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, 1996
---------------------------------------
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)
818-302-2222
(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 7, 1996
- -------------------------- -------------------------------
Common Stock, no par value 433,229,328
paeg
<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, 1996, and 1995 2
Consolidated Balance Sheets--September 30, 1996,
and December 31, 1995 3
Consolidated Statements of Cash Flows--Nine Months
Ended September 30, 1996, and 1995 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 13
Part II. Other Information:
Item 1. Legal Proceedings 26
Item 6. Exhibits and Reports on Form 8-K 32
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,
----------------------- ------------------------
1996 1995 1996 1995
---------- --------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C>
Electric utility revenue $2,346,161 $2,509,848 $5,717,283 $5,969,459
Diversified operations 222,023 160,158 632,300 383,417
---------- ---------- ---------- ----------
Total operating revenue 2,568,184 2,670,006 6,349,583 6,352,876
---------- ---------- ---------- ----------
Fuel 249,385 213,558 555,065 517,022
Purchased power 938,588 917,547 2,026,762 1,954,370
Provisions for regulatory adjustment
clauses -- net (66,531) 146,463 (170,214) 191,918
Other operating expenses 333,300 350,719 1,082,843 1,015,516
Maintenance 67,461 86,488 219,185 269,212
Depreciation and decommissioning 302,276 253,720 865,938 750,271
Income taxes 228,356 202,602 467,555 419,150
Property and other taxes 46,943 50,612 152,528 158,990
---------- ---------- ---------- ----------
Total operating expenses 2,099,778 2,221,709 5,199,662 5,276,449
---------- ---------- ---------- ----------
Operating income 468,406 448,297 1,149,921 1,076,427
---------- ---------- ---------- ----------
Provision for rate phase-in plan (22,021) (33,082) (69,966) (90,947)
Allowance for equity funds used
during construction 3,466 4,392 10,934 14,915
Interest income 14,216 16,625 42,315 46,695
Minority interest (12,812) (11,284) (40,681) (34,378)
Other nonoperating income -- net (12,172) 10,241 (2,125) 29,023
---------- ---------- ---------- ----------
Total other income (deductions) -- net (29,323) (13,108) (59,523) (34,692)
---------- ---------- ---------- ----------
Income before interest and other expenses 439,083 435,189 1,090,398 1,041,735
---------- ---------- ---------- ----------
Interest on long-term debt 149,683 140,913 447,142 399,141
Other interest expense 22,286 14,676 67,921 61,580
Allowance for borrowed funds used
during construction (2,179) (3,335) (6,874) (11,326)
Capitalized interest (19,407) (16,012) (53,055) (43,581)
Dividends on subsidiary preferred
securities 11,881 11,378 35,626 34,934
---------- ---------- ---------- ----------
Total interest and other expenses -- net 162,264 147,620 490,760 440,748
---------- ---------- ---------- ----------
Net income $ 276,819 $ 287,569 $ 599,638 $ 600,987
========== ========== ========== ==========
Weighted-average shares of common stock
outstanding 436,476 445,855 440,135 446,755
Earnings per share $0.63 $0.65 $1.36 $1.35
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,
1996 1995
------------- -----------
(Unaudited)
ASSETS
<S> <C> <C>
Utility plant, at original cost $20,259,757 $19,850,179
Less -- accumulated provision for
depreciation and decommissioning 9,149,918 8,569,265
----------- -----------
11,109,839 11,280,914
Construction work in progress 605,774 727,865
Nuclear fuel, at amortized cost 150,092 139,411
----------- -----------
Total utility plant 11,865,705 12,148,190
----------- -----------
Nonutility property -- less
accumulated provision for
depreciation of $177,873 and $133,670
at respective dates 3,468,150 3,140,385
Nuclear decommissioning trusts 1,401,553 1,260,095
Investments in partnerships and
unconsolidated subsidiaries 1,091,016 1,190,294
Investments in leveraged leases 582,196 574,091
Other investments 224,000 65,963
----------- -----------
Total other property and investments 6,766,915 6,230,828
----------- -----------
Cash and equivalents 1,051,610 507,151
Receivables, including unbilled
revenue, less allowances of
$25,985 and $24,244 for uncollectible
accounts at respective dates 1,232,334 1,054,954
Fuel inventory 76,202 114,357
Materials and supplies, at average cost 153,820 151,180
Accumulated deferred income taxes -- net 458,411 476,725
Prepayments and other current assets 150,619 126,184
----------- -----------
Total current assets 3,122,996 2,430,551
----------- -----------
Unamortized debt issuance and
reacquisition expense 354,684 350,563
Rate phase-in plan 65,912 129,714
Unamortized nuclear plant -- net -- 67,185
Income tax-related deferred charges 1,730,821 1,723,605
Other deferred charges 966,805 865,599
----------- -----------
Total deferred charges 3,118,222 3,136,666
----------- -----------
Total assets $24,873,838 $23,946,235
=========== ===========
</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,
1996 1995
------------- -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
Common shareholders' equity:
Common stock (433,461,780 and 443,607,674
<S> <C> <C>
shares outstanding at respective dates) $ 2,629,471 $ 2,678,578
Retained earnings 3,864,841 3,699,572
----------- -----------
6,494,312 6,378,150
Preferred securities of subsidiaries:
Not subject to mandatory redemption 283,755 283,755
Subject to mandatory redemption 425,000 425,000
Long-term debt 7,131,011 7,195,197
----------- -----------
Total capitalization 14,334,078 14,282,102
----------- -----------
Other long-term liabilities 347,766 344,192
----------- -----------
Current portion of long-term debt 563,029 40,328
Short-term debt 547,542 709,508
Accounts payable 433,067 419,522
Accrued taxes 982,523 557,095
Accrued interest 126,065 101,370
Dividends payable 110,797 113,334
Regulatory balancing accounts -- net 206,053 337,867
Deferred unbilled revenue and other
current liabilities 1,160,156 973,529
----------- -----------
Total current liabilities 4,129,232 3,252,553
----------- -----------
Accumulated deferred income
taxes -- net 4,270,993 4,352,127
Accumulated deferred investment
tax credits 377,827 405,112
Customer advances and other
deferred credits 713,037 680,210
----------- -----------
Total deferred credits 5,361,857 5,437,449
----------- -----------
Minority interest 700,905 629,939
----------- -----------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $24,873,838 $23,946,235
=========== ===========
</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,
-----------------------
1996 1995
------------ -------------
(Unaudited)
Cash flows from operating activities:
<S> <C> <C>
Net income $ 599,638 $ 600,987
Adjustments for non-cash items:
Depreciation and decommissioning 865,938 750,271
Amortization 81,748 47,347
Rate phase-in plan 63,802 81,800
Deferred income taxes and investment tax
credits (103,136) (161,904)
Equity in income from partnerships and
unconsolidated subsidiaries (131,293) (113,770)
Other long-term liabilities 3,574 33,966
Other -- net 5,470 (33,772)
Changes in working capital:
Receivables (158,844) (269,945)
Regulatory balancing accounts (131,814) 241,054
Fuel inventory, materials and supplies 35,515 (29,045)
Prepayments and other current assets (24,435) (37,183)
Accrued interest and taxes 449,377 331,001
Accounts payable and other current
liabilities 211,113 172,698
Distributions from partnerships and
unconsolidated subsidiaries 108,025 118,033
--------- ---------
Net cash provided by operating activities 1,874,678 1,731,538
--------- ---------
Cash flows from financing activities:
Long-term debt issued 1,285,274 836,335
Long-term debt repayments (1,093,835) (762,790)
Preferred securities issued -- 62,500
Preferred securities redemptions -- (75,000)
Common stock issued 745 --
Common stock repurchases (166,287) (39,850)
Nuclear fuel financing - net 20,510 42,775
Short-term debt financing -- net (161,966) (322,512)
Dividends paid (331,709) (335,374)
--------- ---------
Net cash used by financing activities (447,268) (593,916)
--------- ---------
Cash flows from investing activities:
Additions to property and plant (607,253) (719,964)
Funding of nuclear decommissioning trusts (110,241) (111,897)
Investments in partnerships and
unconsolidated subsidiaries (209,808) (310,523)
Unrealized gain on equity investments 11,246 7,260
Other -- net 33,105 8,064
--------- ---------
Net cash used by investing activities (882,951) (1,127,060)
--------- ---------
Net increase in cash and equivalents 544,459 10,562
Cash and equivalents, beginning of period 507,151 533,957
--------- ---------
Cash and equivalents, end of period $1,051,610 $ 544,519
========= =========
</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
1995 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 1995 Annual Report.
