PAGE
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1997
---------------------------------------
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
---------------- -----------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 999)
Rosemead, California
(Address of principal 91770
executive offices) (Zip Code)
626-302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date:
Class Outstanding at November 6, 1997
- -------------------------- -------------------------------
Common Stock, no par value 381,446,797
PAGE
<PAGE>
EDISON INTERNATIONAL
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income--Three and
Nine Months Ended September 30, 1997 and 1996 2
Consolidated Balance Sheets--September 30, 1997,
and December 31, 1996 3
Consolidated Statements of Cash Flows--Nine Months
Ended September 30, 1997, and 1996 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 16
Part II. Other Information:
Item 1. Legal Proceedings 32
Item 6. Exhibits and Reports on Form 8-K 38
page 1
<PAGE>
EDISON INTERNATIONAL
PART I--FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended
September 30, September 30,
------------------------ --------------------------
1997 1996 1997 1996
---------- --------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C>
Electric utility revenue $2,433,526 $2,346,161 $5,972,894 $5,717,283
Diversified operations 304,255 222,023 932,797 632,300
---------- ---------- ---------- ----------
Total operating revenue 2,737,781 2,568,184 6,905,691 6,349,583
---------- ---------- ---------- ----------
Fuel 463,069 249,385 857,630 555,065
Purchased power 900,781 938,588 2,117,116 2,026,762
Provisions for regulatory adjustment
clauses -- net (185,416) (66,531) (277,439) (170,214)
Other operating expenses 438,282 333,300 1,223,453 1,082,843
Maintenance 89,883 67,461 302,885 219,185
Depreciation and decommissioning 342,422 302,276 1,024,799 865,938
Income taxes 186,116 228,356 395,732 467,555
Property and other taxes 32,338 46,943 105,329 152,528
---------- ---------- ---------- ----------
Total operating expenses 2,267,475 2,099,778 5,749,505 5,199,662
---------- ---------- ---------- ----------
Operating income 470,306 468,406 1,156,186 1,149,921
---------- ---------- ---------- ----------
Provision for rate phase-in plan (13,218) (22,021) (35,908) (69,966)
Allowance for equity funds used
during construction 1,691 3,466 5,591 10,934
Interest and dividend income 21,996 14,216 56,987 42,315
Minority interest (779) (12,812) (38,468) (40,681)
Other nonoperating income (deductions) -- net (20,419) (12,172) (30,153) (2,125)
---------- ---------- ---------- ----------
Total other income (deductions) -- net (10,729) (29,323) (41,951) (59,523)
---------- ---------- ---------- ----------
Income before interest and other expenses 459,577 439,083 1,114,235 1,090,398
---------- ---------- ---------- ----------
Interest on long-term debt 144,139 149,683 448,947 447,142
Other interest expense 34,001 22,286 90,261 67,921
Allowance for borrowed funds used
during construction (2,036) (2,179) (6,733) (6,874)
Capitalized interest (3,381) (19,407) (11,457) (53,055)
Dividends on subsidiary preferred
securities 10,063 11,881 32,593 35,626
---------- ---------- ---------- ----------
Total interest and other expenses -- net 182,786 162,264 553,611 490,760
---------- ---------- ---------- ----------
Net income $ 276,791 $ 276,819 $ 560,624 $ 599,638
========== ========== ========== ==========
Weighted-average shares of common stock
outstanding 394,076 436,476 407,133 440,135
Earnings per share $0.70 $0.63 $1.38 $1.36
Dividends declared per common share $0.25 $0.25 $0.75 $0.75
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 2
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
------------- -----------
(Unaudited)
ASSETS
Transmission and distribution utility plant,
at original cost, subject to cost-based
<S> <C> <C>
rate regulation $11,087,199 $10,973,311
Accumulated provision for depreciation (5,294,706) (5,128,652)
Construction work in progress 461,850 461,048
----------- -----------
6,254,343 6,305,707
----------- -----------
Generation utility plant, at original cost,
not subject to cost-based rate regulation 9,502,679 9,427,076
Accumulated provision for depreciation
and decommissioning (4,800,890) (4,302,419)
Construction work in progress 71,598 95,597
Nuclear fuel, at amortized cost 167,682 176,827
----------- -----------
4,941,069 5,397,081
----------- -----------
Total utility plant 11,195,412 11,702,788
----------- -----------
Nonutility property -- less
accumulated provision for
depreciation of $238,523 and $203,256
at respective dates 3,372,037 3,570,237
Nuclear decommissioning trusts 1,608,465 1,485,525
Investments in partnerships and
unconsolidated subsidiaries 1,549,553 1,371,824
Investments in leveraged leases 954,367 584,515
Other investments 124,093 103,973
----------- -----------
Total other property and investments 7,608,515 7,116,074
----------- -----------
Cash and equivalents 585,020 896,594
Receivables, including unbilled
revenue, less allowances of
$22,046 and $26,230 for uncollectible
accounts at respective dates 1,322,193 1,094,498
Fuel inventory 57,027 72,480
Materials and supplies, at average cost 148,762 154,266
Accumulated deferred income taxes -- net 191,563 240,429
Regulatory balancing accounts -- net 100,935 --
Prepayments and other current assets 160,379 113,654
----------- -----------
Total current assets 2,565,879 2,571,921
----------- -----------
Unamortized debt issuance and
reacquisition expense 353,060 346,834
Rate phase-in plan 16,220 50,703
Income tax-related deferred charges 1,581,243 1,741,091
Other deferred charges 1,089,488 1,029,203
----------- -----------
Total deferred charges 3,040,011 3,167,831
----------- -----------
Total assets $24,409,817 $24,558,614
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 3
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
------------- -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
Common shareholders' equity:
Common stock (386,952,629 and 424,524,178
<S> <C> <C>
shares outstanding at respective dates) $ 2,328,294 $ 2,547,403
Cumulative translation adjustments -- net 27,209 63,898
Unrealized gain in equity investments -- net 56,012 33,382
Retained earnings 3,351,507 3,752,549
----------- -----------
5,763,022 6,397,232
Preferred securities of subsidiaries:
Not subject to mandatory redemption 183,755 283,755
Subject to mandatory redemption 425,000 425,000
Long-term debt 7,049,436 7,474,679
----------- -----------
Total capitalization 13,421,213 14,580,666
----------- -----------
Other long-term liabilities 504,734 423,925
----------- -----------
Current portion of long-term debt 347,882 592,143
Short-term debt 1,452,964 397,098
Accounts payable 503,451 437,657
Accrued taxes 827,422 530,365
Accrued interest 113,325 131,079
Dividends payable 101,136 108,563
Regulatory balancing accounts -- net -- 181,488
Deferred unbilled revenue and other
current liabilities 1,207,811 1,059,240
----------- -----------
Total current liabilities 4,553,991 3,437,633
----------- -----------
Accumulated deferred income
taxes -- net 4,110,945 4,283,219
Accumulated deferred investment
tax credits 356,173 372,377
Customer advances and other
deferred credits 1,455,346 753,755
----------- -----------
Total deferred credits 5,922,464 5,409,351
----------- -----------
Minority interest 7,415 707,039
----------- -----------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $24,409,817 $24,558,614
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 4
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
<TABLE>
<CAPTION>
9 Months Ended
September 30,
-----------------------------
1997 1996
--------- -----------
(Unaudited)
Cash flows from operating activities:
<S> <C> <C>
Net income $ 560,624 $ 599,638
Adjustments for non-cash items:
Depreciation and decommissioning 1,024,799 865,938
Amortization 60,582 81,748
Rate phase-in plan 34,483 63,802
Deferred income taxes and investment tax
credits 4,499 (103,136)
Equity in income from partnerships and
unconsolidated subsidiaries (164,170) (131,293)
Other long-term liabilities 80,809 3,574
Other -- net (83,113) 5,470
Changes in working capital components:
Receivables (283,344) (158,844)
Regulatory balancing accounts (282,423) (131,814)
Fuel inventory, materials and supplies 20,957 35,515
Prepayments and other current liabilities (45,063) (24,435)
Accrued interest and taxes 277,924 449,377
Accounts payable and other current
liabilities 218,830 211,113
Distributions from partnerships and
unconsolidated subsidiaries 126,411 108,025
---------- ---------
Net cash provided by operating activities 1,551,805 1,874,678
---------- ---------
Cash flows from financing activities:
Long-term debt issued 1,474,873 1,285,274
Long-term debt repayments (2,011,200) (1,093,835)
Preferred securities redemptions (100,000) --
Common stock repurchased (884,686) (166,287)
Nuclear fuel financing -- net (12,628) 20,510
Short-term debt financing -- net 1,046,208 (161,966)
Dividends paid (310,354) (331,709)
Other -- net 4,708 745
---------- ---------
Net cash used by financing activities (793,079) (447,268)
---------- ---------
Cash flows from investing activities:
Additions to property and plant (514,396) (607,253)
Funding of nuclear decommissioning trusts (109,202) (110,241)
Investments in partnerships and
unconsolidated subsidiaries (219,819) (209,808)
Unrealized gain in equity investments -- net 22,630 11,246
Other -- net (249,513) 33,105
---------- ---------
Net cash used by investing activities (1,070,300) (882,951)
---------- ---------
Net increase (decrease) in cash and equivalents (311,574) 544,459
Cash and equivalents, beginning of period 896,594 507,151
---------- ---------
Cash and equivalents, end of period $ 585,020 $1,051,610
========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 5
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments have been made that are
necessary to present a fair statement of the financial position and
results of operations for the periods covered by this report.
