accounts (19,989) (212,526) (94,972) (111,039) (140,312) 113,215
Fuel inventory, materials
and supplies (2,948) 4,515 11,714 8,463 42,042 32,308
Prepayments and other
current assets 42,516 40,955 87,859 84,804 12,207 (17,565)
Accrued interest and taxes 82,414 (190,587) 169,806 (65,967) 176,946 (99,994)
Accounts payable and other
current liabilities 40,673 24,522 (62,413) (32,239) 63,188 14,090
--------- --------- --------- --------- ---------- ----------
Net cash provided by
operating activities 420,231 371,260 978,573 1,076,021 1,681,195 2,072,465
--------- --------- --------- --------- ---------- ----------
Cash flows from financing activities:
Long-term debt issued -- 313 -- 397,607 -- 397,514
Long-term debt repayments (50) -- (200,055) (406,372) (198,938) (612,380)
Preferred stock redemptions (100,000) -- (100,000) -- (100,000) --
Nuclear fuel financing--net (13,092) 2,980 (7,061) (5,457) 40,199 5,488
Short-term debt financing--net 10,418 85,805 (84,905) 32,832 (247,096) (211,993)
Dividends paid (112,525) (259,509) (298,142) (404,011) (693,725) (694,128)
--------- --------- --------- --------- ---------- ----------
Net cash used by
financing activities (215,249) (170,411) (690,163) (385,401) (1,199,560) (1,115,499)
--------- --------- --------- --------- ---------- ----------
Cash flows from investing activities:
Additions to property and plant (132,239) (156,553) (283,646) (340,922) (559,151) (740,832)
Funding of nuclear decommissioning
trusts (46,684) (36,657) (74,573) (72,632) (150,100) (150,671)
Unrealized gain in equity
investments--net 7,205 7,166 14,448 10,798 18,550 14,692
Other--net (17,166) (26,926) (25,200) (34,586) (66,598) (44,710)
--------- --------- --------- --------- ---------- ----------
Net cash used by
investing activities (188,884) (212,970) (368,971) (437,342) (757,299) (921,521)
--------- --------- --------- --------- ---------- ----------
Net increase (decrease) in cash
and equivalents 16,098 (12,121) (80,561) 253,278 (275,664) 35,445
Cash and equivalents, beginning
of period 223,283 527,166 319,942 261,767 515,045 479,600
--------- --------- --------- --------- ---------- ----------
Cash and equivalents, end
of period $ 239,381 $ 515,045 $ 239,381 $ 515,045 $ 239,381 $ 515,045
========= ========= ========= ========== ========== ==========
Cash payments for interest and taxes:
Interest--net of amounts capitalized $ 96,673 $ 95,291 $ 176,300 $ 171,686 $ 351,595 $ 377,420
Taxes 17,217 153,304 17,472 183,351 379,376 734,785
</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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
---------------------- ---------------------- ------------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance at beginning of period $2,603,439 $2,737,651 $2,665,612 $2,780,058 $2,680,388 $2,688,402
Net income 129,125 131,241 250,108 278,343 627,159 659,460
Dividends declared on common
stock (170,803) (179,888) (345,360) (360,799) (719,989) (633,062)
Dividends declared on preferred
stock (7,372) (8,599) (15,971) (17,197) (33,168) (34,395)
Reacquired capital stock
expense -- (17) -- (17) (1) (17)
---------- ---------- ---------- ---------- ---------- ----------
Balance at end of period $2,554,389 $2,680,388 $2,554,389 $2,680,388 $2,554,389 $2,680,388
========== ========== ========== ========== ========== ==========
</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, 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).
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.
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.
page 8
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 9.49% 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 June 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.
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, $12 million and
$24 million for the three, six and twelve months ended June 30, 1997,
respectively, and $5 million, $9 million and $23 million for the three,
six and twelve months ended June 30, 1996, respectively.
page 9
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 5.3%, 5.3% and 4.9% for the three, six and twelve months ended June
30, 1997, respectively, and 4.3%, 4.0% and 3.8% for the three, six and
twelve months ended June 30, 1996.
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
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 based on cost-of-
service regulation 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 for utility workers.
Rate Reduction Bonds - On May 6, 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. On the same day, 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
page 10
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
electricity consumption. With the CPUC's decision expected in September
1997, and subject to the 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.