Certain prior-period amounts were reclassified to conform to the September
30, 1996, financial statement presentation.
Note 1. Regulatory Matters
Performance-Based Ratemaking (PBR)
On September 20, 1996, the California Public Utilities Commission (CPUC)
adopted a non-generation transmission and distribution (T&D) PBR
mechanism for Southern California Edison Company (SCE) beginning 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 Federal Energy Regulatory
Commission (FERC). The distribution-only PBR will extend through December
2001. Key elements of the non-generation PBR include: T&D rates indexed
to inflation based on the Consumer Price Index; 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. On July 15, 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. If approved, the hydro PBR would be in effect for three
years and the initial terms of the local reliability contracts, which are
subject to FERC approval, would be in effect for up to three years, both
beginning January 1, 1998. A final CPUC decision on hydro PBR is expected
by year-end 1997.
Restructuring Legislation
On September 23, 1996, the State of California enacted legislation to
provide a rapid, but orderly, transition to a competitive market
structure. The legislation substantially adopts the CPUC's December 1995
restructuring decision (discussed below) by favorably addressing stranded-
cost recovery for utilities, 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, allowing SCE to give a rate reduction of 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
page 6
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 period. In
addition, the legislation mandates the implementation of a competition
transition charge (CTC) that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Finally, the
legislation contains provisions for the recovery (through 2006) of
reasonable employee-related transition costs incurred and projected for
retraining, severance, early retirement, outplacement and related expenses
for utility workers.
CPUC Restructuring Decision
In December 1995, the CPUC issued its decision on restructuring
California's electric industry, which it had been considering since April
1994. The new market structure would provide competition and customer
choice. The transition to a competitive electric market would begin
January 1, 1998, with all consumers participating by 2003. However, the
legislation enacted in September 1996 specifies that all customers should
be eligible to participate through direct transactions in the competitive
market no later than January 1, 2002. Key elements of the CPUC decision
include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from and sell to the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore,
control of the scheduling and dispatch of all electricity on the
state's power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the
existing framework, and reasonable employee-related costs) through a
non-bypassable charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture
(through spin-off or sale to an unaffiliated entity) of at least 50%
of utilities' gas-fueled generation to address market power issues.
o PBR for those utility services not subject to competition.
In March 1996, SCE filed a plan outlining how it would propose to divest
50% of its gas-fueled generation. SCE's plan is contingent on assurances
about transition cost recovery and the resolution of key issues related
to: worker protection measures being in place for utility employees who
could suffer hardship as a result of divestiture; utilities being
permitted full recovery of the transition costs incurred during the
divestiture process; appropriate rate-making measures to cover the
contingency if the completion of the divestiture plan or commencement of
the PX is delayed; and prudently incurred costs associated with fuel
supply, transportation and storage contracts not being stranded by the
divestiture.
page 7
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 would be backed by
utility guarantees and SCE's share would be 45%. Once the ISO and PX are
formed, they 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 funding it with $250 million in
order to build the hardware and software systems for the ISO and PX.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public goods programs and the CTC. The filing is in
response to CPUC and FERC directives that electric services, such as T&D,
be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers.
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 currently use utility services or begin utility service
after this decision is effective. On August 30, 1996, in compliance with
the CPUC's restructuring decision, SCE filed its application to estimate
its 1998 transition costs. On October 21, 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 components for
the PX, T&D, nuclear decommissioning, and public benefits 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 $11.9 billion (1997 net
present value), assuming the fossil plants have a market value equal to
the net book value, and $12.6 billion (1997 net present value), assuming
the fossil plants have no market value. These estimates are based on
incurred costs, and forecasts of future costs and assumed market prices.
However, changes in the assumed market price could materially affect these
estimates. The potential transition costs are comprised of: $6.8 billion
from SCE's qualifying facility contracts, which are the direct result of
legislative and regulatory mandates; and $5.1 billion to $5.8 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 and Palo Verde Nuclear Generating
Station, nuclear decommissioning and certain other costs.
In light of the legislation, the CPUC is reassessing the need to prepare
an environmental impact report. If the CPUC's restructuring is
implemented as outlined, SCE would be allowed to recover its CTC (subject
to a lower return on equity) and would continue to apply accounting
standards that recognize the economic effects of rate regulation for its
generation-related assets during the rate recovery period. The effect of
such an outcome would not be expected to materially affect SCE's results
of operations or financial position during the transition period.
If during the restructuring process, events occur that result in SCE no
longer meeting the criteria to apply regulatory accounting standards to
its generation operations, SCE may be required to write off its recorded
generation-related regulatory assets. At September 30, 1996, these
amounts totaled approximately $1.0 billion, primarily for the recovery of
income tax benefits previously flowed-through to customers, the Palo Verde
phase-in plan and unamortized loss on reacquired debt. Although
page 8
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
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.
Additionally, 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 Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, which it had been considering since March 1995.
The decision, which became effective in July 1996, 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 recovery of stranded costs, which are prior-service costs incurred
under the current regulatory framework. In addition to providing recovery
of stranded costs associated with existing wholesale customers, the FERC
directed that it would have primary jurisdiction over the recovery of
stranded costs associated with retail-turned-wholesale customers, such as
the formation of a new municipal electric system. Retail stranded costs
resulting from a state-authorized retail direct-access program are the
responsibility of the states and the FERC would only address recovery of
these costs if the state has no authority to do so. In compliance with
the April 1996 FERC decision, SCE filed a revised open access tariff with
the FERC on July 9, 1996. The tariff became effective, on an interim
basis, subject to refund, as of its filing date. Several wholesale
customers have filed protests with the FERC on the transmission rate
levels, and a ruling from the FERC setting the rates for formal hearing
is anticipated by the end of 1996 or early in 1997.
Mohave Generating Station
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the CPUC's
Organization (formerly Division) of Ratepayer Advocates (ORA) which
resulted in a $39 million (including interest) refund to SCE's customers
beginning in August 1996. As of September 30, 1996, approximately $32.7
million has been refunded to customers via a bill credit. The remainder
will be refunded by year-end. This refund has been fully reflected in the
financial statements.
Canadian Gas Contracts
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA filed its report on the reasonableness of SCE's gas supply costs
for both the 1993 and 1994 record periods. The report recommends a
disallowance of $13.3 million for excessive costs incurred from November
page 9
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
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. SCE and the ORA have filed several rounds of testimony on
this issue. Hearings are scheduled for early 1997.
Palo Verde Rate-making Proposal
In February 1996, SCE filed a proposal with the CPUC requesting a new rate
mechanism for its 15.8% share of the three units at Palo Verde.