Edison International's significant accounting policies were described in
Note 1 of "Notes to Consolidated Financial Statements" included in its
1996 Annual Report on Form 10-K filed with the Securities and Exchange
Commission. Edison International follows the same accounting policies for
interim reporting purposes. This quarterly report should be read in
conjunction with Edison International's 1996 Annual Report.
As a result of industry restructuring legislation enacted by the State of
California and a related change in the application of accounting
principles for rate-regulated enterprises adopted recently by the
Financial Accounting Standards Board's Emerging Issues Task Force (EITF),
during the third quarter of 1997 Southern California Edison Company (SCE)
began accounting for its investment in generation facilities in accordance
with generally accepted accounting principles applicable to enterprises
in general. Although this change did not result in any adjustment of the
carrying value of such investment, it is shown separately on Edison
International's Balance Sheet under the caption "Generation utility plant,
at original cost, not subject to cost-based rate regulation." The
competitive market for electric generation in California is scheduled to
begin January 1, 1998.
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on Edison International's basic earnings per share, which replaces primary
earnings per share.
Certain prior-period amounts were reclassified to conform to the September
30, 1997, financial statement presentation.
Note 1. 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 California Public
Utilities Commission's (CPUC) 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 during the 1998-2001 transition period.
page 6
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Rate Reduction Bonds - In May 1997, SCE filed an application with the CPUC
requesting approval of the issuance of an aggregate amount of up to $3
billion of rate reduction bonds in one or more series or classes and a 10%
rate reduction for the period from January 1, 1998, through March 31,
2002. At the same time, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. On September 3, 1997, the CPUC approved SCE's
request. Subject to prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and Federal Energy Regulatory
Commission (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
page 7
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PX to file more specific information. The filing was made in March 1997,
and included SCE's proposed transmission revenue requirement. On
October 29, 1997, the FERC gave conditional, interim authorization for
operation of the PX and ISO to begin on January 1, 1998. Prior to January
2, 1998, the chief executive officers of the PX, ISO and the three
utilities must certify that all the conditions are in place to ensure
reliable electric power operations. In addition, the FERC stated it would
closely monitor the PX and ISO, require further studies and make
modifications, where necessary. A comprehensive review will be performed
by the FERC after three years of operation of the PX and ISO. In July
1996, the three utilities jointly filed an application with the CPUC
requesting approval to establish a restructuring trust which would obtain
loans up to $250 million for the development of the ISO and PX through
January 1, 1998. The loans are backed by utility guarantees; SCE's share
is 45%, or $113 million. The ISO and PX will repay the trust's loans and
recover funds from future ISO and PX Customers. In August 1996, the CPUC
issued an interim order establishing the restructuring trust and the
funding level of $250 million, which will be used to build the hardware
and software systems for the ISO and PX. On October 17, 1997, the three
utilities jointly filed a petition to modify the CPUC decision that
established the restructuring trust and authorized the $250 million loan
guarantees. The petition requested an increase in the loan guarantees
from $250 million to $300 million; SCE's share of this new total would be
$135 million. The petition also requested that a one-time
restructuring implementation charge, to be paid to the PX by the
utilities, be deemed a non-bypassable charge to be recovered from all
retail customers. The amount of the PX charge is $85 million; SCE's share
is 45%, or $38 million. A CPUC decision on the petition is expected by
year-end 1997.
Direct Customer Access - In May 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997,
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
maximum demand above 20 kW (primarily industrial and large commercial) can
choose SCE or any other supplier to provide their metering service. All
page 8
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D), and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-
end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was
no longer critical to the restructuring process and asked SCE to make
a compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. SCE has proposed that the difference
between the CPUC-determined hydroelectric revenue requirement and the
market revenue from hydroelectric generation would flow through the CTC
mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all twelve of its oil- and gas-fueled
generation plants. This application builds on SCE's March 1996 plan which
outlined how SCE proposed to divest 50% of these assets. Under the new
proposal, SCE would continue to operate and maintain the divested power
plants for at least two years following their sale, as mandated by the
restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be
impacted by divestiture-related job reductions. SCE's proposal is
contingent on the overall electric industry restructuring implementation
process continuing on a satisfactory path. On September 3, 1997, the CPUC
approved SCE's proposal to auction the twelve plants. On September 5,
1997, SCE began the auction of five plants by accepting indications of
interest from potential buyers. On October 3, 1997, SCE accepted
indications of interest from potential buyers on the other seven plants.
On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for
the divestiture of SCE's twelve generation plants, which finds there will
page 9
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be no significant environmental impact resulting from the sale of the
plants. The CPUC is expected to certify the Declaration when it approves
the divestiture of the plants. SCE plans to conclude both auctions and
receive CPUC approval of the divestiture by year-end 1997. Any
differences between the net book value and the market value of the oil-
and gas-fueled generation plants is expected to be recovered through a
non-bypassable CTC.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value) assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value) assuming
the fossil plants have no market value. These estimates are based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of prior legislative and regulatory mandates; and $5.6 billion to
$6.3 billion from costs pertaining to certain generating plants and
regulatory commitments consisting of costs incurred (whose recovery has
been deferred by the CPUC) to provide service to customers. Such
commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Nuclear Generating Station Units 2 and 3 and the
Palo Verde Nuclear Generating Station units, and certain other costs. In
February 1997, SCE filed an update to the CTC filing to reflect
approval by the CPUC of settlements regarding ratemaking for SCE's share
of Palo Verde and the buyout of a power purchase agreement, as well as
other minor data updates. No substantive changes in the total CTC
estimates were included. This issue has been separated into two phases:
Phase 1 captures the rate-making issues and Phase 2 the quantification
issues. Hearings on Phase 1 were held in December 1996 and a decision was
issued in June 1997, which, among other things, required the establishment
of a transition cost balancing account and annual transition cost
proceedings, set a market rate forecast for 1998 transition costs, and
required that generation-related regulatory assets be amortized ratably
over a 48-month period. Hearings on Phase 2 were held in May and June
1997. On October 20, 1997, a proposed decision was issued by the
administrative law judge. Among other things, the proposed decision would
reduce SCE's authorized rate of return on certain assets eligible for
transition cost recovery (primarily fossil generation-related assets)
beginning July 1997. The proposed decision, if adopted, and excluding the
effects of other rate actions, will have a negative impact on 1997
earnings of approximately 3 cents per share. A final decision on Phase 2 is
expected in the fourth quarter of 1997.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be
subject to a lower authorized rate of return).
page 10
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the EITF during April 1997 and a final consensus
was reached at the July EITF meeting. During the third quarter of 1997,
SCE implemented the EITF consensus and discontinued application of
accounting principles for rate-regulated enterprises for its investment
in generation facilities.
However, SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $900 million
at September 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
rate phase-in plan. The consensus reached by the EITF also permits the
recording of new generation-related regulatory assets during the
transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the
recovery of these generation-related regulatory assets no longer probable,
SCE would be required to write off the remaining balance of such assets
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
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
page 11
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
Note 2. Contingencies
In addition to the matters disclosed in these notes, Edison International
is involved in legal, tax and regulatory proceedings before various courts
and governmental agencies regarding matters arising in the ordinary course
of business. Edison International believes the outcome of these
proceedings will not materially affect its results of operations or
liquidity.
Brooklyn Navy Yard Project
Edison Mission Energy (EME), a subsidiary of Edison International, owns,
through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard project.
The subsidiary funded all of the required equity during construction and
will be required to fund all remaining costs of the project facility until
the close of non-recourse financing. The estimated total cost is $492
million, of which $457 million has been spent through September 30, 1997.
In December 1995, a $254 million tax-exempt bond financing for the project
was obtained through the New York City Industrial Development Agency
(NYCIDA). EME has guaranteed the obligations of the project pursuant to
the financing and indemnified NYCIDA for environmental liability up to
$40 million.
page 12
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In February 1997, the contractor asserted general monetary claims under
the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. (BNY) for damages in the amount of $137 million against BNY. In
addition to defending this action, BNY has filed an action against the
contractor in New York State Court asserting general monetary claims in
excess of $13 million arising out of the turnkey agreement. EME believes
that the outcome of this litigation will not materially affect its results
of operations or financial position.
