<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 March 31, 1997
---------------------------------------
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
---------------- -----------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 999)
Rosemead, California
(Address of principal 91770
executive offices) (Zip Code)
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 May 13, 1997
- -------------------------- ---------------------------
Common Stock, no par value 410,126,374
PAGE
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EDISON INTERNATIONAL
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income--Three
Months Ended March 31, 1997, and 1996 2
Consolidated Balance Sheets--March 31, 1997
and December 31, 1996 3
Consolidated Statements of Cash Flows--Three Months
Ended March 31, 1997, and 1996 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 14
Part II. Other Information:
Item 1. Legal Proceedings 27
Item 4. Submission of Matters to a Vote of Security Holders 32
Item 6. Exhibits and Reports on Form 8-K 32
page 1
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EDISON INTERNATIONAL
PART I--FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
3 Months Ended
March 31,
-------------------------
1997 1996
---------- ----------
(Unaudited)
Electric utility revenue $1,695,401 $1,760,134
Diversified operations 305,324 207,520
---------- ----------
Total operating revenue 2,000,725 1,967,654
---------- ----------
Fuel 200,233 143,178
Purchased power 628,674 527,433
Provisions for regulatory adjustment
clauses -- net (88,173) 97,823
Other operating expenses 330,270 329,860
Maintenance 96,155 84,113
Depreciation and decommissioning 340,121 264,527
Income taxes 96,076 111,477
Property and other taxes 40,309 59,686
---------- ----------
Total operating expenses 1,643,665 1,618,097
---------- ----------
Operating income 357,060 349,557
---------- ----------
Provision for rate phase-in plan (11,309) (29,078)
Allowance for equity funds used
during construction 2,003 4,402
Interest and dividend income 15,842 15,327
Minority interest (27,965) (13,724)
Other nonoperating income -- net (2,862) 8,465
---------- ----------
Total other income (deductions) -- net (24,291) (14,608)
---------- ----------
Income before interest and other expenses 332,769 334,949
---------- ----------
Interest on long-term debt 152,425 150,986
Other interest expense 31,259 23,761
Allowance for borrowed funds used
during construction (2,412) (2,767)
Capitalized interest (5,177) (15,998)
Dividends on subsidiary preferred
securities 11,862 11,878
---------- ----------
Total interest and other expenses -- net 187,957 167,860
---------- ----------
Net income $ 144,812 $ 167,089
========== ==========
Weighted-average shares of common stock
outstanding 419,665 443,626
Earnings per share $0.35 $0.38
Dividends declared per common share $0.25 $0.25
The accompanying notes are an integral part of these financial statements.
page 2
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
March 31, December 31,
1997 1996
------------- -----------
(Unaudited)
ASSETS
Utility plant, at original cost $20,537,877 $20,400,387
Less -- accumulated provision for
depreciation and decommissioning 9,687,121 9,431,071
----------- -----------
10,850,756 10,969,316
Construction work in progress 525,265 556,645
Nuclear fuel, at amortized cost 185,411 176,827
----------- -----------
Total utility plant 11,561,432 11,702,788
----------- -----------
Nonutility property -- less
accumulated provision for
depreciation of $217,825 and $203,256
at respective dates 3,492,640 3,570,237
Nuclear decommissioning trusts 1,499,836 1,485,525
Investments in partnerships and
unconsolidated subsidiaries 1,483,991 1,371,824
Investments in leveraged leases 587,654 584,515
Other investments 115,470 103,973
----------- -----------
Total other property and investments 7,179,591 7,116,074
----------- -----------
Cash and equivalents 733,392 896,594
Receivables, including unbilled
revenue, less allowances of
$24,677 and $26,230 for uncollectible
accounts at respective dates 945,942 1,094,498
Fuel inventory 58,626 72,480
Materials and supplies, at average cost 153,458 154,266
Accumulated deferred income taxes -- net 167,699 240,429
Prepayments and other current assets 66,757 113,654
----------- -----------
Total current assets 2,125,874 2,571,921
----------- -----------
Unamortized debt issuance and
reacquisition expense 339,654 346,834
Rate phase-in plan 40,013 50,703
Income tax-related deferred charges 1,691,963 1,741,091
Other deferred charges 1,007,911 1,029,203
----------- -----------
Total deferred charges 3,079,541 3,167,831
----------- -----------
Total assets $23,946,438 $24,558,614
=========== ===========
The accompanying notes are an integral part of these financial statements.