The proposed rate mechanism would allow SCE to accelerate the recovery of
its share of Palo Verde's sunk cost (forecast to be $1.2 billion as of
December 31, 1996), over a seven-year period, beginning January 1, 1997,
and ending in 2003. During the seven-year period, SCE's return on rate
base for Palo Verde's sunk cost would be reduced to 7.35% from the current
9.55%. In addition, SCE proposed an incentive pricing plan to recover the
incremental costs of continued operation of Palo Verde at approximately
3.4 cents per kilowatt-hour, provided the Palo Verde units operate at an
average capacity factor of 77%. The legislation has accelerated the
proposed recovery period to five years (1997-2001). On November 1, 1996,
all of the active parties to the Palo Verde proceeding signed a Memorandum
of Understanding (MOU) which will form the basis for a definitive
settlement agreement. The portion of the MOU concerning accelerated
recovery of Palo Verde's sunk costs is consistent with SCE's proposal, as
modified by the new legislation. However, instead of the incremental cost
incentive pricing proposed by SCE, the MOU proposes to pass-through Palo
Verde incremental costs to ratepayers through a balancing account. These
costs will be considered reasonable so long as they do not exceed 30% of
a baseline forecast and the site's capacity factor does not go below 55%.
The existing nuclear unit incentive procedure will continue only for
purposes of calculating a reward for performance of any unit above an 80%
capacity factor for a fuel cycle. For post-2001 operations, SCE's
ratepayers will receive 50% of the operational benefits. A definitive
settlement agreement is expected to be filed with the CPUC in late 1996
with a decision expected in late 1996 or early 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) owns, through a wholly owned subsidiary, 50%
of the Brooklyn Navy Yard project; however, it is initially funding all
of the required equity and debt ($483 million) for the project and has
provided a guarantee as a condition of obtaining financing for the
project. In November 1996, EME executed a new Energy Sales Agreement with
Consolidated Edison Company of New York, which has contracted to buy most
of the project's power and steam, and began selling power and steam under
the Agreement on November 1, 1996. EME continues to believe that the
anticipated returns with respect to the project will be substantially less
than originally estimated. EME has been advised that the contractor
intends to assert general monetary claims, under the construction turnkey
agreement, against Brooklyn Navy Yard. EME may assert claims against the
contractor. None of such claims is expected to have a material effect on
EME.
page 10
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
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.
Edison International's recorded estimated minimum liability to remediate
its 61 identified sites (58 at SCE and 3 at EME) was $114 million at
September 30, 1996. 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 $215 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 35 of its
sites, representing $101 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 a
number of its carriers and is no longer pursuing any additional
recoveries. Costs incurred at SCE's remaining 23 sites are expected to
be recovered through customer rates. SCE has recorded a regulatory asset
of $104 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
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 $8 million.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
In 1994, SCE utilized an estimating technique to quantify its potential
liability for environmental cleanup in an effort to obtain a reasonably
possible objective and reliable estimate of environmental cleanup. During
1995, EME completed a similar review of some of its sites where known
contamination and potential liability exist and does not believe a
material liability exists as of September 30, 1996.
Based on currently available information, Edison International believes
it is not likely 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 have a material adverse effect on 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 will 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
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 $42 million per year.
Insurance premiums are charged to operating expense.
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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, 1996, were 63 cents and $1.36, respectively, compared
with 65 cents and $1.35 for the year-earlier periods. Southern
California Edison Company's (SCE) earnings were 56 cents and $1.15 for the
quarter and year-to-date ended September 30, 1996, compared to 55 cents
and $1.17 for the same periods in 1995. Edison International's reported
earnings include a 4-cent per share reversal of a portion of workforce
management costs previously accrued in the second quarter of 1996, and
provisions for operating reserves of 2 cents per share at the nonutility
subsidiaries. Excluding these special charges, Edison International's
quarterly earnings decreased 5 cents per share while year-to-date earnings
were unchanged.
Excluding special charges, SCE's earnings decreased 4 cents and 2 cents,
respectively, for the three- and nine-month periods ended September 30,
1996. The decreased earnings reflect a lower authorized return on common
equity and lower authorized operating expenses.
The combined earnings of the nonutility subsidiaries and the parent
company were 7 cents and 21 cents for the quarter and year-to-date ended
September 30, 1996, compared to 10 cents and 18 cents for the same periods
in 1995. Excluding special charges, the nonutility subsidiaries'
quarterly earnings decreased 1 cent for the quarter and increased 2 cents
for the nine months ended September 30, 1996. The quarterly decrease is
mainly attributable to Edison International's interest payments on a $350
million debt issuance related to EME's acquisition of First Hydro in
December 1995, as well as start-up costs for Edison International's new
subsidiaries. Year-to-date earnings at the nonutility subsidiaries
include special charges of 3 cents per share related to a gain on the sale
of EME's interest in four geothermal projects previously reported during
the second quarter, partially offset by a 2-cent third quarter charge for
operating reserves previously discussed. The year-to-date increase is
primarily related to earnings from EME's recently acquired First Hydro
project. There were no comparable earnings from First Hydro included in
1995.
Operating Revenue
Electric utility revenue decreased during the three and nine months ended
September 30, 1996, due to a 4.4% decline in California Public Utilities
Commission (CPUC)-authorized rates effective April 1996. Additionally,
SCE refunded $237 million to ratepayers as part of a CPUC-ordered refund
of energy-cost balancing account overcollections.
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In March 1995, SCE announced its intention to freeze average rates for
residential, small business and agricultural customers through 1996, and
announced a five-year goal to reduce system average rates by 25% (from
10.7 cents per kilowatt-hour to below 10 cents per kilowatt-hour), after
adjusting for inflation. In February 1996, the CPUC approved a system-
wide rate reduction which will drop the average price per kilowatt-hour
from 10.7 cents to 10.1 cents. Legislation enacted in September 1996
provides, among other things, at least a 10% rate reduction for
residential and small commercial customers beginning in 1998, contingent
upon the issuance of rate reduction bonds (see Regulatory Matters).
Revenue from diversified operations increased 39% and 65%, respectively,
for the three and nine month periods ended September 30, 1996, compared
with the same periods in 1995. The changes are due to an increase in
EME's electric revenue from its First Hydro and Iberian Hy-Power projects.
First Hydro is an independent power company whose principal assets consist
of two pumped-storage electric power stations with a combined capacity of
2,088 megawatts; it was acquired in December 1995. In January 1996, EME
increased its ownership from 34% to 100% in Iberian Hy-Power, which
consists of 18 hydroelectric plants located throughout Spain. There was
no comparable revenue from these projects included in 1995.
Operating Expenses
Fuel expense increased 17% during the third quarter of 1996, compared to
the same period in 1995, due to higher gas prices and increased purchased
power on the open market. EME's fuel expense increased due to the
inclusion of fuel costs related to First Hydro. Year-to-date fuel expense
increased 7%, due mainly to the inclusion of EME's First Hydro project,
and was partially offset by a slight decrease at SCE. There was no
comparable fuel expense for First Hydro included in 1995.
Purchased-power expense increased slightly, for the three and nine months
ended September 30, 1996, compared to the same periods last year due to
an increase in power provided by federally required sources. SCE makes
federally required power purchases from nonutility generators based on
contracts with CPUC-mandated pricing. Energy prices under these contracts
are generally higher than other energy sources.
Provisions for regulatory adjustment clauses decreased substantially for
the three, nine and twelve months ended September 30, 1996, compared to
the year-earlier periods. The decreases are mainly due to the energy-cost-
balancing account-related refund as discussed above, lower base rate
revenue, and undercollections related to the accelerated recovery of SCE's
remaining investment in San Onofre Nuclear Generating Station Units 2 and
3 (see discussion in Regulatory Matters).