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 on March 31,
1997, and included SCE's proposed transmission revenue requirement. A
FERC decision is expected in late 1997. 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%. 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.
Direct Customer Access - On May 6, 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
page 11
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 on May 6, 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
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. SCE is reviewing the potential effect of these
decisions on its results of operations and financial condition.
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. It is anticipated 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
page 12
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 of its oil- and gas-fueled generation
assets. 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 recent
restructuring legislation. 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. CPUC approval of the oil- and gas-fueled generation
divestiture was requested for late 1997.
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 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 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 ratemaking issues and Phase 2 the quantification
issues. Hearings on Phase 1 were held in December 1996 and a decision was
issued on June 11, 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. A decision on Phase 2 is expected in the fourth quarter of
1997.
page 13
<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 Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting.
If, as expected, this consensus is formally issued by the EITF, SCE will
be required to discontinue application of these regulatory accounting
standards immediately for its generation-related operations. The net
plant investment related to these operations is approximately $5.0
billion. SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $800 million
at June 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 at the July EITF meeting also
permits the recording of new generation-related 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.
page 14
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
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 and Equivalents
Cash equivalents include tax-exempt investments ($215 million at June 30,
1997, $261 million at December 31, 1996, and $433 million at June 30,
1996), and time deposits and other investments ($18 million at June 30,
1997, $43 million at December 31, 1996, and $50 million at June 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
page 15
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
fluctuations in interest rates, but prohibits the use of these instruments
for speculative or trading purposes.
SCE uses the hedge accounting method to record its derivative financial
instruments. 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. For all
balance sheet dates presented, SCE had the following derivative financial
instruments:
<TABLE>
<CAPTION>
Category Contract Amount/Terms Purpose
- -------- --------------------- -------
<S> <C> <C> <C>
Interest rate swap $196 million due 2008 fix interest rate at 5.585%
Interest rate cap $30 million expired cap interest rate at 6%
July 1, 1997, debt due 2027
</TABLE>
The interest rate swap agreement requires the parties to pledge collateral
according to bond rating and market interest rate changes. At June 30,
1997, SCE had pledged $16 million as collateral due to a decline in market
interest rates. SCE is exposed to credit loss in the event of
nonperformance by counterparties to these agreements, but does not expect
the counterparties to fail to meet their obligations.
Fair Value of Financial Instruments
Fair values of financial instruments were:
<TABLE>
<CAPTION>
June 30, December 31, June 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 $1,292 $1,671 $1,217 $1,485 $1,142 $1,343
Equity investments 11 91 11 68 11 61
Financial liabilities:
DOE decommissioning and
decontamination fees 54 45 54 45 58 46
Interest rate swap & cap -- 17 -- 16 -- 12
Long-term debt 4,499 4,672 4,779 5,001 5,031 5,100
Preferred stock subject to
mandatory redemption 275 288 275 286 275 277
</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
page 16
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Gross unrealized holding gains on financial assets were:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
1997 1996 1996
---------- ------------ --------
(In millions)
Decommissioning trusts:
<S> <C> <C> <C>
Municipal bonds $108 $ 79 $ 58
Stocks 198 138 103
U.S. government issues 68 39 28
Short-term and other 5 12 12
---- ---- ----
379 268 201
Equity investments 80 57 50
---- ---- ----
Total $459 $325 $251
==== ==== ====
</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 June 30, 1997, are: 1998--$576 million;
1999--$322 million; 2000--$330 million; 2001--$400 million; and 2002--
zero.
page 17
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt consisted of:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
1997 1996 1996
-------------- ------------ -------------
(In millions)
First and refunding mortgage bonds:
<C> <C> <C> <C>
1997--2026 (5.45% to 8-7/8%) $2,525 $2,725 $2,725
Pollution-control bonds:
1999--2027 (5.4% to 7.2% and variable) 1,204 1,204 1,205
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 105 112 65
Long-term debt due within one year (576) (501) (201)
Unamortized debt discount--net (52) (54) (56)
------ ------ ------
Total $4,499 $4,779 $5,031
====== ====== ======
</TABLE>
Short-Term Debt
SCE has lines of credit it can use at negotiated or bank index rates. At
June 30, 1997, available lines totaled $1.8 billion, with $1.3 billion 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 June 30, 1997, December 31,
1996, and June 30, 1996, was $251 million, $345 million and $460 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 5.7%, 5.5% and 5.4%, at June 30, 1997, December 31,
1996, and June 30, 1996, respectively.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may
pay Edison International. At June 30, 1997, SCE had the capacity to pay
$512 million 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 June 30, 1997, are: 1998 through 2001--zero and 2002--$105
million.