Environmental Protection
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site using currently available
information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level
of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure.
Unless there is a probable amount, Edison International records the lower
end of this reasonably likely range of costs (classified as other long-
term liabilities at undiscounted amounts). While Edison International
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.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached an agreement with the California Coastal Commission
in 1991 to restore certain marine mitigation sites. The restorations
include two sites: designated wetlands and the construction of an
artificial kelp reef off the California coast. After SCE requested
certain modifications to the agreement, the Coastal Commission issued a
final ruling in April 1997 to reduce the scope of remediation required at
these two sites. SCE elected to pay for the costs of marine mitigation
in lieu of placing the funds into a trust. Rate recovery of these costs
is occurring through the San Onofre incentive pricing plan.
Edison International's recorded estimated minimum liability to remediate
its 53 identified sites (52 at SCE and 1 at EME) is $185 million, which
includes $75 million for the two sites discussed above. The ultimate
costs to clean up Edison International's identified sites may vary from
its recorded liability due to numerous uncertainties inherent in the
estimation process, such as: the extent and nature of contamination; the
scarcity of reliable data for identified sites; the varying costs of
alternative cleanup methods; developments resulting from investigatory
studies; the possibility of identifying additional sites; and the time
periods over which site remediation is expected to occur. Edison
International believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to
$246 million. The upper limit of this range of costs was estimated using
assumptions least favorable to Edison International among a range of
reasonably possible outcomes.
page 13
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $97 million of Edison International's recorded
liability, through an incentive mechanism (SCE may request to include
additional sites). Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with
the opportunity to recover these costs from insurance carriers and other
third parties. SCE has successfully settled insurance claims with all
responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $159 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates. This
amount includes $60 million of marine mitigation costs remaining to be
recovered through the San Onofre incentive pricing plan.
Edison International's identified sites include several sites for which
there is a lack of currently available information, including the nature
and magnitude of contamination, and the extent, if any, that Edison
International may be held responsible for contributing to any costs
incurred for remediating these sites. Thus, no reasonable estimate of
cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a
period of up to 30 years. Remediation costs in each of the next several
years are expected to range from $4 million to $10 million.
Based on currently available information, Edison International believes
it is unlikely that it will incur amounts in excess of the upper limit of
the estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs
ultimately recorded will not materially affect its results of operations
or financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $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
page 14
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
has also been purchased in amounts greater than federal requirements.
Additional insurance covers part of replacement power expenses during an
accident-related nuclear unit outage. These policies are issued primarily
by mutual insurance companies owned by utilities with nuclear facilities.
If losses at any nuclear facility covered by the arrangement were to
exceed the accumulated funds for these insurance programs, SCE could be
assessed retrospective premium adjustments of up to $32 million per year.
Insurance premiums are charged to operating expense.
page 15
<PAGE>
EDISON INTERNATIONAL
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
Edison International's earnings per share for the three and nine months
ended September 30, 1997, were 70 cents and $1.38, respectively, compared
with 63 cents and $1.36 for the same periods in 1996. Southern California
Edison Company's (SCE) earnings were 57 cents and $1.13 for the quarter
and year-to-date periods ended September 30, 1997, compared to 56 cents
and $1.15 for the year-earlier periods. SCE made one-time adjustments
(after-tax) for workforce management costs of 7 cents (charge) in
second quarter 1996 and 4 cents (benefit) in third quarter 1996. Excluding
these special items, Edison International's earnings for the three and nine
months ended September 30, 1997, increased 11 cents and decreased 1 cent,
respectively, compared to the same periods in 1996. The quarterly increase
in earnings per share reflects an increase in electricity sales, higher
earnings at the nonutility subsidiaries, the impact of Edison Mission Energy
Company's (EME) lower effective tax rate, and the effects of the ongoing
share repurchase program. The year-to-date decrease is primarily due
to the refueling outages at SCE's San Onofre Nuclear Generating Station
(see discussion in Regulatory Matters) and the new rate-making treatment for
the Palo Verde Nuclear Generating Station. These decreases were partially
offset by income from Edison Capital's new cross-border leases, EME's
effective tax rate change, as well as the ongoing share repurchase program.
Operating Revenue
Electric utility revenue increased slightly for the three and nine months
ended September 30, 1997, compared with the same periods in 1996. The
quarterly increase is primarily due to an increase in non-residential
retail rates, partially offset by a decrease in resale sales volume. The
year-to-date increase is due to a 3% increase in sales volume from
commercial and agricultural customers (due to an improving Southern
California economy), as well as a slight increase in resale rates. Over
98% of operating revenue is from retail sales. Retail rates are regulated
by the California Public Utilities Commission (CPUC) and wholesale rates
are regulated by the Federal Energy Regulatory Commission (FERC).
In March 1995, SCE announced a five-year goal to reduce system average
rates by 25% on an inflation-adjusted basis (from 10.7 cents per kilowatt-hour
to below 10 cents per kilowatt-hour). In February 1996, the CPUC approved a
system-wide rate reduction which lowered the average price per kilowatt-
hour from 10.7 cents to 10.1 cents, effective June 1996. Legislation enacted
in September 1996 provides for, among other things, at least a 10% rate
page 16
<PAGE>
reduction (financed through the issuance of rate reduction bonds) for
residential and small commercial customers beginning in 1998 (see
discussion in Competitive Environment).
Revenue from diversified operations increased 37% and 48%, respectively,
for the three and nine months ended September 30, 1997, primarily due to
the start-up of EME's Loy Yang B Unit 2 and Kwinana projects. The Loy
Yang B Unit 2 and Kwinana projects began commercial operations during the
fourth quarter of 1996. In addition, revenue from diversified operations
increased due to additional revenue from Edison Capital's May 1997 $360
million investment in cross-border leases in the Netherlands and in South
Australia.
Operating Expenses
Fuel expense increased 86% and 55% for the three and nine months ended
September 30, 1997, respectively. The increases are primarily due to a
$174 million gas contract termination payment during the third quarter,
combined with higher gas prices and the extended refueling outages at San
Onofre. San Onofre Unit 2 was shut down during the entire first quarter
of 1997, Unit 3 was shut down 80 days of the second quarter, and both
units had a combined outage of 30 days during the third quarter of 1997,
resulting in an overall increase in gas-powered generation for both
periods presented. There were no comparable outages for the same periods
in 1996. Fuel expense also increased at EME due to the start-up of Loy
Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996 and
higher fuel costs at the First Hydro project due to increased generation
and higher prices.
Purchased-power expense decreased 4% during the quarter, as cost increases
in spot market purchases were more than offset by decreases in federally
mandated contract payments. For the nine months ended September 30, 1997,
purchased-power expense increased 5% due to increased power purchases in
the open market and increases in power purchased under federally-mandated
contracts. SCE is required under federal law to purchase all power
delivered by certain nonutility generators (up to a project's rated
capacity) even though energy prices under these contracts are generally
higher than other sources. For the twelve months ended September 30,
1997, SCE paid about $1.6 billion (including energy and capacity payments)
more for these power purchases than the cost of power available from other
sources. The CPUC has mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially for
both periods presented compared with the year-earlier periods. The
quarterly decrease is primarily due to undercollections in the energy cost
balancing account resulting from gas contract termination payments made
in third quarter 1997, as well as a lesser amount of actual base-rate
revenue from kilowatt-hour sales exceeding CPUC-authorized estimates.
These quarterly undercollections were partially offset by a net
overcollection resulting from the San Onofre units operating at a lower
capacity in third quarter 1997 (30 days of refueling and inspection
outages) compared to third quarter 1996 when the San Onofre units operated
at a higher capacity than estimated. Another offset to the quarterly
decrease is an overcollection due to the accelerated recovery of SCE's
remaining investment at San Onofre. The year-to-date decrease is mainly
due to an undercollection related to the gas contract termination payments
made in 1997 and actual energy costs exceeding CPUC-authorized fuel and
purchased-power cost estimates. This undercollection was partially offset
by overcollections related to: actual base-rate revenue from kilowatt-
hour sales exceeding CPUC-authorized estimates; the effects of the San
Onofre refueling outages in 1997 and the acceleration of SCE's remaining
investment at San Onofre.
page 17
<PAGE>
Other operating expenses increased 32% and 13%, respectively, for the
three and nine months ended September 30, 1997, compared with the year-
earlier periods. The quarterly increase is due to increased operating
costs at San Onofre for inspections associated with the earlier Unit 2 and
3 outages, along with increased expenses associated with meter reading,
customer records and interim direct access activities. Also contributing
to the increases were higher administrative costs at Edison Enterprises
and EME. The year-to-date increase is primarily due to the same quarterly
reasons at EME and Edison Enterprises, as well as higher costs associated
with the sale of property at Mission Land in 1997. For the year-to-date
period, SCE's quarterly increase was more than offset by reductions in
pension-related expenses associated with the voluntary retirement programs
in 1996.