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EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
March 31, December 31,
1997 1996
------------- -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
Common shareholders' equity:
Common stock (414,681,238 and 424,524,178
shares outstanding at respective dates) $ 2,491,241 $ 2,547,403
Cumulative translation adjustments -- net 36,997 63,898
Unrealized gain in equity investments -- net 40,625 33,382
Retained earnings 3,639,305 3,752,549
----------- -----------
6,208,168 6,397,232
Preferred securities of subsidiaries:
Not subject to mandatory redemption 283,755 283,755
Subject to mandatory redemption 425,000 425,000
Long-term debt 7,246,771 7,474,679
----------- -----------
Total capitalization 14,163,694 14,580,666
----------- -----------
Other long-term liabilities 452,048 423,925
----------- -----------
Current portion of long-term debt 505,047 592,143
Short-term debt 438,192 397,098
Accounts payable 372,431 437,657
Accrued taxes 580,532 530,365
Accrued interest 134,488 131,079
Dividends payable 106,102 108,563
Regulatory balancing accounts -- net 106,505 181,488
Deferred unbilled revenue and other
current liabilities 1,069,931 1,059,240
----------- -----------
Total current liabilities 3,313,228 3,437,633
----------- -----------
Accumulated deferred income
taxes -- net 4,204,855 4,283,219
Accumulated deferred investment
tax credits 366,976 372,377
Customer advances and other
deferred credits 752,946 753,755
----------- -----------
Total deferred credits 5,324,777 5,409,351
----------- -----------
Minority interest 692,691 707,039
----------- -----------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $23,946,438 $24,558,614
=========== ===========
The accompanying notes are an integral part of these financial statements.
page 4
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EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
3 Months Ended
March 31,
------------------------
1997 1996
--------- -----------
(Unaudited)
Cash flows from operating activities:
Net income $ 144,812 $ 167,089
Adjustments for non-cash items:
Depreciation and decommissioning 340,121 264,527
Amortization 13,580 28,969
Rate phase-in plan 10,690 28,345
Deferred income taxes and investment tax
credits 54,117 (17,494)
Equity in income from partnerships and
unconsolidated subsidiaries (40,113) (24,907)
Other long-term liabilities 28,123 29,610
Other -- net (23,775) (6,432)
Changes in working capital:
Receivables 103,643 105,325
Regulatory balancing accounts (74,983) 101,487
Fuel inventory, materials and supplies 14,662 3,948
Prepayments and other current assets 46,897 49,084
Accrued interest and taxes 53,882 142,053
Accounts payable and other current
liabilities (89,060) (120,681)
Distributions from partnerships and
unconsolidated subsidiaries 20,672 15,302
---------- ----------
Net cash provided by operating activities 603,268 766,225
---------- ----------
Cash flows from financing activities:
Long-term debt issued 5,677 1,048,518
Long-term debt repayments (271,567) (1,027,633)
Common stock issued 3,943 653
Common stock repurchases (214,492) -
Nuclear fuel financing -- net 6,031 (8,437)
Short-term debt financing -- net 31,415 (100,973)
Dividends paid (112,018) (110,911)
Other -- net 3,324 -
---------- ----------
Net cash used by financing activities (547,687) (198,783)
---------- ----------
Cash flows from investing activities:
Additions to property and plant (158,008) (232,402)
Funding of nuclear decommissioning trusts (27,889) (35,975)
Investments in partnerships and
unconsolidated subsidiaries (14,234) (96,266)
Unrealized gain in equity investments--net 7,243 3,632
Other -- net (25,895) 9,115
---------- ----------
Net cash used by investing activities (218,783) (351,896)
---------- ----------
Net increase (decrease) in cash and
equivalents (163,202) 215,546
Cash and equivalents, beginning of period 896,594 507,151
---------- ----------
Cash and equivalents, end of period $ 733,392 $ 722,697
========== ==========
The accompanying notes are an integral part of these financial statements.
page 5
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments have been made that are
necessary to present a fair statement of the financial position and
results of operations for the periods covered by this report.