page 18
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
June 30, 1997
---------------------------
Shares Redemption June 30, December 31, June 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 19
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED STATEMENTS
The components of the net accumulated deferred income tax liability were:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
1997 1996 1996
------------- ------------ -------------
(In millions)
Deferred tax assets:
<S> <C> <C> <C>
Property-related $ 238 $ 247 $ 256
Investment tax credits 198 206 213
Regulatory balancing accounts 123 205 148
Decommissioning-related 107 208 84
Other 533 429 516
------ ------ ------
Total 1,199 1,295 1,217
------ ------ ------
Deferred tax liabilities:
Property-related 3,396 3,550 3,630
Other 610 676 528
------ ------ ------
Total 4,006 4,226 4,158
------ ------ ------
Accumulated deferred income taxes--net $2,807 $2,931 $2,941
====== ====== ======
Classification of accumulated deferred income taxes:
Included in deferred credits $3,001 $3,171 $3,282
Included in current assets 194 240 341
</TABLE>
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
----------------- ---------------- ----------------
1997 1996 1997 1996 1997 1996
---- ----- ---- ---- ---- ----
(In millions)
Current:
<S> <C> <C> <C> <C> <C> <C>
Federal $151 $ 30 $176 $120 $441 $476
State 36 11 55 52 132 154
---- ---- ---- ---- ---- ----
187 41 231 172 573 630
---- ---- ---- ---- ---- ----
Deferred--federal and state:
Accrued charges (11) (21) (13) (22) (5) (17)
Depreciation (11) 2 (23) (5) (33) 4
Investment and energy tax credits--net (5) (6) (10) (13) (21) (25)
Pension reserves (1) - (2) - 49 -
Rate phase-in plan (4) (7) (10) (18) (22) (43)
Regulatory balancing accounts 11 83 37 34 37 (55)
Retirement of debt (3) (3) (5) (6) (11) (11)
State tax--privilege year (12) (3) 15 36 - 4
Unbilled revenue (16) 46 (8) 48 (56) 63
Workforce management - (21) - (19) - (25)
Other (9) 2 1 2 5 (11)
----- ----- ----- ----- ----- -----
(61) 72 (18) 37 (57) (116)
----- ----- ----- ----- ----- -----
Total income tax expense $126 $ 113 $ 213 $ 209 $ 516 $ 514
===== ===== ===== ===== ===== =====
Classification of income taxes:
Included in operating income $134 $ 134 $ 229 $ 242 $ 565 $ 567
Included in other income (8) (21) (16) (33) (49) (53)
</TABLE>
page 20
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO FINANCIAL STATEMENTS
The composite federal and state statutory income tax rate was 40.551%,
40.551% and 40.798% for the three, six and twelve months ended June 30,
1997, respectively, and 41.045% for the three, six and twelve months ended
June 30, 1996.
The federal statutory income tax rate is reconciled to the effective tax
rate below:
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------- --------------- ---------------
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 (0.7) (0.7) (0.8) (0.7) (0.8) (0.7)
Depreciation and other 9.8 6.8 6.4 4.0 5.5 4.6
Investment and energy tax credits (2.0) (2.6) (2.2) (2.6) (1.9) (2.2)
State tax--net of federal deduction 7.3 7.7 7.6 7.2 7.3 7.1
----- ----- ----- ----- ----- -----
Effective tax rate 49.4% 46.2% 46.0% 42.9% 45.1% 43.8%
===== ===== ===== ===== ===== =====
</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 3.9 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
recipient or beneficiary. If an optionee is terminated other than by
page 21
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO FINANCIAL STATEMENTS
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 $8 million, $15 million and $21 million
for the three, six and twelve months ended June 30, 1997, respectively,
and $1 million, $1 million, and $3 million for the three, six and twelve
months ended June 30, 1996, respectively.
Stock-based compensation expense under the fair-value method of accounting
would have resulted in pro forma earnings of $123 million, $236 million
and $598 million for the three, six and twelve months ended June 30, 1997,
respectively, and $138 million, $261 million and $624 million for the
three, six and twelve months ended June 30, 1996, respectively.