Maintenance expense increased substantially in both periods presented
compared with the year-earlier periods, due to increased maintenance costs
for SCE's electric plant assets and scheduled refueling outages at the San
Onofre units.
Depreciation and decommissioning expense increased 13% and 18%,
respectively, for the quarter and year-to-date ended September 30, 1997,
due to increases in plant assets and the accelerated recovery of the Palo
Verde Nuclear Generating Station units effective January 1997. The start-
up of Loy Yang B Unit 2 and the Kwinana project, which began commercial
operations in the fourth quarter of 1996, also contributed to increases
at EME.
Income taxes decreased 19% and 15%, respectively, for the three and nine
months ended September 30, 1997, compared to the year-earlier periods, due
to a decrease in pre-tax income.
Property and other taxes decreased 31% for both the three and nine months
ended September 30, 1997, compared to the same periods in 1996, due to
SCE's reclassification of payroll taxes to operation and maintenance
expense in 1997.
Other Income and Deductions
The provision for rate phase-in plan reflects a CPUC-authorized, 10-year
rate phase-in plan, which deferred the collection of revenue during the
first four years of operation for the Palo Verde units. The deferred
revenue (including interest) is being collected evenly over the final six
years of each unit's plan. The plan ended in February 1996 and September
1996 for Units 1 and 2, respectively. The plan ends in January 1998 for
Unit 3. The provision is a non-cash offset to the collection of deferred
revenue.
Interest and dividend income increased 55% and 35%, respectively, for the
three and nine months ended September 30, 1997, compared to the year-
earlier periods, primarily due to EME's higher international cash
balances.
Minority interest decreased for both periods presented, primarily due to
the May 1997 acquisition of the remaining 49% ownership interest in EME's
Loy Yang B project.
Other nonoperating income decreased for both periods presented, primarily
due to additional accruals for regulatory matters and increased costs
resulting from the effect of a rise in Edison International's stock price
on SCE's stock option plan.
Interest and Other Expenses
Other interest expense increased 53% and 33% for the three and nine months
ended September 30, 1997, respectively, compared to the same periods in
1996, due to higher levels of short-term debt at SCE used to retire first
page 18
<PAGE>
and refunding mortgage bonds during the third quarter of 1997. EME also
had increased interest expense from the net effect of $450 million of
securities issued by Edison Mission Energy Funding Corporation in December
1996 and the December 1996 repayment of a 200 million Australian dollar
loan.
Capitalized interest decreased for both periods presented, primarily due
to the completion of construction of Loy Yang B Unit 2 and other projects
in the fourth quarter of 1996.
FINANCIAL CONDITION
Edison International's liquidity is primarily affected by debt maturities,
dividend payments, capital expenditures and investments in partnerships
and unconsolidated subsidiaries. Capital resources include cash from
operations and external financings.
Edison International's Board of Directors has authorized the repurchase
of up to $2.3 billion of its outstanding shares of common stock. Edison
International has repurchased 68.4 million shares ($1.5 billion) between
January 1995 and November 4, 1997, funded by dividends from its
subsidiaries and its lines of credit.
For the nine months ended September 30, 1997, Edison International's cash
flow coverage of dividends decreased to 5.0 times from 5.7 times for the
same period in 1996, as a result of the ongoing share repurchase program
and the repayment of SCE's long-term debt. Edison International's
dividend payout ratio for the twelve-month period ended September 30,
1997, was 61%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.6 billion for the
nine-month period ended September 30, 1997, compared with $1.9 billion in
1996. Cash from operations exceeded capital requirements for both periods
presented.
Cash Flows from Financing Activities
At September 30, 1997, Edison International and its subsidiaries had $1.9
billion of borrowing capacity available under lines of credit totaling
$3.6 billion. SCE had $1.8 billion of borrowing capacity under lines of
credit, with $900 million available ($400 million for general purpose,
short-term debt and $500 million for the long-term refinancing of its
variable-rate pollution-control bonds). The parent company had a $1.0
billion line of credit with $315 million of borrowing capacity available.
The nonutility companies had available lines of credit of $800 million,
with $716 million of borrowing capacity available to finance general cash
requirements. Edison International's unsecured lines of credit are at
negotiated or bank index rates with various expiration dates; the majority
have five-year terms.
SCE's short-term debt is used to finance fuel inventories, balancing
account undercollections and general cash requirements. EME uses short-
term debt and available credit lines mainly for construction projects
until long-term construction or project loans are secured. Long-term debt
is used mainly to finance capital expenditures. SCE's external financings
are influenced by market conditions and other factors, including
limitations imposed by its articles of incorporation and trust indenture.
As of September 30, 1997, SCE could issue approximately $9.5 billion of
additional first and refunding mortgage bonds and $5.2 billion of
preferred stock at current interest and dividend rates.
page 19
<PAGE>
EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard
project. The subsidiary funded all of the required equity during
construction and will be required to fund the remaining costs of the
project facility until the close of nonrecourse financing. The estimated
total cost is $492 million, of which $457 million had been spent through
September 30, 1997. In December 1995, a $254 million tax-exempt bond
financing for the project was obtained through the New York City
Industrial Development Agency (NYCIDA). EME has guaranteed the
obligations of the project pursuant to the financing and indemnified
NYCIDA for environmental liability up to $40 million.
In February 1997, the contractor asserted general monetary claims under
the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. (BNY) for damages in the amount of $137 million against BNY. In
addition to defending this action, BNY has filed an action against the
contractor in New York State Court asserting general monetary claims in
excess of $13 million arising out of the turnkey agreement. EME believes
that the outcome of this litigation will not materially affect its results
of operations or financial position.
In April 1997, EME completed financing and commenced construction of the
Doga project, a 180 megawatt gas-powered power plant near Istanbul,
Turkey. A wholly owned subsidiary of EME will own 80% of this project.
In connection with the financing, EME has guaranteed $25 million in equity
contributions and will continue making equity contributions until
commercial operation begins, which is scheduled for late 1998.
In May 1997, Edison Capital closed its largest infrastructure transaction
in recent years by entering into a cross-border lease transaction in the
Eems Power Station located in the Netherlands. This transaction is valued
at $200 million. The Eems power station is a new, five unit (335 MW each)
gas fired, combined cycle power plant. It is operated by EPON, the
largest power generating company in the Netherlands. Edison Capital also
acquired an interest in the electric power transmission system in South
Australia. This cross-border lease transaction is valued at $160 million.
EME has firm commitments of $320 million to make equity and other
contributions, primarily for the Paiton project in Indonesia, the ISAB
project in Italy, and the Doga project in Turkey. EME also has contingent
obligations to make additional contributions of $479 million, primarily
for a guarantee to secure payment of the bonds issued pursuant to the $254
million tax-exempt financing for the Brooklyn Navy Yard project and equity
support guarantees related to Paiton.
EME may incur additional obligations to make equity and other
contributions to projects in the future. EME believes it will have
sufficient liquidity to meet these equity requirements from cash provided
by operating activities, proceeds from the repayment of loans to energy
projects, funds available from EME's revolving line of credit and
additional corporate borrowings.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital
structure, limiting the dividends it may pay Edison International. At
September 30, 1997, SCE had the capacity to pay $1.7 billion in additional
dividends and continue to maintain its authorized capital structure.
These restrictions are not expected to affect Edison International's
ability to meet its cash obligations.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant, the nonutilities' investments in partnerships and
unconsolidated subsidiaries, and funding of nuclear decommissioning
page 20
<PAGE>
trusts. 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).
Cash used for the nonutility subsidiaries' investing activities was $501
million for the nine-month period ended September 30, 1997, compared with
$240 million for the same period in 1996.
Edison International's risk management policy allows the use of derivative
financial instruments to mitigate risk. Changes in interest rates,
electricity pool pricing in the United Kingdom and Australia and
fluctuations in foreign currency exchange rates can have a significant
impact on EME's results of operations. EME has mitigated the risk of
interest rate fluctuations by arranging for fixed rate or variable rate
financing with interest rate swaps or other hedging mechanisms for the
majority of its project financings. As a result of interest rate hedging
mechanisms, interest expense included $9 million and $6 million,
respectively, for the nine months ended September 30, 1997, and 1996.
The maturity dates of several of EME's interest rate swap agreements do
not correspond to the term of the underlying debt. EME does not believe
that interest rate fluctuations will have a material adverse effect on its
results of operations or financial position.
Projects in the United Kingdom sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly
clearing price for electrical energy. The pool price is extremely
volatile, and can vary by a factor of ten or more over the course of a few
hours due to large differentials in demand according to the time of day.