In the third quarter of 1996, SCE recorded a $40 million (pre-tax) one-
time benefit it had accrued in the previous quarter, based on a
decision not to outsource certain operations. This benefit was partially
offset by $12 million (pre-tax) in additional accruals for a voluntary
retirement program for represented employees. Excluding these special
items, other operating expenses increased 2% and 9% for the three and nine
months ended September 30, 1996, due to increased administrative and
operating expenses at EME's First Hydro and Iberian Hy-power projects.
Maintenance expense decreased 22% and 19%, respectively, for the three and
nine months ended September 30, 1996, compared with the year-earlier
periods, due to higher expenses during 1995 from scheduled refueling and
maintenance outages at San Onofre Units 2 and 3.
Depreciation and decommissioning expense increased 19% and 15%,
respectively, for the three and nine months ended September 30, 1996,
compared to the year-earlier periods. The increases are primarily due to
increased depreciation rates and the accelerated recovery of SCE's San
Onofre Unit 2 and 3 investments which began April 14, 1996, as part of
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an agreement with the CPUC (see discussion in Regulatory Matters) and
increases at EME related to its First Hydro and Iberian Hy-Power projects.
There was no comparable depreciation expense from these EME projects
included in 1995.
Income taxes increased for the three and nine months ended September 30,
1996, compared to 1995, mainly due to an increase in the deferred tax
provision related to the accelerated recovery of San Onofre Units 2 and
3 at SCE and increased earnings at EME from its First Hydro project.
Earnings from First Hydro are subject to a higher effective tax rate than
the federal statutory rate.
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 Nuclear Generating
Station. 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 income decreased 15% and 9% respectively, during the three and
nine months ended September 30, 1996, compared to the same period in 1995,
as higher investment balances were more than offset by lower interest
rates.
Minority interest increased 14% and 18%, respectively, for the three and
nine months ended September 30, 1996, compared to the same periods in
1995, primarily from higher pre-tax income at EME's Loy Yang B project.
Other nonoperating income decreased substantially for both the three and
nine months ended September 30, 1996, due to additional accruals for SCE
regulatory matters in the third quarter of 1996, partially offset by EME's
gain on the sale of its geothermal facilities.
Interest and Other Expenses
Interest on long-term debt increased 6% and 12%, respectively, for the
three and nine month periods ended September 30, 1996, reflecting EME's
increased ownership in Iberian Hy-Power and newly acquired First Hydro
project.
Other interest expense increased for both the three and nine months ended
September 30, 1996, due to the current maturity of a $350 million
borrowing by Edison International (holding company) for the acquisition
of First Hydro in the fourth quarter of 1995.
Capitalized interest increased 22% for both periods ended September 30,
1996, compared to the year-earlier periods, primarily due to an increase
in construction activity at EME's Loy Yang B Unit 2, Brooklyn Navy Yard
and Paiton projects. Loy Yang B Unit 2 began commercial operation on
October 1, 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.
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In June 1994, Edison International lowered its quarterly common stock
dividend by 30%, as the result of uncertainty of future earnings levels
arising from the changing nature of California's electric utility
regulation.
In January 1995, Edison International authorized the repurchase of up to
$150 million (increased to $800 million on September 25, 1996) of its
common stock. Edison International has repurchased 16.5 million shares
($277 million) through November 7, 1996, funded by dividends from its
subsidiaries.
For the nine months ended September 30, 1996, Edison International's cash
flow coverage of dividends increased to 5.7 times from 5.2 times for the
same period in 1995. Edison International's dividend payout ratio for the
twelve-month period ended September 30, 1996, was 60%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.9 billion for the
nine-month period ended September 30, 1996, compared with $1.7 billion for
the same period in 1995. Cash from operations exceeded capital
requirements for all periods presented.
Cash Flows from Financing Activities
At September 30, 1996, Edison International and its subsidiaries had $1.7
billion of borrowing capacity available under lines of credit totaling
$2.0 billion. SCE had available lines of credit of $1.1 billion, with
$600 million for short-term debt and $500 million for the long-term
refinancing of its variable-rate pollution-control bonds. The parent
company had a $350 million, one-year term, line of credit with $85 million
of borrowing capacity available. The nonutility companies had available
lines of credit of $600 million 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, 1996, SCE could issue approximately $7.9 billion of
additional first and refunding mortgage bonds and $4.4 billion of
preferred stock at current interest and dividend rates.
EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard
project. However, EME is initially funding all of the required equity and
debt ($483 million) for the project; about $409 million had been spent
through September 30, 1996. In December 1995, EME provided a guarantee
as a condition of obtaining a $254 million tax-exempt financing for the
project. In November 1996, EME executed a new Energy Sales Agreement with
Consolidated Edison Company of New York, which has contracted to buy most
of the project's power and steam, and began selling power and steam under
the Agreement on November 1, 1996. EME continues to believe that the
anticipated returns with respect to the project will be substantially less
than originally estimated. EME has been advised that the contractor
intends to assert general monetary claims, under the construction turnkey
agreement, against Brooklyn Navy Yard. EME may assert claims against the
contractor. None of such claims is expected to have a material effect on
EME.
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At September 30, 1996, EME had firm commitments to make equity and other
contributions to its projects and contingent obligations to make
additional contributions to its projects in the amount of $421 million and
$464 million, respectively. Included in the contingent obligations are
EME's guarantees related to the Brooklyn Navy Yard project, discussed
above. The majority of the remaining amounts are for the expected four-
year construction period of the Paiton project and the ISAB S.p.A. project
discussed below.
In April 1996, EME and its partner ISAB S.p.A., completed a 1.9 trillion
Italian lira ($1.2 billion) financing for a 512 MW power project located
in Italy. In connection with the financing, EME has guaranteed equity
contributions and subordinated debt totaling 244 billion Italian lira
($160 million).
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, 1996, SCE had the capacity to pay $295 million 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
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 between 2013-2070 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar
decommissioning costs ($2.0 billion), escalated using a 6.65% rate and an
earnings assumption on trust funds ranging from 5.5% to 5.75%. 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 $240
million for the nine-month period ended September 30, 1996, compared to
$432 million for the same period in 1995.
Edison International's risk management policy allows the use of derivative
financial instruments to mitigate risk. Changes in interest rates,
electricity pool pricing and fluctuations in foreign currency exchange
rates can have a significant impact on EME's results of operations. EME
has attempted to mitigate 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 increased $5.6 million for the nine months ended September 30,
1996, and $5.3 million for the nine months ended September 30, 1995. 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
financial position or results of operations.
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Projects in the United Kingdom (U.K.) sell their energy and capacity
production through a centralized electricity pool, which establishes a
half-hourly clearing price for electrical energy and capacity. 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), where payments are made when pool selling prices rise above
the price specified in the contracts. These contracts act as a means of
stabilizing production revenue by removing an element of net exposure to
pool price volatility. First Hydro's electric revenue was decreased by $4
million for the nine months ended September 30, 1996, as a result of
electricity rate swap agreements.
As EME continues to expand into foreign markets, fluctuations in foreign
currency exchange rates will continue to affect the amount of its equity
contributions to, distributions from, and results of operations for its
foreign projects. EME has hedged a portion of its current exposure to
fluctuations in foreign exchange risks, where it deems appropriate,
through offsetting obligations denominated in foreign currencies, and
indexing underlying project agreements to US dollars or other indices
reasonably expected to correlate with foreign exchange movements.