The weighted-average fair value of options granted during the twelve
months ended June 30, 1997, and June 30, 1996, was $7.66 per share option
and $6.27 per share option, respectively. The weighted-average remaining
life of options outstanding as of June 30, 1997, December 31, 1996, and
June 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:
<TABLE>
<CAPTION>
12 Months Ended
June 30,
-------------------------------
1997 1996
-------------- --------------
<S> <C> <C>
Expected life 7 years 7 years
Risk-free interest rate 6.5% - 6.8% 5.5%
Expected volatility 17% 17%
</TABLE>
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 22
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The plan's funded status was:
<TABLE>
<CAPTION>
June 30, December 31, June 30,
1997 1996 1996
-------------- ------------- --------------
(In millions)
Actuarial present value of benefit obligation:
<S> <C> <C> <C>
Vested benefits $1,530 $1,670 $2,071
Nonvested benefits 76 71 70
------ ------ ------
Accumulated benefit obligation 1,606 1,741 2,141
Value of projected future compensation levels 282 261 300
------ ------ ------
Projected benefit obligation $1,888 $2,002 $2,441
====== ====== ======
Fair value of plan assets $2,221 $2,165 $2,782
====== ====== ======
Projected benefit obligation less
than plan assets $ (333) $ (163) $ (341)
Unrecognized net gain 454 300 464
Unrecognized prior service cost (191) (199) (126)
Unrecognized net obligation (17-year amortization) (41) (43) (46)
------ ------ ------
Pension liability (asset) $ (111) $ (105) $ (49)
====== ====== ======
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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------- --------------- ----------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Service cost for benefits earned $ 11 $ 16 $ 22 $ 33 $ 38 $ 62
Interest cost projected benefit obligation 35 44 70 87 161 166
Actual return on plan assets (210) (52) (232) (153) (422) (410)
Net amortization and deferral 174 2 160 52 253 215
---- ---- ---- ---- ---- ----
Pension expense under accounting standards 10 10 20 19 30 33
Special termination benefits - - - - - 3
Regulatory adjustment--deferred 3 4 6 9 19 20
---- ---- ---- ---- ---- ----
Net pension expense recognized 13 14 26 28 49 56
Settlement gain - (78) - (78) (43) (78)
---- ---- ---- ---- ---- ----
Total expense (gain) $ 13 $(64) $ 26 $(50) $ 6 $(22)
==== ==== ==== ==== ==== ====
</TABLE>
page 23
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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>
June 30, December 31, June 30,
1997 1996 1996
------------- ------------- -------------
(In millions)
Actuarial present value of benefit obligation:
<S> <C> <C> <C>
Retirees $ 932 $ 928 $ 573
Employees eligible to retire 36 35 47
Other employees 416 386 408
------ ------ -----
Accumulated benefit obligation $1,384 $1,349 $1,028
====== ====== ======
Fair value of plan assets $ 668 $ 617 $ 515
====== ====== ======
Plan assets less than accumulated benefit
obligation $ 716 $ 732 $ 513
Unrecognized transition obligation (20-year
amortization) (417) (430) (443)
Unrecognized net gain (loss) (228) (231) (20)
------ ------ ------
Recorded liability $ 71 $ 71 $ 50
====== ====== ======
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 6 Months Ended 12 Months Ended
June 30, June 30, June 30,
--------------- --------------- ----------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
(In millions)
<S> <C> <C> <C> <C> <C> <C>
Service cost for benefits earned $ 7 $ 9 $ 15 $ 19 $ 27 $ 37
Interest cost on benefit obligation 25 19 51 39 102 79
Actual return on plan assets (13) (9) (26) (19) (51) (33)
Amortization of loss 2 2 3 4 6 5
Amortization of transition obligation 7 7 13 13 27 23
---- ---- ---- ---- ---- ----
Net expense 28 28 56 56 111 111
Special termination expense - 49 - 49 23 49
---- ---- ---- ---- ---- ----
Total expense $ 28 $ 77 $ 56 $105 $134 $160
==== ==== ==== ==== ==== ====
</TABLE>
page 24
<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 June 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 $4 million, $7 million and $22 million for the three, six and twelve
months ended June 30, 1997, respectively, and $5 million, $10 million and
$19 million for the three, six and twelve months ended June 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 June 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 74 11 50
Generating stations:
Four Corners Units 4 and 5 (coal) 457 241 3 48
Mohave (coal) 301 143 8 56
Palo Verde (nuclear) 1,598 544 7 16
San Onofre (nuclear) 4,199 2,033 24 75
------ ------ ---
Total $6,815 $3,044 $54
====== ====== ===
</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 June 30, 1997,
were:
<TABLE>
<CAPTION>
<S> <C>
Year ended December 31, (In millions)
1997 $10
1998 17
1999 13
2000 11
2001 7
Thereafter 9
---
Total $67
===
</TABLE>
page 25
<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 $39 million, $75 million and $150 million for the three, six and
twelve months ended June 30, 1997, respectively, and $36 million, $73