First Hydro mitigates a portion of the market risk of the pool by entering
into contracts for differences (electricity rate swap agreements), related
to either the selling or purchase price of power, whereby a contract
specifies a price at which the electricity will be traded, and the parties
to the agreements make payments, calculated based on the difference
between the price in the contract and the half hourly clearing price for
the element of power under contract. These contracts act as a means of
stabilizing production revenue or purchasing costs by removing an element
of First Hydro's net exposure to pool price volatility. First Hydro's
electric revenue increased by $27 million for the nine months ended
September 30, 1997, compared to a decrease of $4 million in the
corresponding period of the prior year, as a result of electricity rate
swap agreements.
Loy Yang B sells their electrical energy through a centralized electricity
pool (Victorian Wholesale Electricity Market which will be integrated into
the National Electricity Market), which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing
market for each half-hour of every day. The Victorian Power Exchange,
operator and administrator of the pool, determines a system marginal price
each half-hour. To mitigate the exposure to price volatility of the
electricity traded in the pool, Loy Yang B has entered into a number of
financial hedges. From May 8, 1997, to December 31, 2000, approximately
53% to 64% of the plant output sold is hedged under vesting contracts with
the remainder of the plant capacity hedged under the state hedge. Vesting
contracts were put into place by the State, between each generator and
each distributor, prior to the privatization of electric power
distributors in order to provide more predictable pricing for those
electricity customers that were unable to choose their electricity
retailer. Vesting contracts set base strike prices at which the
electricity will be traded, and the parties to the agreement make
payments, calculated based on the difference between the price in the
page 21
<PAGE>
contract and the half-hourly pool clearing price for the element of power
under contract. These contracts can be sold as one-way or two-way
contracts which are structured similar to the electricity rate swap
agreements described above. The state hedge is a long-term contractual
arrangement based upon a fixed price commencing May 8, 1997, and
terminating October 31, 2016. The State guarantees the State Electricity
Commission of Victoria's obligations under the state hedge. Loy Yang B's
electric revenue was increased by $43 million for the nine-month period
ended September 30, 1997, as a result of hedging contract arrangements.
As EME continues to expand into foreign markets, fluctuations in foreign
currency exchange rates can affect the amount of its equity contributions
to, distributions from, and results of operations of its foreign projects.
At times, EME has hedged a portion of its current exposure to fluctuations
in foreign exchange rates where it deems appropriate through financial
derivatives, offsetting obligations denominated in foreign currencies, and
indexing underlying project agreements to U.S. dollars or other indices
reasonably expected to correlate with foreign exchange movements. Various
statistical forecasting techniques are used to help assess foreign
exchange risk and the probabilities of various outcomes. There can be no
assurance, however, that fluctuations in exchange rates will be fully
offset by hedges or that currency movements and the relationship between
certain macro economic variables will behave in a manner that is
consistent with historical or forecasted relationships.
Projected Capital Requirements
Edison International's projected capital requirements for the next five
years are: 1997--$856 million; 1998--$1.0 billion; 1999--$807 million;
2000--$763 million; and 2001--$721 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1997, are: 1998--$341
million; 1999--$587 million; 2000--$547 million; 2001--$544 million; and
2002--$212 million.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1997, are: 1998 through 2001--zero and 2002--$105
million.
REGULATORY MATTERS
SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to
legislation enacted in September 1996 which requires that rates remain
frozen at the June 10, 1996, level (system average of 10.1 cent per kilowatt-
hour). See further discussion in Competitive Environment.
The CPUC's 1997 cost-of-capital decision authorized SCE's common equity
ratio to remain at 48%. SCE's return on common equity also remains at
11.6%. SCE's return on rate base was lowered from 9.55% to 9.49%. This
decision, excluding the effects of other rate actions, will have a
negative impact on 1997 earnings of approximately 1 cent per share. On
October 20, 1997, a proposed decision was issued by a CPUC administrative
law judge in Phase 2 of the competition transition charge (CTC)
proceeding. Among other things, the proposed decision would reduce SCE's
authorized rate of return on certain assets eligible for transition cost
recovery (primarily fossil generation-related assets) beginning July 1997.
The proposed decision, if adopted, and excluding the effects of other rate
actions, will have a negative impact on 1997 earnings of approximately
3 cents per share.
The CPUC has authorized revised rate-making plans for SCE's nuclear
facilities, which call for the accelerated recovery of its nuclear
investments in exchange for a lower authorized rate of return. SCE's
nuclear assets are now earning an annual rate of return of 7.35%, compared
to an authorized rate of 9.49% in 1997 for other assets. In addition, the
page 22
<PAGE>
San Onofre plan authorizes a fixed rate of approximately 4 cent per kilowatt-
hour generated for incremental operating costs, including incremental
capital costs, and nuclear fuel and nuclear fuel financing costs. The San
Onofre plan commenced in April 1996, and ends in December 2001 for the
accelerated recovery portion and in December 2003 for the incremental
pricing portion. Palo Verde's incremental operating costs, including
incremental capital costs, and nuclear fuel and nuclear fuel financing
costs, are subject to balancing account treatment. The Palo Verde plan
commenced in January 1997 and ends in December 2001.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994 record
periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowance's 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 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
page 23
<PAGE>
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses.
Rate Reduction Bonds - In May 1997, SCE filed an application with the CPUC
requesting approval of the issuance of an aggregate amount of up to $3
billion of rate reduction bonds in one or more series or classes and a 10%
rate reduction for the period from January 1, 1998, through March 31,
2002. At the same time, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. On September 3, 1997, the CPUC approved SCE's
request. Subject to prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and FERC directives) for the
functional unbundling of its rates for electric service, beginning January
1, 1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates into separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The transmission component of this rate
unbundling process is being addressed at the FERC through a March 1997
filing. (See PX and ISO discussion below.) Hearings on SCE's rate
unbundling (also known as rate-setting) plan were concluded in April 1997.
On August 1, 1997, the CPUC issued a decision which adopted the
methodology for determining CTC residually (see CTC discussion below) and
adopted SCE's revenue requirement components for public benefit programs
and nuclear decommissioning. The decision also adjusted SCE's proposed
distribution revenue requirement by reallocating $76 million of it
annually to other functions such as generation and transmission. Under
the decision, SCE will be able to recover most of the annual $76 million
through market revenue, the CTC mechanism after petitioning the CPUC to
modify its prior decisions, or another review process later in the
transition period.
PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San
Diego Gas & Electric Company filed a proposal with the FERC regarding the
creation of the PX and the ISO. In November 1996, the FERC conditionally
accepted the proposal and directed the three utilities, the ISO, and the
PX to file more specific information. The filing was made in March 1997,
and included SCE's proposed transmission revenue requirement. On
October 29, 1997, the FERC gave conditional, interim authorization for
operation of the PX and ISO to begin on January 1, 1998. Prior to January
2, 1998, the chief executive officers of the PX, ISO and the three
utilities must certify that all the conditions are in place to ensure
reliable electric power operations. In addition, the FERC stated it would
closely monitor the PX and ISO, require further studies and make
modifications, where necessary. A comprehensive review will be performed
page 24
<PAGE>
by the FERC after three years of operation of the PX and ISO. In July
1996, the three utilities jointly filed an application with the CPUC
requesting approval to establish a restructuring trust which would obtain
loans up to $250 million for the development of the ISO and PX through
January 1, 1998. The loans are backed by utility guarantees; SCE's share
is 45%, or $113 million. The ISO and PX will repay the trust's loans and
recover funds from future ISO and PX customers. In August 1996, the CPUC
issued an interim order establishing the restructuring trust and the
funding level of $250 million, which will be used to build the hardware
and software systems for the ISO and PX. On October 17, 1997, the three
utilities jointly filed a petition to modify the CPUC decision that
established the restructuring trust and authorized the $250 million loan
guarantees. The petition requested an increase in the loan guarantees
from $250 million to $300 million; SCE's share of this new total would be
$135 million. The petition also requested that a one-time restructuring
implementation charge, to be paid to the PX by the utilities, be deemed
a non-bypassable charge to be recovered from all retail customers. The
amount of the PX charge is $85 million; SCE's share is 45%, or $38
million. A CPUC decision on the petition is expected by year-end 1997.
Direct Customer Access - In May 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
maximum demand above 20 kW (primarily industrial and large commercial) can
choose SCE or any other supplier to provide their metering service. All
other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D) and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
page 25
<PAGE>
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-
end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was
no longer critical to the restructuring process and asked SCE to make a
compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. SCE has proposed that the difference
between the CPUC-determined hydroelectric revenue requirement and the
market revenue from hydroelectric generation would flow through the CTC
mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all twelve of its oil- and gas-fueled
generation plants. This application builds on SCE's March 1996 plan which
outlined how SCE proposed to divest 50% of these assets. Under the new
proposal, SCE would continue to operate and maintain the divested power
plants for at least two years following their sale, as mandated by the
restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be
impacted by divestiture-related job reductions. SCE's proposal is
contingent on the overall electric industry restructuring implementation
process continuing on a satisfactory path. On September 3, 1997, the CPUC
approved SCE's proposal to auction the twelve plants. On September 5,
1997, SCE began the auction of five plants by accepting indications of
interest from potential buyers. On October 3, 1997, SCE accepted
indications of interest from potential buyers on the other seven plants.