Edison International's significant accounting policies were described in
Note 1 of "Notes to Consolidated Financial Statements" included in its
1996 Annual Report on Form 10-K filed with the Securities and Exchange
Commission. Edison International follows the same accounting policies for
interim reporting purposes. This quarterly report should be read in
conjunction with Edison International's 1996 Annual Report.
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on reported earnings per share.
Certain prior-period amounts were reclassified to conform to the March 31,
1997, financial statement presentation.
Note 1. Regulatory Matters
California Electric Utility Industry Restructuring
The California Public Utilities Commission's (CPUC) December 1995 decision
on restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the competition transition charge (CTC).
In September 1996, the State of California enacted legislation to provide
a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision by
addressing stranded-cost recovery for utilities, and providing a certain
cost-recovery time period for the transition costs associated with
utility-owned generation-related assets. Transition costs related to
power-purchase contracts would be recovered through the terms of their
contracts while most of the remaining transition costs would be recovered
through 2001. The legislation also includes provisions to finance a
portion of the stranded costs that residential and small commercial
customers would have paid between 1998 and 2001, which would allow
Southern California Edison Company (SCE), a subsidiary of Edison
International, to reduce rates by at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of a
non-bypassable CTC that provides utilities the opportunity to recover
page 6
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
On May 6, 1997, SCE filed an application with the CPUC requesting approval
of the issuance of an aggregate amount of up to $3 billion of rate
reduction bonds in one or more series or classes and a 10% rate reduction
for the period from January 1, 1998, through May 31, 2002. On the same
day, SCE filed an application with the California Infrastructure and
Economic Development Bank for approval to issue the bonds. Residential
and small commercial customers will repay the bonds over the expected 10-
year term through non-bypassable charges based on electricity consumption.
With the CPUC's decision expected in September 1997, and subject to the
prior approval of the Infrastructure Bank, it is anticipated that the rate
reduction bonds will be issued in the fourth quarter of 1997.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the Federal Energy Regulatory
Commission (FERC) regarding the creation of the PX and the ISO. In
November 1996, the FERC conditionally accepted the proposal and directed
the three utilities to file more specific information which was filed on
March 31, 1997. In July 1996, the three utilities jointly filed an
application with the CPUC requesting approval to establish a restructuring
trust which would obtain loans up to $250 million for the development of
the ISO and PX through January 1, 1998. The loans would be backed by
utility guarantees; SCE's share would be 45%. The ISO and PX will repay
the trust's loans and recover funds from future ISO and PX customers. In
August 1996, the CPUC issued an interim order establishing the
restructuring trust and the funding level of $250 million which will be
used to build the hardware and software systems for the ISO and PX.
On May 6, 1997, the CPUC issued a decision describing how all California
investor-owned utility customers will be able to choose who will provide
them with electric generation service. Beginning January 1, 1998,
customers will be able to choose to purchase power from the PX through
SCE, or choose direct access, which means the customer can contract
directly with either independent power producers or retail electric
service providers such as power brokers, marketers and aggregators.
Additionally, all investor-owned utility customers must pay the CTC
whether or not they choose to buy power through SCE. Electric utilities
will continue to provide the core distribution service of delivering
energy through its distribution system regardless of a customer's choice
of electricity supplier. The CPUC will continue to regulate the prices
and service obligations related to distribution services. If the new
competitive market cannot accommodate the volume of direct access
transactions, the CPUC could implement a contingency plan. However, the
CPUC believes it is likely that interest in and migration to direct access
will be gradual.
A second decision issued by the CPUC on May 6, 1997, introduces customer
choice to metering, billing and related services (referred to as revenue
cycle services) that are now provided by California's investor-owned
utilities. Under this revenue cycle services "unbundling" decision,
beginning in January 1998, customers may choose to have either SCE or
their electric generation service provider render consolidated (energy and
distribution) bills, or they may choose to have separate billings from
each service provider. In addition, beginning in January 1998, customers
with maximum demand above 20 kW (primarily industrial and large
commercial) can choose SCE or any other supplier to provide their metering
service. All other customers will have this option beginning in January
1999. In determining whether any credit should be provided by the utility
page 7
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to firms providing customers with revenue cycle services, and the amount
of any such credit, the CPUC has indicated that it is appropriate to "net"
the cost incurred by the utility and the cost avoided by the utility as
a result of such services being provided by the other firm rather than by
the utility.