million and $151 million for the three, six and twelve months ended June
30, 1996, respectively. The accumulated provision for decommissioning was
$1.0 billion at June 30, 1997, $949 million at December 31, 1996, and $884
million at June 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 June 30, December 31, June 30,
Dates 1997 1996 1996
---------- ------------- --------------- -------------
(In millions)
<S> <C> <C> <C> <C>
Municipal bonds 1999-2023 $ 439 $ 400 $ 366
Stocks -- 544 549 525
U.S. government issues 1998-2024 300 212 180
Short-term and other 1997-2024 9 56 71
------ ------ ------
Total $1,292 $1,217 $1,142
====== ====== ======
</TABLE>
Trust fund earnings (based on specific identification) increase the trust
fund balance and the accumulated provision for decommissioning. Net
earnings were $14 million, $25 million and $50 million for the three, six
and twelve months ended June 30, 1997, respectively, and $11 million, $23
million and $51 million for the three, six and twelve months ended June
30, 1996, respectively. Proceeds from sales of securities (which are
reinvested) were $114 million, $261 million and $628 million for the
three, six and twelve months ended June 30, 1997, respectively, and $219
million, $587 million and $1.1 billion for the three, six and twelve
months ended June 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
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
page 26
<PAGE>
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $852 $910 $757 $730 $712
Fuel supply contracts 207 160 148 167 153
Purchased-power capacity payments 699 702 704 705 699
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 27
<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 incorporating particular 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 55 identified
sites is $186 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 $245
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 $99 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 $160
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 June 30, 1997, were $8 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 28
<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 $33 million per year.
Insurance premiums are charged to operating expense.
page 29
<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's (SCE) earnings for the three, six and twelve
months ended June 30, 1997, were $122 million, $234 million and $594
million, respectively, compared with $123 million, $261 million and $625
million for the same periods in 1996. Second quarter and year-to-date
June 30, 1996, earnings include $32 million in special charges for
workforce adjustment expenses. For the twelve months ended June 30, 1997,
non-recurring items were a $14 million net gain for workforce
adjustments/reserves, compared with a $37 million charge for workforce
adjustments in the year-earlier period. Before one-time items, SCE's
earnings for the three, six and twelve months ended June 30, 1997, were
$122 million, $234 million and $580 million, respectively, down $33
million, $59 million and $82 million from the year-earlier periods,
primarily due to the impact of the extended refueling outages at the San
Onofre Nuclear Generating Station and the lower return on nuclear units
(see discussion in Regulatory Matters). The quarterly and year-to-date
decreases were partially offset by a reduction in costs from operations
and an increase in electricity sales.
Operating Revenue
Operating revenue increased 14% and 5% for the three and six months ended
June 30, 1997, respectively, compared with the same periods in 1996, due
to a higher volume of sales to all customer groups relative to the same
periods last year. The higher volume is also attributable to an increase
in the number of customers over the prior year and increased demand for
electricity due to unseasonably warm weather during the month of May,
1997. For the twelve months ended June 30, 1997, operating revenue
decreased slightly when compared to the year-earlier period, as increased
sales volume was more than offset by lower average rates. Average rates
fell approximately 4% when compared to the year-earlier period. The lower
rates are attributable to the California Public Utilities Commission's
(CPUC) decision effective April 1996 which lowered SCE's 1996 authorized
revenue by $338 million, or 4.4%. Rates in 1997 are unchanged from April
1996. Over 98% of operating revenue is from retail sales. Retail rates
are regulated by the 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 cemts 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 30
<PAGE>
Operating Expenses
Fuel expense increased 13%, 21% and 16%, respectively, for the three, six
and twelve months ended June 30, 1997. The increases are due to 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 and Unit 3
was shut down 80 days of the second quarter, thus resulting in an overall
increase in gas-powered generation for all periods presented. There were
no comparable outages in 1996.