On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for
the divestiture of SCE's twelve generation plants, which finds there will
be no significant environmental impact resulting from the sale of the
plants. The CPUC is expected to certify the Declaration when it approves
the divestiture of the plants. SCE plans to conclude both auctions and
receive CPUC approval of the divestiture by year-end 1997. Any
differences between the net book value and the market value of the oil-
and gas-fueled generation plants is expected to be recovered through a
non-bypassable CTC.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
page 26
<PAGE>
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value) assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value) assuming
the fossil plants have no market value. These estimates are based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of prior legislative and regulatory mandates; and $5.6 billion to
$6.3 billion from costs pertaining to certain generating plants and
regulatory commitments consisting of costs incurred (whose recovery has
been deferred by the CPUC) to provide service to customers. Such
commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Nuclear Generating Station Units 2 and 3 and the
Palo Verde Nuclear Generating Station units, and certain other costs. In
February 1997, SCE filed an update to the CTC filing to reflect approval
by the CPUC of settlements regarding ratemaking for SCE's share of Palo
Verde and the buyout of a power purchase agreement, as well as other minor
data updates. No substantive changes in the total CTC estimates were
included. This issue has been separated into two phases: Phase 1
captures the rate-making issues and Phase 2 the quantification issues.
Hearings on Phase 1 were held in December 1996 and a decision was issued
in June 1997, which, among other things, required the establishment of a
transition cost balancing account and annual transition cost proceedings,
set a market rate forecast for 1998 transition costs, and required that
generation-related regulatory assets be amortized ratably over a 48-month
period. Hearings on Phase 2 were held in May and June 1997. On
October 20, 1997, a proposed decision was issued by the administrative law
judge. Among other things, the proposed decision would reduce SCE's
authorized rate of return on certain assets eligible for transition cost
recovery (primarily fossil generation-related assets) beginning July 1997.
The proposed decision, if adopted, and excluding the effects of other rate
actions, will have a negative impact on 1997 earnings of approximately 3 cent
per share. A final decision on Phase 2 is expected in the fourth quarter
of 1997.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be
subject to a lower authorized rate of return).
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting. During the third quarter of 1997,
SCE implemented the EITF consensus and discontinued application of
accounting principles for rate-regulated enterprises for its investment
in generation facilities.
However, SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $900 million
at September 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed-through to customers,
page 27
<PAGE>
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
rate phase-in plan. The consensus reached by the EITF also permits the
recording of new generation-related regulatory assets during the
transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the
recovery of these generation-related regulatory assets no longer probable,
SCE would be required to write off the remaining balance of such assets
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
opportunity to recover stranded costs associated with existing wholesale
customers, retail-turned-wholesale customers and retail wheeling when the
state regulatory body does not have authority to address retail stranded
costs. Even though the CPUC is currently addressing stranded cost
recovery through the CTC proceedings, the FERC has also asserted primary
jurisdiction over the recovery of stranded costs associated with retail-
turned-wholesale customers, such as a new municipal electric system or a
municipal annexation. However, the FERC did clarify that it does not
intend to prevent or interfere with a state's authority and that it has
discretion to defer to a state stranded-cost-calculation method. In
January 1997, the FERC accepted the open access transmission tariff SCE
filed in compliance with the April 1996 decision. The rates included in
the tariff are being collected subject to refund. In May 1997, SCE filed
a revised open access tariff to reflect the few revisions set forth in the
March 1997 order.
ENVIRONMENTAL PROTECTION
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
As further discussed in Note 2 of the Consolidated Financial Statements,
Edison International records its environmental liabilities when site
page 28
<PAGE>
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site. Unless there is a
probable amount, Edison International records the lower end of this range
of costs.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached agreement with the California Coastal Commission in
1991 to restore certain marine mitigation sites. The restorations include
two sites: designated wetlands and the construction of an artificial kelp
reef off the California coast. After SCE requested certain modifications
to the agreement, the Coastal Commission issued a final ruling in April
1997 to reduce the scope of remediation required at these two sites. SCE
elected to pay for the costs of marine mitigation in lieu of placing the
funds into a trust. Rate recovery of these costs is occurring through the
San Onofre incentive pricing plan.
Edison International's recorded estimated minimum liability to
remediate its 53 identified sites is $185 million, which includes $75
million for the two sites discussed above. One of SCE's sites, a former
pole-treating facility, is considered a federal Superfund site and
represents 43% of Edison International's recorded liability. The ultimate
costs to clean up Edison International's identified sites may vary from
its recorded liability due to numerous uncertainties inherent in the
estimation process. Edison International believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed
its recorded liability by up to $246 million. The upper limit of this
range of costs was estimated using assumptions least favorable to Edison
International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $97 million of Edison International's recorded
liability, through an incentive mechanism. Under this mechanism, SCE will
recover 90% of cleanup costs through customer rates; shareholders fund the
remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance
claims with all responsible carriers. Costs incurred at SCE's remaining
sites are expected to be recovered through customer rates. SCE has
recorded a regulatory asset of $159 million for its estimated minimum
environmental-cleanup costs expected to be recovered through customer
rates. This amount includes $60 million of marine mitigation costs
remaining to be recovered through the San Onofre incentive pricing plan.
Edison International's identified sites include several sites for which
there is a lack of currently available information, including the nature
and magnitude of contamination, and the extent, if any, that Edison
International may be held responsible for contributing to any costs
incurred for remediating these sites. Thus, no reasonable estimate of
cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a
period of up to 30 years. Remediation costs in each of the next several
years are expected to range from $4 million to $10 million.
Based on currently available information, Edison International believes
it is unlikely that it will incur amounts in excess of the upper limit of
the estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs
ultimately recorded will not materially affect its results of operations
or financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
page 29
<PAGE>
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.
Edison International's projected capital expenditures to protect the
environment are $831 million for the 1997-2001 period, mainly for
aesthetics treatment, including undergrounding certain transmission and
distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
scientific research. After many years of research, scientists have not
found that exposure to EMF causes disease in humans. Research on this
topic is continuing. However, the CPUC has issued a decision which
provides for a rate-recoverable research and public education program
conducted by California electric utilities, and authorizes these utilities
to take no-cost or low-cost steps to reduce EMF in new electric
facilities. SCE is unable to predict when or if the scientific community
will be able to reach a consensus on any health effects of EMF, or the
effect that such a consensus, if reached, could have on future electric
operations.
PALO VERDE STEAM TUBE RUPTURE
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in Unit 2 will have to be replaced within five to ten years.
SCE supports the purchase of spare steam generators that could be used,
if needed, in any of the Palo Verde units. SCE estimates its share of the
steam generator replacement costs to be between $16 million and $30
million, plus replacement power costs.
SAN ONOFRE STEAM GENERATOR TUBES
The San Onofre Units 2 and 3 steam generators have performed relatively
well through the first 15 years of operation, with low rates of ongoing
steam generator tube degradation. However, during the Unit 2 scheduled
refueling and inspection outage, which was completed in Spring 1997, an
increased rate of tube degradation was identified, resulting in removing
1.8% of the tubes from service. The cumulative total of Unit 2's tubes
removed from service is now 5.5%, well below the maximum 10% allowed in
the steam generator design before the rating capacity of the unit must be
reduced. As a result of the increased degradation, a mid-cycle inspection
outage will be conducted in 1998 for Unit 2.
During Unit 3's refueling outage, which was completed in July 1997,
inspections of structural supports for steam generator tubes identified
several areas where the thickness of the supports had been reduced,
apparently by erosion during normal plant operation. As a result, a mid-
cycle inspection outage is planned for 1998. However, during Unit 2's
Spring 1997 inspection outage, similar tube supports showed no signs of
such erosion.
page 30
<PAGE>
NEW EARNINGS PER SHARE STANDARD
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on Edison International's basic earnings per share, which replaces primary
earnings per share.
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.
The nonutility subsidiaries are currently reviewing what impact the
exposure draft may have on their results of operations and financial
position.
page 31
<PAGE>
PART II--OTHER INFORMATION
Item 1. Legal Proceedings
Edison Mission Energy
PMNC Litigation
In February 1997, a civil action was commenced in the Superior Court of
the State of California, Orange County, entitled The Parsons Corporation
and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy
New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which
plaintiffs assert general monetary claims under the construction turnkey
agreement in the amount of $136.8 million. In addition to defending this
action, Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy
Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc.,
Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons
Corporation in the Supreme Court of the State of New York, Kings County,
Index No. 5966/97 asserting general monetary claims in excess of $13
million under the construction turnkey agreement. EME believes that the
outcome of this litigation will not have a material adverse effect on its
consolidated financial position or results of operations.