Projected Capital Requirements
Edison International's projected capital requirements for the next five
years are: 1996--$781 million; 1997--$932 million; 1998--$831 million;
1999--$773 million; and 2000--$790 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1996, are: 1997--$546
million; 1998--$406 million; 1999--$520 million; 2000--$437 million; and
2001--$543 million.
REGULATORY MATTERS
SCE's 1996 CPUC-authorized revenue decreased $575 million, or 7.5%,
including a one-time bill credit of $237 million (which had no impact on
operating income) for lower fuel costs than originally estimated. The
remaining $338 million revenue reduction is primarily for a $242 million
decrease in fuel costs, a $53 million decrease for lower costs of debt and
equity (discussed below), a $24 million decrease for lower nuclear
refueling costs and a $9 million decrease related to the 1995 general rate
case (discussed below).
On January 10, 1996, the CPUC issued its decision on SCE's 1995 general
rate case. The decision affirmed the CPUC's interim order to reduce 1995
operating revenue by $67 million, but decreased 1996 operating revenue by
an additional $9 million, which includes a decrease of $44 million for
operating and maintenance expenses. The decision also authorized recovery
of SCE's remaining investment (approximately $2.7 billion) in San Onofre
Units 2 and 3 at a reduced rate of return over an eight-year period. In
April 1996, SCE began accelerating the recovery of its remaining
investment of $2.6 billion. The accelerated recovery will continue
through December 2001 (the original end date of 2003 was changed by
legislation enacted in September 1996), earning a 7.35% fixed rate of
return (compared to the current 9.55%). Future operating costs, including
nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures at San Onofre Units 2 and 3 are subject to an incentive
pricing plan, through which SCE receives about 4 cents per kilowatt-hour
through 2003. Any differences between these costs and the incentive price
will flow through to shareholders. Beginning in 2004, SCE would be
required to share equally with ratepayers the benefits received from
operation of the units.
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The CPUC's 1996 cost-of-capital decision authorized an increase to SCE's
equity ratio from 47.75% to 48% and authorized SCE an 11.6% return on
common equity, compared to 12.1% for 1995. This decision, excluding the
effects of other rate actions, would reduce 1996 earnings by approximately
4 cents per share. On August 27, 1996, SCE agreed to terms regarding key
components of its 1997 cost-of-capital. The agreement provides that SCE
will continue to receive the same 11.6% return on common equity as well
as maintain its equity ratio at 48%. Final approval by the CPUC is
expected in November 1996.
On August 13, 1996, Edison Source, the unregulated energy subsidiary of
Edison International, received approval from the FERC to sell wholesale
power at market-based rates.
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the CPUC's
Organization (formerly Division) of Ratepayer Advocates (ORA) which
resulted in a $39 million (including interest) refund to SCE's customers
beginning in August 1996. As of September 30, 1996, approximately $32.7
million has been refunded to customers via a bill credit. The remainder
will be refunded by year-end. This refund has been fully reflected in the
financial statements.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA filed its report on the reasonableness of SCE's gas supply costs
for both the 1993 and 1994 record periods. The report recommends a
disallowance of $13.3 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. SCE and the ORA have filed several rounds of testimony on
this issue. Hearings are scheduled for early 1997.
In February 1996, SCE filed a proposal with the CPUC requesting a new rate
mechanism for its 15.8% share of the three units at Palo Verde. The
proposed rate mechanism would allow SCE to accelerate the recovery of its
share of Palo Verde's sunk cost (forecast to be $1.2 billion as of
December 31, 1996) over a seven-year period, beginning January 1, 1997,
and ending in 2003. During the seven-year period, SCE's return on rate
base for Palo Verde's sunk cost would be reduced to 7.35% from the current
9.55%. In addition, SCE proposed an incentive pricing plan to recover the
incremental costs of continued operation of Palo Verde at approximately
3.4 cents per kilowatt-hour, provided the Palo Verde units operate at an
average capacity factor of 77%. The legislation has accelerated the
proposed recovery period to five years (1997-2001). On November 1, 1996,
all of the active parties to the Palo Verde proceeding signed a Memorandum
of Understanding (MOU) which will form the basis for a definitive
settlement agreement. The portion of the MOU concerning accelerated
recovery of Palo Verde's sunk costs is consistent with SCE's proposal,
as modified by the legislation enacted in September 1996. However,
instead of the incremental cost incentive pricing proposed by SCE, the MOU
proposes to pass-through Palo Verde incremental costs to ratepayers
through a balancing account. These costs will be considered reasonable
so long as they do not exceed 30% of a baseline forecast and the site's
capacity factor does not go below 55%. The existing nuclear unit
incentive procedure will continue only for purposes of calculating a
reward for performance of any unit above an 80% capacity factor for a fuel
cycle. For post-2001 operations, SCE's ratepayers will receive 50% of the
operational benefits. A definitive settlement agreement is expected to
be filed with the CPUC in late 1996 with a decision expected in late 1996
or early 1997.
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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 regulation.
In December 1995, the CPUC issued its decision on restructuring
California's electric industry, which it had been considering since April
1994. The new market structure would provide competition and customer
choice. The transition to a competitive electric market would begin
January 1, 1998, with all consumers participating by 2003. However, the
legislation enacted in September 1996 (discussed below) specifies that all
customers should be eligible to participate through direct transactions
in the competitive market, no later than January 1, 2002. Key elements
of the CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from, and sell to, the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore, to
control the scheduling and dispatch of all electricity on the state's
power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
o Recovery of costs to transition to a competitive market (utility
investments and obligations incurred to serve customers under the
existing framework) through a non-bypassable charge, applied to all
customers, called the competition transition charge (CTC).
o CPUC-established incentives to encourage voluntary divestiture (through
spin-off or sale to an unaffiliated entity) of at least 50% of
utilities' gas-fueled generation to address market power issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
On September 20, 1996, the CPUC adopted a non-generation (transmission and
distribution - T&D) PBR mechanism for SCE beginning 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 to inflation based on the Consumer Price
Index; 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. On July 15, 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. If approved, the
hydro PBR would be in effect for three years and the initial terms of the
local reliability contracts, which are subject to FERC approval, would be
in effect for up to three years, both beginning January 1, 1998. A final
CPUC decision on hydro PBR is expected by year-end 1997.
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In March 1996, SCE filed a plan outlining how it would propose to divest
50% of its gas-fueled generation. SCE's plan is contingent on assurances
about transition cost recovery and the resolution of key issues related
to: worker protection measures being in place for utility employees who
could suffer hardship as a result of divestiture; utilities being
permitted full recovery of the transition costs incurred during the
divestiture process; appropriate rate-making measures to cover the
contingency if the completion of the divestiture plan or commencement of
the PX is delayed; and prudently incurred costs associated with fuel
supply, transportation and storage contracts not being stranded by the
divestiture.
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 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 would be backed by
utility guarantees and SCE's share would be 45%. Once the ISO and PX are
formed, they 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 funding it with $250 million in
order to build the hardware and software systems for the ISO and PX.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public goods programs and the CTC. The filing is in
response to CPUC and FERC directives that electric services, such as T&D,
be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers.
On August 30, 1996, in compliance with the CPUC's restructuring decision,
SCE filed its application to estimate its 1998 transition costs. On
October 21, 1996, SCE amended its transition cost filing to reflect the
effects of the legislation enacted in September 1996, discussed below.
Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting components for the PX, T&D,
nuclear decommissioning, and public benefits 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 $11.9 billion (1997 net present value),
assuming the fossil plants have a market value equal to the net book
value, and $12.6 billion (1997 net present value), assuming the fossil
plants have no market value. These estimates are based on incurred costs
and forecasts of future costs and assumed market prices. However, changes
in the assumed market price could require material revisions to such
estimates. The potential transition costs are comprised of: $6.8 billion
from SCE's qualifying facility contracts, which are the direct result of
legislative and regulatory mandates; and $5.1 billion to $5.8 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 nuclear plants (including San Onofre Unit 1 as discussed in Note 1 and
San Onofre Units 2 and 3 as discussed above) and Palo Verde Units 1, 2 and
3, nuclear decommissioning and certain other costs.
On September 23, 1996, the State of California enacted legislation to
provide a rapid, but orderly, transition to a competitive market
structure. The legislation substantially adopts the CPUC's December 1995
restructuring decision (previously discussed) by favorably addressing
stranded-cost recovery for utilities, 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
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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, allowing SCE to give a rate reduction of at
least 10% to these customers, beginning January 1, 1998. The financing
would occur with securities issued by the California Infrastructure and
Economic Development Bank, or an entity approved by the Bank. The
legislation includes a rate freeze for all other customers, including
large commercial and industrial customers, as well as provisions for
continued funding for energy conservation, low-income programs and
renewable resources. Despite the rate freeze, SCE expects to be able to
recover its revenue requirement based on cost-of-service regulation during
the 1998-2001 period. In addition, the legislation mandates the
implementation of a CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Finally, the
legislation contains provisions for the recovery (through 2006) of
reasonable employee-related transition costs incurred and projected for
retraining, severance, early retirement, outplacement, and related
expenses for utility workers. The legislation also presents substantial
challenges to SCE related to the stranded cost recovery that must be
completed by 2001, while still maintaining a rate freeze for some
customers and a rate reduction for others.
In light of the legislation, the CPUC is reassessing the need to prepare
an environmental impact report. If the CPUC's restructuring is
implemented as outlined, SCE would be allowed to recover its CTC (subject
to a lower return on equity) and would continue to apply accounting
standards that recognize the economic effects of rate regulation for its
generation-related assets during the rate recovery period. The effect of
such an outcome would not be expected to materially affect SCE's results
of operations or financial position during the transition period.
If, during the restructuring process, events occur that result in SCE no
longer meeting the criteria to apply regulatory accounting standards to
its generation operations, SCE may be required to write off its recorded
generation-related regulatory assets. At September 30, 1996, these
amounts totaled approximately $1.0 billion, primarily for the recovery of
income tax benefits previously flowed-through to customers, the Palo Verde
phase-in plan and unamortized loss on reacquired debt. 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.
Additionally, 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 Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, which it had been considering since March 1995.
The decision, which became effective in July 1996, 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 recovery of stranded costs, which are prior-service costs incurred
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under the current regulatory framework. In addition to providing recovery
of stranded costs associated with existing wholesale customers, the FERC
directed that it would have primary jurisdiction over the recovery of
stranded costs associated with retail-turned-wholesale customers, such as
the formation of a new municipal electric system. Retail stranded costs
resulting from a state-authorized retail direct-access program are the
responsibility of the states and the FERC would only address recovery of
these costs if the state has no authority to do so. In compliance with
the April 1996 FERC decision, SCE filed a revised open access tariff with
the FERC on July 9, 1996. The tariff became effective, on an interim
basis, subject to refund, as of its filing date. Several wholesale
customers have filed protests with the FERC on the transmission rate
levels, and a ruling from the FERC setting the rates for formal hearing
is anticipated by the end of 1996 or early in 1997.
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 to the Consolidated Financial Statements,
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. Unless there is a
probable amount, Edison International records the lower end of this
reasonably likely range of costs.
Edison International's recorded estimated minimum liability to remediate
its 61 identified sites (58 at SCE and 3 at EME) was $114 million at September
30, 1996. One of SCE's sites, a former pole-treating facility, is
considered a federal Superfund site and represents 71% 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
$215 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 35 of its
sites, representing $95 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
this remaining 10%, with the opportunity to recover these costs from
insurance carriers and other third parties. SCE has successfully settled
insurance claims with a number of its carriers and is no longer pursuing
any additional recoveries. Costs incurred at SCE's remaining 23 sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $104 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates.
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 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 $8 million.
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In 1994, SCE utilized an estimating technique to quantify its potential
liability for environmental cleanup in an effort to obtain a reasonably
possible objective and reliable estimate of environmental cleanup. During
1995, EME completed a similar review of some of its sites where known
contamination and potential liability exist, and does not believe that a
material liability exists as of September 30, 1996.
Based on currently available information, Edison International believes
it is not likely 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 have a material adverse effect on its results
of operations or financial position. There can be no assurance, however,
that future developments, including additional information about existing
sites or the identification of new sites, will not require material
revisions to such estimates.
The 1990 federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions
allowances from the federal government and may bank or sell excess
allowances. SCE expects to have excess allowances under Phase II of the
Clean Air Act (2000 and later). The act also calls for a study to
determine if additional regulations are needed to reduce regional haze in
the southwestern US In addition, another study is underway 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 $653 million for the 1996-2000 period, mainly for
aesthetics treatment, including undergrounding certain transmission and
distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects is receiving increased
attention. The scientific community has not yet reached a consensus on
the nature of any health effects of EMF. However, the CPUC has issued a
decision which provides for a rate-recoverable research and public
education program conducted by California electric utilities, and
authorizes these utilities to take no-cost or low-cost steps to reduce EMF
in new electric facilities. SCE is unable to predict when or if the
scientific community will be able to reach a consensus on any health
effects of EMF, or the effect that such a consensus, if reached, could
have on future electric operations.
PALO VERDE STEAM TUBE RUPTURE
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in only one of the units will have to be replaced within five
to ten years. Based on APS' 100% share estimate, SCE estimates its share
of the costs to be between $22 million and $24 million, plus replacement
power costs which are subject to CPUC reasonableness review. SCE is
evaluating APS' analyses, conducting its own review, and has not yet
decided whether it supports replacement of the steam generators.
WORKFORCE REDUCTIONS
During third quarter 1996, SCE decided not to outsource certain operations
and reversed a $40 million charge it had accrued in the previous quarter.
During the third quarter, an additional $12 million was accrued as a
charge against earnings for a voluntary retirement program for represented
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employees (these employees voted to accept SCE's voluntary retirement
package in August 1996 and elections became irrevocable on September 30,
1996). SCE expects to reduce its workforce by approximately 3,400
employees (2,400 non-represented and 1,000 represented employees) by
year-end 1996. SCE has expensed a total of $26 million in 1996 for
workforce reductions associated with its voluntary retirement program.
Proposed New Accounting Standard
The Financial Accounting Standards Board (FASB) has issued an exposure
draft, which 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 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 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
financial positions or results of operations.
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PART II--OTHER INFORMATION
Item 1. Legal Proceedings
Qualifying Facilities ("QF") Litigation
On May 20, 1993, four geothermal QFs filed a lawsuit against Southern
California Edison Company ("SCE") in Los Angeles County Superior Court,
claiming that SCE underpaid, and continues to underpay, the plaintiffs for
energy. SCE denied the allegations in its response to the complaint. The
action was brought on behalf of Vulcan/BN Geothermal Power Company, Elmore
L.P., Del Ranch L.P., and Leathers L.P., each of which was partially owned
by a subsidiary of Edison Mission Energy ("EME") (a subsidiary of Edison
International) until April of this year when EME sold its interests in the
projects to its nationwide partner. 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 alleged that the past underpayments
totaled at least $21,000,000. In other court filings, plaintiffs have
contended that the total amount of additional contract payments owing from
the beginning of the alleged underpayments through the end of the contract
term could total approximately $60,000,000. In addition to seeking
compensatory damages and declaratory relief, the fourth amended complaint
also seeks unspecified punitive damages and an injunction to enjoin SCE
from "future" unfair competition. After a number of continuances, the
matter was set for trial on June 18, 1996. On May 1, 1996, the parties
entered into an agreement providing for a settlement of all claims in
dispute. Pursuant to the agreement, the specific terms of which are
confidential, SCE has paid a settlement amount jointly to the plaintiffs
and the parties have resolved all claims prior to January 1, 1996. SCE
intends to seek recovery of this payment in its annual Energy Cost
Adjustment Clause ("ECAC") filing. 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 retained the right to
continue the lawsuit as to the period after December 31, 1995, in the
event CPUC approval of the increased payments 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. The application is
currently pending.