Purchased-power expense increased slightly during the quarter and
increased 12% and 8%, respectively, for the six- and twelve-month periods
ended June 30, 1997. The increase is due to an increase in purchases in
the open market particularly in the Southwest and increases in power
purchased under federally-mandated contracts. SCE is required under
federal law to purchase power from certain nonutility generators even
though energy prices under these contracts are generally higher than other
sources. For the twelve months ended June 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 increased substantially for
the three months ended June 30, 1997, compared to the year-earlier period.
The quarterly increase is primarily due to the effect of the 1996 CPUC-
ordered $237 million refund to customers for energy cost balancing account
overcollections of which $179 million was paid in the second quarter of
1996. There was no comparable refund paid in 1997. The quarterly
increase is also attributable to the San Onofre Units 2 and 3 refueling
outages. Undercollections in the second quarter of 1996 at San Onofre
(the San Onofre units operated at higher capacities than estimated) were
partially offset by overcollections in the second quarter of 1997 due to
decreased nuclear generation as a result of the outages at Units 2 and 3.
Another contribution to the quarterly increase is overcollections due to
the accelerated recovery of SCE's remaining investment at San Onofre. For
the six months ended June 30, 1997, the provisions increased 11%, compared
with the same period in 1996. The year-to-date increase is primarily due
to overcollections related to: the San Onofre second quarter factors
discussed above; actual base-rate revenue from kilowatt-hour sales
exceeding CPUC-authorized estimates; and the effect of the 1996 CPUC-
ordered refund, also discussed above. However, these overcollections were
almost completely offset by actual energy costs exceeding CPUC-authorized
fuel and purchased-power cost estimates. For the twelve months ended June
30, 1997, the provision decreased due to actual energy costs exceeding
CPUC-authorized fuel and purchased-power cost estimates, partially offset
by the effects of the CPUC-ordered refund in 1996 and overcollections
related to actual base-rate revenue from kilowatt-hour sales exceeding
CPUC-authorized estimates.
Other operating expenses decreased 14%, 13% and 13%, respectively, for the
three, six and twelve months ended June 30, 1997, compared with the year-
earlier periods, due to reduced payroll costs resulting from workforce
reductions associated with SCE's voluntary retirement program in 1996,
partially offset by a reallocation of payroll taxes.
Maintenance expense increased substantially in all periods presented
compared with the year-earlier periods, due to scheduled refueling outages
at the San Onofre units and increased maintenance costs for electric plant
assets. There were no comparable outages for the nuclear units during the
same periods in 1996.
Depreciation and decommissioning expense increased 14%, 19% and 16%,
respectively, for the three-, six- and twelve-month periods ended June
30, 1997, due to increases in plant assets and the accelerated recovery
of the San Onofre Units 2 and 3 effective April 1996 and the accelerated
recovery of the Palo Verde Nuclear Generating Station units effective
January 1997.
page 31
<PAGE>
Property and other taxes decreased 36%, 32% and 21%, respectively, for the
three-, six- and twelve-month periods ended June 30, 1997, due to changes
in SCE's internal payroll tax allocation methods in 1997 from 1996.
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 increased for the three and six months ended
June 30, 1997, compared to the same periods in 1996, primarily due to
prior year accruals for regulatory expenses and other operating reserves
established in 1996. For the twelve months ended June 30, 1997, other
nonoperating income decreased due to increases in operating reserves in
the third and fourth quarter of 1996.
Interest Expense
Other interest expense increased for the six and twelve months ended June
30, 1997, compared to the same periods in 1996, due to balancing account
overcollections.
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 52.2 million shares ($1.1 billion) between
January 1995 and August 1, 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 and six months ended
June 30, 1997, was 3.7 times and 3.3 times, respectively, compared to 1.4
times and 2.7 times for the year-earlier periods as the aggregate amount
of dividends paid decreased as a result of the ongoing share repurchase
program. For the twelve months ended June 30, 1997, the coverage ratio
decreased to 2.4 times from 3.0 due to reductions in the issuance of long-
term debt.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $420 million, $979
million and $1.7 billion, respectively, for the three, six and twelve
months ended June 30, 1997, compared with $371 million, $1.1 billion and
$2.1 billion for the same periods in 1996. Cash from operations exceeded
capital requirements for all periods presented.