Southern California Edison Company
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
page 32
<PAGE>
CPUC not grant the application or, in the alternative, that the CPUC
conduct hearings on the application. On January 17, 1997, SCE filed
a reply to the ORA's request. On February 27, 1997, a prehearing
conference was held, at which time SCE's application was set for hearing
to start on April 23, 1997. This hearing date was subsequently vacated
by the assigned administrative law judge due to ongoing discussions to
resolve issues raised by ORA's protest. As a result of those discussions,
SCE and the ORA entered into a stipulation and agreement (Stipulation)
effective July 11, 1997. In the Stipulation, the ORA agrees to withdraw
its protest and support SCE's application in return for SCE's agreement
that the cost recovery issues presented in the application may be
transferred for a decision in SCE's 1992 Energy Cost Adjustment Clause
(ECAC) proceeding, where related issues are currently pending. The
Stipulation further provides for SCE and the ORA to file a joint motion
for approval of the Stipulation. The motion was filed on September 25,
1997. In light of the Stipulation, plaintiffs and SCE have entered into
two amendments to the May 1, 1996, settlement agreement. The first
amendment provides for the post-1995 portion of the settlement to become
effective through 1997 upon CPUC approval consistent with the Stipulation.
The second amendment resulted in plaintiffs dismissing the lawsuit without
prejudice pending final CPUC resolution of the issues raised by SCE's
application. On October 15, 1997, the assigned administrative law judge
issued a draft decision on SCE's application and the motion for approval
of the Stipulation. The draft decision would approve the application
subject to the terms of the Stipulation. As of this date, the CPUC has
not yet acted on the draft decision.
Wind Generators' Litigation
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189 million in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
Superior Court case granted the plaintiffs' motion seeking summary
adjudication that the contract language in question is not reasonably
susceptible to SCE's position that there is only a single, 10-year period
of fixed payments. Following the March 1 ruling, a ninth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first eight. SCE subsequently responded to the complaint
in the new lawsuit by denying its material allegations. On April 5, 1995,
SCE filed a petition for Writ of Mandate, Prohibition or Other Appropriate
Relief, requesting that the Court of Appeal of the State of California,
Second Appellate District issue a writ directing the Los Angeles Superior
Court to vacate its March 1 order granting summary adjudication. In a
decision filed August 9, 1995, the Court of Appeal issued a writ directing
that the order be overturned, and a new order be entered denying the
motion. In light of the Court of Appeal decision in the lead Los Angeles
case, a summary adjudication motion in the Kern County case was withdrawn.
On March 25, 1996, pursuant to a court-approved stipulation, all but one
of the cases were consolidated for trial in Los Angeles Superior Court.
Shortly thereafter, on April 3, 1997, pursuant to stipulation of the
parties, the Kern County case was ordered to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. Trial of the
consolidated cases, beginning with the lead case, commenced on March 10,
1997. The consolidated cases are to be tried one after another in
bifurcated fashion with the liability phase of each and all of the cases
page 33
<PAGE>
to be tried before commencement of the damages phase, if applicable.
Testimony and arguments in the liability phase of the lead case concluded
on May 20, 1997. On July 7, 1997, the court issued a tentative decision
which effectively would resolve all liability issues in the lead case in
SCE's favor. A proposed Statement of Decision consistent with the
conclusions in the tentative decision has been submitted by SCE and
argument on the same took place at a hearing on October 31, 1997. The
hearing was not concluded at that time and further argument has therefore
been scheduled for November 19, 1997. In addition, a status conference
has been scheduled for December 17, 1997, at which time the court will
address scheduling of trial dates in the remaining cases and a date for
commencement of the damages phase of the lead case.
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles Superior Court
against another independent power producer of geothermal generation and
five of its affiliated entities (collectively the "Defendants"). SCE
alleges that in order to avoid power production plant shutdowns caused by
excessive noncondensable gas in the geothermal field brine, the Defendants
routinely vented highly toxic hydrogen sulfide gas from unmonitored
release points beginning in 1990 and continuing through at least 1994, in
violation of applicable federal, state and local environmental law.
According to SCE, these violations constituted material breaches by the
Defendants of their obligations under their contracts and applicable law.
The complaint seeks termination of the contracts and damages for excess
power purchase payments made to the Defendants. The Defendants' motion
to transfer venue to Inyo County Superior Court was granted on August 31,
1997. The Defendants have responded to SCE's allegations by filing both
a demurrer and a motion to strike. These matters are currently set for
hearing on November 20, 1997, in Inyo County Superior Court. In addition,
the Defendants have filed a motion for summary judgment on the grounds
that SCE's claims are time-barred or that such claims were released in
connection with the settlement of the prior litigation between some of the
Defendants and SCE's affiliates, Mission Power Engineering Co., Edison
Mission Energy and The Mission Group.
The Defendants have also filed a cross-complaint which names SCE, Mission
Power Engineering Co., Edison Mission Energy and The Mission Group. In
response to SCE's demurrer, the Defendants withdrew their cross-complaint
and filed a first amended cross-complaint. The first amended cross-
complaint asserts twelve causes of action for alleged violation of certain
orders of the CPUC, declaratory relief with respect to the contracts,
breach of the implied covenant of good faith and fair dealing, inducing
breach of employment agreements, abuse of process, breach of settlement
agreements, disparagement and slander per se, and unfair business
practices under section 17200 of the California Business and Professions
Code. The first amended cross-complaint seeks damages in an unspecified
amount as well as exemplary damages and injunctive relief. SCE has
responded to the first amended cross-complaint by filing a demurrer, which
is set for hearing on November 20, 1997, in Inyo County Superior Court.
In addition to asserting the claims in the first amended cross-complaint,
three of the Defendants (collectively the "Related Plaintiffs") have filed
a separate lawsuit in Inyo County Superior Court. In a first amended
complaint in the separate lawsuit, the Related Plaintiffs allege causes
of action for breach of contract, breach of the implied covenant of good
faith and fair dealing, declaratory relief, violation of California Public
Utilities Code sections 702, 453 and 2106, unfair competition and false
advertising. In addition, the Related Plaintiffs claim that SCE
anticipatorily breached the contracts by asserting that all of the Related
Plaintiffs' facilities are subject to a single "first period." The
Related Plaintiffs seek recovery of $400,000,000 in alleged compensatory
damages as well as exemplary damages and unspecified injunctive relief.
SCE has demurred to the amended complaint and has also moved to strike
page 34
<PAGE>
or, in the alternative, to consolidate the Related Plaintiffs' claims with
the Defendants' claims in the first lawsuit on the ground that the former
claims should have been asserted as part of the amended cross-complaint
in the original action. The hearing on SCE's demurrer and motion to
strike or to consolidate is also currently set for November 20, 1997. No
trial date in either of the two cases has been set.
Electric and Magnetic Fields (EMF) Litigation
SCE is involved in three lawsuits alleging that various plaintiffs
developed cancer as a result of exposure to EMF from SCE facilities. SCE
denied the material allegations in its responses to each of these
lawsuits.
The first lawsuit was filed in Orange County Superior Court and served on
SCE in June 1994. There are five named plaintiffs and six named
defendants, including SCE. Three of the five plaintiffs are presently or
were formerly employed by Grubb & Ellis, a real estate brokerage firm with
offices located in a commercial building known as the Koll Center in
Newport Beach. Two of the named plaintiffs are spouses of the other
plaintiffs. Grubb & Ellis and the owners and developers of the Koll
Center are also named as defendants in the lawsuit. This lawsuit alleges,
among other things, that the three plaintiffs employed by Grubb & Ellis
developed various forms of cancer as a result of exposure to EMF from
electrical facilities owned by SCE and/or the other defendants located on
Koll Center property. No specific damage amounts are alleged in the
complaint, but supplemental documentation prepared by the plaintiffs
indicates that plaintiffs allege compensatory damages of approximately $8
million, plus unspecified punitive damages. In December 1995, the court
granted SCE's motion for summary judgment and dismissed the case.
Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but
no date for oral argument has been set.
A second lawsuit was filed in Orange County Superior Court and served on
SCE in January 1995. This lawsuit arises out of the same fact situation
as the June 1994 lawsuit described above and involves the same defendants.
There are four named plaintiffs, two of whom were formerly employed by
Grubb & Ellis and now allegedly have various forms of cancer. The other
two plaintiffs are the spouses of those two individuals. No specific
damage amounts are alleged in the complaint, but supplemental
documentation prepared by the plaintiffs indicates that plaintiffs will
allege compensatory damages of approximately $13.5 million, plus
unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a
cross-complaint against the other co-defendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. Although stayed for a time pending
appellate review of sanctions imposed against plaintiffs' attorneys by the
trial court, the case has been remanded back to the trial court following
the Court of Appeal's decision modifying the sanctions order. To date,
no further proceedings have been scheduled.