The unbundling of revenue cycle services is likely to expose SCE to the
loss of revenue, higher stranded costs and a reduction in revenue
security. SCE is reviewing the potential effect of these decisions on its
results of operations and financial condition.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. 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. In September 1996, the CPUC
adopted a non-generation transmission and distribution (T&D) PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
In November 1996, SCE filed an application with the CPUC to voluntarily
divest, by auction, all of its oil- and gas-fueled generation assets.
This application builds on SCE's March 1996 plan which outlined how SCE
proposed to divest 50% of these assets. Under the new proposal, SCE would
continue to operate and maintain the divested power plants for at least
two years following their sale, as mandated by the recent restructuring
legislation. In addition, SCE would offer workforce transition programs
to those employees who may be impacted by divestiture-related job
reductions. SCE's proposal is contingent on the overall electric industry
restructuring implementation process continuing on a satisfactory path.
CPUC approval of the oil- and gas-fueled generation divestiture was
requested for late 1997.
In December 1996, SCE filed a more comprehensive plan (elaborating on its
July 1996 filing related to the conceptual aspects of separating costs as
requested by CPUC and FERC directives) for the functional unbundling of
its rates for electric service, beginning on January 1, 1998. In response
to CPUC and FERC orders, as well as the new restructuring legislation,
this filing addressed the implementation-level detail for the functional
unbundling of rates in separate charges for energy, transmission,
distribution, the CTC, public benefit programs and nuclear
decommissioning. Hearings on SCE's rate unbundling plan were concluded
in April 1997. A final decision on this matter is expected in the third
quarter of 1997.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
PAGE 8
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value), assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value), assuming
the fossil plants have no market value. These estimates are based on
incurred costs, and forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of legislative and regulatory mandates; and $5.6 billion to $6.3
billion from costs pertaining to certain generating plants and regulatory
commitments consisting of costs incurred (whose recovery has been deferred
by the CPUC) to provide service to customers. Such commitments include
the recovery of income tax benefits previously flowed-through to
customers, postretirement benefit transition costs, accelerated recovery
of San Onofre and Palo Verde and certain other costs. On February 14,
1997, SCE submitted an update to the CTC filing to reflect approval by the
CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and
the buyout of a power purchase agreement, as well as other minor data
updates. No substantive changes in the total CTC estimates were included.
Hearings on various phases of this issue began in December 1996 and will
continue throughout 1997. A decision is expected before January 1, 1998.
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
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996, SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and the other
major California electric utilities met with the SEC in March 1997.
Subsequently, the SEC asked a series of questions to be answered by each
of California's major electric utilities. SCE responded to the SEC's
questions in early April 1997. The authority to require SCE to discontinue
applying regulatory accounting standards rests with the SEC, although
matters such as this can be referred to the Financial Accounting Standards
Board's Emerging Issues Task Force (EITF) for resolution. On April 28,
1997, this regulatory accounting matter was added to the EITF's agenda for
discussion at its May 21-22, 1997 meeting. If the EITF is able to reach
a consensus on this matter, SCE will be required to follow the EITF's
guidance. If SCE is required to discontinue the application of these
regulatory accounting standards for its generation-related assets, and the
EITF does not change the current requirements of these standards, SCE
would have to write off generation-related regulatory assets, which at
March 31, 1997, totaled approximately $500 million on an after-tax basis,
primarily for the recovery of income tax benefits previously flowed-
through to customers, purchased-power agreement termination payments,
unamortized loss on reacquired debt and the Palo Verde phase-in plan.
page 9
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to
the FERC's jurisdiction to file transmission tariffs which provide
competitors with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
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 in July 1996. The tariff became effective on an interim basis,
subject to refund, as of its filing date. The FERC accepted SCE's
compliance filing in February 1997. SCE will revise its tariff to reflect
the few revisions set forth in the FERC's March 1997 order.
page 10
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED 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 CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994
record periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowances have been
consolidated into one proceeding. SCE and the ORA have filed several
rounds of testimony on this issue. Hearings began in January 1997 and
concluded in February 1997. A decision is expected in late 1997.