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 June
30, 1997, SCE could issue approximately $8.7 billion of additional first
and refunding mortgage bonds and $4.7 billion of preferred stock at
current interest and dividend rates.
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At June 30, 1997, SCE had available lines of credit of $1.8 billion, with
$1.3 billion 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
June 30, 1997, SCE had the capacity to pay $512 million 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--$852 million; 1998--$910 million; 1999--$757 million; 2000--$730
million; and 2001--$712 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 1997, are: 1998--$576 million;
1999--$322 million; 2000--$330 million; 2001--$400 million; and 2002--
zero.
Preferred stock redemption requirements for the five twelve-month periods
following June 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
recently enacted legislation 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, would reduce 1997
earnings by approximately $5 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 the current 9.49% 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
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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
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 based on cost-of-
service regulation during the 1998-2001 transition period. In addition,
the legislation mandates the implementation of a non-bypassable
competition transition charge (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 for utility workers.
Rate Reduction Bonds - On May 6, 1997, SCE filed an application with the
CPUC requesting approval of the issuance of an aggregate amount of up to
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$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. On the same day, 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. With the CPUC's decision expected in September
1997, and subject to the 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 various market revenue, the CTC mechanism after petitioning the
CPUC to 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 on March 31,
1997, and included SCE's proposed transmission revenue requirement. A
FERC decision is expected in late 1997. 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%. 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.
Direct Customer Access - On May 6, 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.
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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 on May 6, 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
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. SCE is reviewing the potential effect of these
decisions on its results of operations and financial condition.
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. It is anticipated 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
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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 of its oil- and gas-fueled generation
assets. 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 recent
restructuring legislation. 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. CPUC approval of the oil- and gas-fueled generation
divestiture was requested for late 1997.
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 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 and Palo Verde (as discussed in Note 1 to Consolidated
Financial Statements) 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 ratemaking
issues and Phase 2 the quantification issues. Hearings on Phase 1 were
held in December 1996 and a decision was issued on June 11, 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. A 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
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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.
If, as expected, this consensus is formally issued by the EITF, SCE will
be required to discontinue application of these regulatory accounting
standards immediately for its generation-related operations. The net
plant investment related to these operations is approximately $5.0
billion. SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $800 million
at June 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 at the July EITF meeting also
permits the recording of new generation-related 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
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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.
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 incorporating particular 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 55
identified sites is $186 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 $245 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 $99 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 $160 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.
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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 June 30, 1997, were $8 million.
Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental cleanup
costs, SCE believes that costs ultimately recorded will not materially
affect its results of operations or financial position. There can be no
assurance, however, that future developments, including additional
information about existing sites or the identification of new sites, will
not require material revisions to such estimates.
The 1990 federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions
allowances from the federal government and may bank or sell excess
allowances. SCE expects to have excess allowances under Phase II of the
Clean Air Act (2000 and later). The act also calls for a study to
determine if additional regulations are needed to reduce regional haze in
the southwestern U.S. In addition, another study 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 is receiving increased
attention. The scientific community has not yet reached a consensus on
the nature of any health effects of EMF. 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 estimates its share of the steam generator replacement costs to be
between $16 million and $30 million, plus replacement power costs. SCE
is evaluating APS' analyses, conducting its own review, and has not yet
decided whether it supports replacement of the steam generators.
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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.
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 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 41
<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, which SCE expects to file in August 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
provides for plaintiffs to dismiss the lawsuit without prejudice pending
final CPUC resolution of the issues raised by SCE's application.
Accordingly, the application remains pending but without a hearing date.
page 42
<PAGE>
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, and is currently under submission. No trial date has
been set for the single case not consolidated for trial with the others.
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,
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
page 43
<PAGE>
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. 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.
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
page 44
<PAGE>
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. 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 November 24, 1997.
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.