A third case was filed in Orange County Superior Court and served on SCE
in March 1995. The plaintiff alleges, among other things, that he
developed cancer as a result of EMF emitted from SCE distribution lines
which he alleges were not constructed in accordance with CPUC standards.
No specific damage amounts are alleged in the complaint but supplemental
documentation prepared by the plaintiff indicates that plaintiff will
allege compensatory damages of approximately $5.5 million, plus
unspecified punitive damages. No trial date has been set in this case.
San Onofre 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
page 35
<PAGE>
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. SCE's April 20, 1995, answer to
the complaint denied all material allegations. On October 10, 1995, the
court granted plaintiffs' motion to include the Institute of Nuclear Power
Operations (an organization dedicated to achieving excellence in nuclear
power operations) as a defendant in the suit. On December 7, 1995, the
court granted SCE's motion for summary judgment on the sole outstanding
claim against it, basing the ruling on the worker's compensation system
being the exclusive remedy for the claim. Plaintiffs have appealed this
ruling to the Ninth Circuit Court of Appeals. Oral argument on the appeal
has been set for December 4, 1997. All trial court proceedings have been
stayed pending the ruling of the Court of Appeals. The impact on SCE, if
any, from further proceedings in this case against the remaining
defendants cannot be determined at this time.
On July 5, 1995, a former SCE reactor operator and his wife sued SCE and
SDG&E in the U.S. District court for the Southern District of California.
Plaintiffs also named Combustion Engineering, the manufacturer of the fuel
rods for the plant, and the Institute of Nuclear Power Operations as
defendants. The former employee died of leukemia shortly after the
complaint was filed. Plaintiffs allege that the former operator's illness
resulted from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles released from failed
fuel rods. Plaintiffs seek unspecified compensatory and punitive damages.
On November 22, 1995, the complaint was amended to allege wrongful death
and added the former employee's two children as plaintiffs. On December
22, 1995, SCE filed a motion to dismiss or, in the alternative, for
summary judgment based on worker's compensation exclusivity. On March 25,
1996, the court granted SCE's motion for summary judgment. Plaintiffs
have appealed this ruling to the Ninth Circuit Court of Appeals. Oral
argument on the appeal has been set for December 4, 1997. All trial court
proceedings have been stayed pending the ruling of the Court of Appeals
in this case and in the case described in the above paragraph. The impact
on SCE, if any, from further proceedings in this case against the
remaining defendants cannot be determined at this time.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District court for the Southern
District of California. Plaintiffs also named Combustion Engineering, the
manufacturer of fuel rods for the plant, and the Institute of Nuclear
Power Operations as defendants. The security officer worked for a
contractor in 1982, worked for SCE as a temporary employee (1982-1984),
and later worked as an SCE security supervisor (1984-1994). The officer
died of leukemia in 1994. Plaintiffs allege that the former officer's
illness resulted from, and was aggravated by, his exposure to radiation
at San Onofre, including contact with radioactive fuel particles released
from failed fuel rods. Plaintiffs seek unspecified compensatory and
punitive damages. SCE's November 13, 1995, answer to the complaint denied
all material allegations. All trial court proceedings have been stayed
pending the rulings of the Court of Appeals in the cases described in the
above two paragraphs.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S.
District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering, the manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs alleged 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,
page 36
<PAGE>
partial answer to the complaint denied all material non-employment related
allegations. SCE's motion to dismiss the employee's employment related
allegations based on worker's compensation exclusivity was granted on
March 19, 1996. The employee's wife died on August 15, 1996. On
September 20, 1996, the complaint was amended to allege wrongful death and
to add the employee's two children as plaintiffs. SCE's motion for
summary judgment was denied on April 9, 1997. The trial in this case is
scheduled to begin on January 27, 1998.
On November 28, 1995, a former contract worker at San Onofre, her husband,
and her son, sued SCE in the U.S. District Court for the Southern District
of California. Plaintiffs also named Combustion Engineering, the
manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege
that the former contract worker transported radioactive byproducts on her
person and clothing to her home where her son was then exposed to
radiation that caused his leukemia. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's January 2, 1996, answer denied
all material allegations. On August 12, 1996, the Court dismissed the
claims of the former worker and her husband with prejudice. This case is
expected to go to trial in early 1998, after completion of the trial in
the case described in the preceding paragraph.
Oil Pipeline Litigation
On November 1, 1996, plaintiff, a crude oil pipeline company, filed a
lawsuit against SCE and the City of Los Angeles (the City) in the United
States District Court for the Central District of California claiming that
SCE and the City had interfered with its attempt to construct a proposed
132-mile oil pipeline (Pacific Pipeline) designed to transport oil from
the San Joaquin Valley and Santa Barbara to the Los Angeles refineries.
Plaintiff alleges, among other things, that SCE and the City wrongfully
initiated administrative and other legal proceedings in an attempt to
derail and obstruct the construction of the Pacific Pipeline. Plaintiff
alleges that these acts constitute unfair competition, tortious
interference with economic advantage and violate state and federal
antitrust laws. Plaintiff further claims that because of the alleged
delays, it could suffer losses in excess of $300 million. Additionally,
plaintiff seeks treble and punitive damages.
On June 30, 1997, SCE filed an answer to the complaint denying the
substantive allegations and raising appropriate defenses.
Rubaii False Claims Act Litigation
In September 1997, SCE became aware of a complaint filed in the Southern
District of the U.S. District Court of California by a San Onofre
employee, acting at his own initiative on behalf of the United States
under the False Claims Act, against SCE and SDG&E. The complaint alleges
that SCE and SDG&E have submitted fraudulent claims to the United States
government, the State of California and their customers resulting in $491
million in overpayments ($383 million of which is attributed to SCE). The
employee alleges that SCE and SDG&E provided the CPUC with data which
inflated projected costs at San Onofre while minimizing projected
revenues, resulting in the CPUC setting inflated rates. The amount sought
in this complaint is subject to trebling, plus civil penalties of $10,000
per false claim submitted for payment (for an unspecified number of
claims). SCE filed a motion to dismiss this lawsuit on November 7, 1997.
page 37
<PAGE>
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.
EDISON INTERNATIONAL
(Registrant)
By R. K. BUSHEY
---------------------------------
R. K. BUSHEY
Vice President and Controller
By K. S. STEWART
---------------------------------
K. S. STEWART
Assistant General Counsel and
Assistant Secretary
November 13, 1997
PAGE
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report included in this quarterly report on Form
10-Q for the quarter ended September 30, 1997, of Edison International
into the previously filed Registration Statements which follow:
Registration Form File No. Effective Date
----------------- -------- --------------
Form S-3 333-08115 July 15, 1996
Form S-8 333-30913 May 16, 1996
Form S-8 33-32302 June 2, 1993
Form S-8 33-46713 June 2, 1993
Form S-8 33-46714 June 2, 1993
Form S-3 33-44148 September 17, 1993
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
November 12, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Edison International Financial Data Schedule - Exhibit 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,195,412
<OTHER-PROPERTY-AND-INVEST> 7,608,515
<TOTAL-CURRENT-ASSETS> 2,565,879
<TOTAL-DEFERRED-CHARGES> 3,040,011
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 24,409,817
<COMMON> 2,328,294
<CAPITAL-SURPLUS-PAID-IN> 83,221
<RETAINED-EARNINGS> 3,351,507
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,763,022
425,000
183,755
<LONG-TERM-DEBT-NET> 2,810,221
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 4,192,343
<COMMERCIAL-PAPER-OBLIGATIONS> 869,509
<LONG-TERM-DEBT-CURRENT-PORT> 347,882
0
<CAPITAL-LEASE-OBLIGATIONS> 46,872
<LEASES-CURRENT> 19,879
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,751,334
<TOT-CAPITALIZATION-AND-LIAB> 24,409,817
<GROSS-OPERATING-REVENUE> 6,905,691
<INCOME-TAX-EXPENSE> 395,732
<OTHER-OPERATING-EXPENSES> 5,353,773
<TOTAL-OPERATING-EXPENSES> 5,749,505
<OPERATING-INCOME-LOSS> 1,156,186
<OTHER-INCOME-NET> (41,951)
<INCOME-BEFORE-INTEREST-EXPEN> 1,114,235
<TOTAL-INTEREST-EXPENSE> 521,018
<NET-INCOME> 593,217
32,593
<EARNINGS-AVAILABLE-FOR-COMM> 560,624
<COMMON-STOCK-DIVIDENDS> 300,962
<TOTAL-INTEREST-ON-BONDS> 259,503
<CASH-FLOW-OPERATIONS> 1,551,805
<EPS-PRIMARY> $1.38
<EPS-DILUTED> $1.37
</TABLE>