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 $189,000,000 in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
County 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. In March 1995, a ninth lawsuit was filed in the Los
Angeles County Superior Court raising claims similar to those alleged in
the first seven cases in that court. SCE has 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 issue a writ directing the Los
Angeles Superior Court to vacate its March 1 order granting summary
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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. A pending summary adjudication motion in the
Kern County case has been withdrawn in light of the Court of Appeal
decision. Furthermore, pursuant to stipulation of the parties, the Kern
County case was ordered on April 3, 1996, to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. As a result
of the coordination, the April 22, 1996, trial date for the Kern County
case was stricken. On February 6, 1996, plaintiffs in one of the actions
filed their first amended and supplemental complaint. On March 6, 1996,
SCE filed its new answer, denying the material allegations of the first
amended and supplemental complaint. On April 16, 1996, SCE filed a motion
for summary adjudication of certain of the causes of action in this
complaint. After hearing, the motion was denied without prejudice.
Plaintiffs' motion to consolidate all eight Los Angeles cases for jury
trial was denied without prejudice on March 25, 1996. However, SCE and
all of the plaintiffs, with the exception of Flowind Corporation,
subsequently entered into a court-approved stipulation whereby the cases
involving the stipulating plaintiffs have been consolidated for trial
commencing on January 27, 1997, in return for these plaintiffs' waiver of
a jury trial. No trial date has been established for Flowind
Corporation's claims. The materiality of final judgments in favor of the
plaintiffs in these cases would be largely dependent on the extent to
which any damages or additional payments which might result from such
judgments would be recoverable through SCE's ECAC.
This matter was previously reported under the heading "QF Litigation" in
Part I, Item 3 of SCE's Annual Report on Form 10-K for the year ended
December 31, 1995, and the Quarterly Reports on Form 10-Q for the periods
ended March 31, 1996, and June 30, 1996.
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
denies the material allegations in its responses to each of the lawsuits.
Two of the lawsuits allege, among other things, that certain past and
present employees of Grubb & Ellis ("Employee-Plaintiffs"), a real estate
brokerage firm with offices located in a commercial building known as the
Koll Center in Newport Beach, developed cancer as a result of exposure to
EMF from electrical facilities owned by SCE and/or the other defendants
located on the property. The lawsuits, served on SCE in 1994 ("First
Case") and January 1995 ("Second Case"), respectively, also name Grubb &
Ellis and the owners and developers of the Koll Center as defendants. No
specific damage amounts are alleged in either complaint.
The five named plaintiffs in the First Case, three Employee-Plaintiffs and
the spouses of two of them, allege compensatory damages of $8,000,000 plus
unspecified punitive damages, according to supplemental documentation they
have prepared. In December, 1995 the court granted SCE's motion for
summary judgment and dismissed the case. Plaintiffs have filed a Notice
of Appeal. A briefing schedule for the appeal has been established, but
no date for oral argument has been set.
Supplemental documentation prepared by the four named plaintiffs in the
Second Case, two Employee-Plaintiffs and their respective spouses,
indicates they allege compensatory damages of approximately $13,500,000
plus unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed
a cross-complaint against the other codefendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. This case has been stayed pending
appellate review of the trial judge's sanction order against the
plaintiffs' attorneys. The Court of Appeals has set oral argument on this
issue for January 21, 1997.
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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 facilities 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 $5,500,000, plus unspecified
punitive damages. No trial date has been set in this case.
These matters were previously reported under the heading "Environmental
Litigation" in Part I, Item 3 of SCE's Annual Report on Form 10-K for the
year ended December 31, 1995, and the Quarterly Reports on Form 10-Q for
the periods ended March 31, 1996, and June 30, 1996.
San Onofre Personal Injury Litigation
An engineer for two contractors providing services for San Onofre has been
diagnosed with chronic myelogenous leukemia. On July 12, 1994, the
engineer and his wife sued SCE, San Diego Gas and Electric Company
("SDG&E") and Combustion Engineering, the manufacturer of the fuel rods
for the plant, in the United States District Court for the Southern
District of California. The plaintiffs alleged that the engineer's
illness resulted from contact with radioactive fuel particles released
from failed fuel rods. SCE's December 23, 1994, answer to the complaint
denied all material allegations. Trial began on August 3, 1995, and on
October 12, 1995, an eight-member jury unanimously decided that radiation
exposure at San Onofre was not the cause of the leukemia. Plaintiffs'
motion for a new trial was denied on December 5, 1995. On August 15,
1996, the plaintiffs' appeal of the denial of their motion was denied by
the Ninth Circuit Court of Appeals. Plaintiffs have until November 13,
1996, to file a petition for writ of certiorari with the U.S. Supreme
Court.
A SCE engineer employed at San Onofre died in 1991 from cancer of the
abdomen. On February 6, 1995, his children sued SCE, SDG&E and Combustion
Engineering in the United States District Court for the Southern District
of California. The plaintiffs allege that the engineer's illness resulted
from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles. Plant records show
that the engineer's exposure to radiation was well below NRC safety
levels. In the complaint, plaintiffs sought unspecified compensatory and
punitive damages.
On April 3, 1995, the Court granted the defendants' motion to dismiss 14
of plaintiffs' 15 claims. Punitive damages are not available under the
remaining claim. SCE's April 20, 1995, answer to the complaint denied all
material allegations. On October 10, 1995, the Court ruled in favor of
plaintiffs' request 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 July 29, 1996, the court
entered judgment in favor of SCE dismissing the remaining claim.
Plaintiffs filed a notice of appeal of this decision to the Ninth Circuit
Court of Appeals on August 22, 1996. Trial of the case against the other
defendants has been stayed by the court until there are final
determinations on any appeals from the judgment entered in favor of SCE
and from a number of other orders. The impact on SCE, if any, from
further proceedings in this case against the remaining defendants cannot
be determined at this time.
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On July 5, 1995, a former SCE reactor operator employed at San Onofre and
his wife sued SCE, SDG&E, Combustion Engineering and the Institute of
Nuclear Power Operations in the U.S. District Court for the Southern
District of California. Plaintiffs allege the former employee's acute
myelogenous leukemia resulted from, and was aggravated by, exposure to
radiation at San Onofre, including contact with radioactive fuel
particles. The former employee subsequently died from his illness.
Plaintiffs seek unspecified compensatory and punitive damages. On March
25, 1996, the court granted SCE's motion for summary judgment on all
claims. Plaintiffs filed a notice of appeal of this decision to the
Ninth Circuit Court of Appeals on September 25, 1996. In addition, the
court stayed all further trial court proceedings until there are final
determinations on any appeals in this case and in the case described
immediately above. Should plaintiffs do so, trial of the case may be
delayed 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 August 31, 1995, the family of a former worker for a contractor at San
Onofre, and later a temporary and then a permanent SCE employee at San
Onofre, sued SCE, SDG&E, Combustion Engineering and the Institute of
Nuclear Power Operations in the U.S. District Court for the Southern
District of California. Plaintiffs allege the former employee's acute
myelogenous leukemia, which resulted in his death in 1994, resulted from,
and was aggravated by, exposure to radiation at San Onofre, including
contact with radioactive fuel particles. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's answer to the complaint filed
on November 13, 1995, denied all material allegations. On August 1, 1996,
the court stayed all further trial court proceedings until there are final
determinations on any appeals from the judgments entered in favor of SCE
in the two cases mentioned immediately above.