Employment Discrimination Litigation
On September 21, 1994, nine African-American employees filed a lawsuit
against Edison International and SCE on behalf of a class of African-
American employees, alleging racial discrimination in job advancement,
pay, training and evaluation. The lawsuit was filed in the United States
District Court for the Central District of California. The plaintiffs
sought injunctive relief, as well as an unspecified amount of compensatory
and punitive damages, attorneys' fees, costs and interest. Edison
page 45
<PAGE>
International and SCE responded by denying the material allegations of the
complaint and asserting several affirmative defenses.
Simultaneous with discovery, the parties entered into settlement
discussions. The parties agreed to include the Equal Employment
Opportunity Commission (EEOC) in their settlement discussions after that
agency indicated its intent to intervene in the lawsuit in support of the
plaintiffs. The parties and EEOC agreed upon settlement terms and
submitted a proposed Consent Decree to the court for approval. After
certain issues raised by the court were addressed through a modification
of the proposed Decree, the court granted preliminary approval of the
modified Consent Decree on August 5, 1996, ordered that notice be given
to the class members, and scheduled a final fairness hearing on September
26, 1996.
Fifteen individuals and an organization filed timely objections to the
proposed Consent Decree and a motion to intervene in the lawsuit.
Thirteen individuals filed timely requests to be excluded from the
monetary provisions of the proposed Decree. On September 25, 1996, the
court denied the motion to intervene. After the hearing on September 26,
at which the court heard oral argument from the objectors, the court on
September 30, 1996, overruled the objections and granted final approval
of the Consent Decree.
The Decree provides that a settlement fund of $8.15 million for back pay
claims and $3.1 million for emotional distress claims be established, and
it contains an expedited claim review process for class members who make
claims to the settlement fund. The Decree also provides for improvements
in SCE's internal claims resolution process, expansion of career
development and skills training programs, expansion of diversity training
programs, and improvements in other human resources systems. The Decree
has a seven-year term, with the possibility of early termination after
five years.
On October 25, 1996, the organization and individuals who sought to
intervene and/or object to the Consent Decree served notice of appeal from
the court's orders denying intervention and approving the Consent Decree.
The Court of Appeals ordered that the appellants file their opening brief
by March 12, 1997, and that appellees file any responsive brief by
April 11, 1997. Appellants moved for an extension of time to file their
opening brief, and Appellees filed a joint motion to dismiss the appeal
for lack of prosecution. On April 29, 1997, the motion was granted, and
the appeal was dismissed.
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.
page 46
<PAGE>
Environmental Settlement
In July 1997, SCE reached a settlement with the San Bernardino County Fire
Department of alleged violations of environmental laws and regulations in
connection with the 1995 decommissioning of acid and caustic tanks at one
of its sites. The settlement calls for SCE to pay $150,000 in penalties
and $7,832 in costs, for a total payment to the San Bernardino County Fire
Department of $157,832.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
None
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
August 12, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Southern California Edison Financial Data Schedule - Exhibit 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,257,508
<OTHER-PROPERTY-AND-INVEST> 1,876,683
<TOTAL-CURRENT-ASSETS> 1,647,450
<TOTAL-DEFERRED-CHARGES> 2,519,594
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 17,301,235
<COMMON> 2,168,054
<CAPITAL-SURPLUS-PAID-IN> 225,703
<RETAINED-EARNINGS> 2,554,389
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,948,146
275,000
183,755
<LONG-TERM-DEBT-NET> 3,203,782
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 1,295,000
<COMMERCIAL-PAPER-OBLIGATIONS> 344,485
<LONG-TERM-DEBT-CURRENT-PORT> 576,470
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 6,474,597
<TOT-CAPITALIZATION-AND-LIAB> 17,301,235
<GROSS-OPERATING-REVENUE> 3,539,433
<INCOME-TAX-EXPENSE> 228,881
<OTHER-OPERATING-EXPENSES> 2,847,544
<TOTAL-OPERATING-EXPENSES> 3,076,425
<OPERATING-INCOME-LOSS> 463,008
<OTHER-INCOME-NET> 7,867
<INCOME-BEFORE-INTEREST-EXPEN> 470,875
<TOTAL-INTEREST-EXPENSE> 220,767
<NET-INCOME> 250,108
15,971
<EARNINGS-AVAILABLE-FOR-COMM> 234,137
<COMMON-STOCK-DIVIDENDS> 345,360
<TOTAL-INTEREST-ON-BONDS> 181,744
<CASH-FLOW-OPERATIONS> 978,573
<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 June 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
Los Angeles, California
August 12, 1997