On November 17, 1995, a SCE employee and his wife sued SCE in the U.S.
District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering, the manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs allege that the employee transported radioactive
byproducts on his person, clothing and/or tools to his home where his wife
was then exposed to radiation that caused her leukemia. Plaintiffs seek
unspecified compensatory and punitive damages. SCE's December 19, 1995,
partial answer to the complaint denied all material non-employment related
allegations. SCE's motion to dismiss the claims of the employee was
granted on March 19, 1996. The employee's wife subsequently died from her
illness. This case is expected to go to trial in March 1997.
On November 28, 1995, a former contract worker at San Onofre, her husband,
and her son, sued SCE in the U.S. District Court for the Southern District
of California. Plaintiffs also named Combustion Engineering, the
manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege
that the former contract worker transported radioactive byproducts on her
person and clothing to her home where her son was then exposed to
radiation that caused his leukemia. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's January 2, 1996, answer to the
complaint 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, after completion of the trial of the
case described immediately above, in mid-1997.
On February 20, 1996, an individual employed by various contractors
intermittently at San Onofre from 1984 to 1993, and who was employed by
SCE as a temporary security officer in 1994, sued SCE in Orange County
municipal court for undiagnosed injuries he allegedly sustained as a
result of radiation exposure at San Onofre. In the complaint, plaintiff
seeks $25,000 in compensatory damages. This case was removed to the U.S.
District for the Southern District of California. SCE's answer to the
complaint, filed on July 2, 1996, denied all material allegations. This
case was dismissed with prejudice on October 11, 1996.
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With the exception of the last of the above-mentioned matters, these
matters were previously reported under the heading "San Onofre Personal
Injury Litigation" in Part I, Item 3 of SCE's Annual Report on Form 10-K
for the year ended December 31, 1995, and the Quarterly Reports on Form
10-Q for the periods ended March 31, 1996, and June 30, 1996.
Employment Discrimination Litigation
On September 21, 1994, nine African-American employees filed a lawsuit
against Edison International and SCE on behalf of an alleged class of
African-American employees, alleging racial discrimination in job
advancement, pay, training and evaluation. The lawsuit was filed in the
United States District Court for the Central District of California. The
plaintiffs sought injunctive relief, as well as an unspecified amount of
compensatory and punitive damages, attorneys' fees, costs and interest.
Edison International and SCE denied the material allegations of the
complaint, asserted several affirmative defenses, and pursued discovery.
On May 2, 1996, SCE and the Equal Employment Opportunity Commission
("EEOC") stipulated to the EEOC's intervention in the action.
Subsequently, on May 9, 1996, the Court entered an order allowing the EEOC
to intervene.
Following extensive negotiations, the parties agreed upon settlement terms
and submitted a proposed Consent Decree to the court for approval. On May
13, 1996, the Court granted the parties' Joint Motion for Preliminary
Approval of Consent Decree, preliminarily accepting the proposed Consent
Decree, provisionally certifying the case as a class action, and approving
notice to the class members. On July 22, 1996, at the hearing on final
approval of the Consent Decree, the court raised issues that resulted in
the parties' agreement to modify the proposed Consent Decree. The court
then granted preliminary approval of the modified Consent Decree on August
5, 1996, ordered that notice be given to the class members, and scheduled
a final fairness hearing for September 26, 1996.
Fifteen individuals and an organization filed objections to the proposed
Consent Decree and a motion to intervene in the lawsuit. Thirteen
individuals filed timely requests to be excluded from the monetary
provisions of the proposed Decree. On September 25, 1996, the court
denied the motion to intervene. After the hearing on September 26, at
which the court heard oral argument from the objectors, the court on
September 30, 1996, overruled the objections and granted final approval
of the Consent Decree.
The Consent Decree provides that a settlement fund of $8,150,000 for back
pay claims and $3,100,000 for emotional distress claims be established,
and it contains an expedited claim review process for class members who
make claims to the settlement fund. The Decree also provides for
improvements in the Company's internal claims resolution process,
expansion of career development and skills training programs, expansion
of diversity training programs, and improvements in other human resources
systems. The Decree has a seven-year term, with the possibility of early
termination after five years.
On October 25, 1996, the organization and individuals who sought to
intervene and/or objected to the Consent Decree served notices of appeal
from the court's orders denying intervention and approving the Consent
Decree.
This matter was previously reported under the heading "Employment
Discrimination Litigation" in Part I, Item 3 of SCE's Annual Report on
Form 10-K for the year ended December 31, 1995, and the Quarterly Reports
on Form 10-Q for the periods ended March 31, 1996, and June 30, 1996.
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
page 30
<PAGE>
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 $300,000,000. Additionally,
plaintiff seeks treble and punitive damages.
Unless the filing deadline is extended, SCE's response to the complaint
is due on or before November 25, 1996. SCE intends to deny the material
allegations of the complaint. This matter has not been previously
reported.
page 31
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
27. Financial Data Schedule
(b) Reports on Form 8-K:
October 3, 1996 -- Item 5 -- Other Events--
Governor Signs Restructuring Legislation
CPUC Incentive-Based Rate Decision
-- Edison International Board of Directors
Increase Share Repurchase Authorization
page 32
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By R. K. BUSHEY
-----------------------------
R. K. BUSHEY
Vice President and Controller
By K. S. STEWART
-----------------------------
K. S. STEWART
Assistant General Counsel
November 12, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Edison International Exhibit 27 Financial Data Schedule
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,865,705
<OTHER-PROPERTY-AND-INVEST> 6,766,915
<TOTAL-CURRENT-ASSETS> 3,122,996
<TOTAL-DEFERRED-CHARGES> 3,118,222
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 24,873,838
<COMMON> 2,629,471
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 3,864,841
<TOTAL-COMMON-STOCKHOLDERS-EQ> 6,494,312
425,000
283,755
<LONG-TERM-DEBT-NET> 3,461,324
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 3,604,621
<COMMERCIAL-PAPER-OBLIGATIONS> 368,075
<LONG-TERM-DEBT-CURRENT-PORT> 546,779
0
<CAPITAL-LEASE-OBLIGATIONS> 65,066
<LEASES-CURRENT> 16,250
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,608,656
<TOT-CAPITALIZATION-AND-LIAB> 24,873,838
<GROSS-OPERATING-REVENUE> 6,349,583
<INCOME-TAX-EXPENSE> 467,555
<OTHER-OPERATING-EXPENSES> 4,732,107
<TOTAL-OPERATING-EXPENSES> 5,199,662
<OPERATING-INCOME-LOSS> 1,149,921
<OTHER-INCOME-NET> (59,523)
<INCOME-BEFORE-INTEREST-EXPEN> 1,090,398
<TOTAL-INTEREST-EXPENSE> 455,134
<NET-INCOME> 635,264
35,626
<EARNINGS-AVAILABLE-FOR-COMM> 599,638
<COMMON-STOCK-DIVIDENDS> 329,165
<TOTAL-INTEREST-ON-BONDS> 286,252
<CASH-FLOW-OPERATIONS> 1,877,918
<EPS-PRIMARY> $1.36
<EPS-DILUTED> $1.36
</TABLE>