Note 2. Contingencies
In addition to the matters disclosed in these notes, Edison International
is involved in legal, tax and regulatory proceedings before various courts
and governmental agencies regarding matters arising in the ordinary course
of business. Edison International believes the outcome of these
proceedings will not materially affect its results of operations or
liquidity.
Brooklyn Navy Yard Project
Edison Mission Energy (EME), a subsidiary of Edison International, owns,
through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard project;
however, it is initially funding all of the required equity and debt ($492
million) for the project and has provided a guarantee as a condition of
obtaining financing for the project.
In February 1997, the contractor asserted general monetary claims under
the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. (BNY) and has served a Complaint filed in California State Court for
damages in the amount of $137 million against BNY. In addition to
defending this action, BNY has filed an action against the contractor in
New York State Court asserting general monetary claims in excess of $13
million under the turnkey agreement. EME believes that the outcome of
this litigation will not materially affect its results of operations or
financial position.
Environmental Protection
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site using currently available
information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level
of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
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 55 identified sites (54 at SCE and 1 at EME) was $112 million at March
31, 1997. 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 $211 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 $96 million of Edison International's recorded
liability, through an incentive mechanism (SCE may request to include
additional sites). Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with
the opportunity to recover these costs from insurance carriers and other
third parties. SCE has successfully settled insurance claims with all
responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $101 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 $10 million.
Based on currently available information, Edison International believes
it is unlikely that it will incur amounts in excess of the upper limit of
the estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs
ultimately recorded will not materially affect its results of operations
or financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased
the maximum private primary insurance available ($200 million). The
balance is covered by the industry's retrospective rating plan that uses
deferred premium charges to every reactor licensee if a nuclear incident
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
at any licensed reactor in the U.S. results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary
level, effective June 1994. The maximum deferred premium for each nuclear
incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its
ownership interests, SCE could be required to pay a maximum of $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability
claims and are subject to adjustment for inflation. If the public
liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500 million
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 $34 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
First Quarter 1997 vs. First Quarter 1996
Earnings
Edison International's earnings per share were 35 cents for the first quarter
of 1997, compared to 38 cents for the first quarter of 1996. Southern
California Edison Company's (SCE) earnings were 27 cents per share, compared
to 31 cents for the first quarter of 1996. The decline of SCE's earnings is
primarily due to a revised ratemaking plan for SCE's nuclear units (see
Regulatory Matters) and a scheduled refueling outage at San Onofre Nuclear
Generating Station Unit 2 during the entire first quarter (see San Onofre
Steam Generator Tubes). This decrease was partially offset by improved
overall operating performance, including a strong performance at San
Onofre Unit 3. Edison Mission Energy's (EME), Edison Capital's and
Mission Land Company's earnings per share were 10 cents, up 3 cents from
the same period in 1996. The increase is primarily due to higher earnings from
EME's foreign projects, particularly First Hydro, which benefited from
higher energy prices and increased utilization. The parent company and
new subsidiaries had expenses of 2 cents per share, up 2 cents from the
same period last year, due to start-up costs at the new subsidiaries. Edison
International's earnings per share decline was partially offset by a 2 cents
increase from the effects of the ongoing share repurchase program.
Operating Revenue
Electric utility revenue decreased 4%, as increased sales volume was more
than offset by lower average rates. Average retail rates were
approximately 5% lower during the first quarter of 1997, compared with
same period for the prior year. The lower rates are attributable to the
continuing effects of the California Public Utilities Commission's (CPUC)
decision effective April 1996 which lowered SCE's 1996 authorized revenue
by $338 million, or 4.4%. Rates in 1997 are unchanged from April 1996.
Over 98% of SCE's electric utility revenue is from retail sales. Retail
rates are regulated by the CPUC and wholesale rates are regulated by the
Federal Energy Regulatory Commission (FERC).
In March 1995, SCE announced a five-year goal to reduce system average
rates by 25% on an inflation-adjusted basis (from 10.7 cents per kilowatt-hour
to below 10 cents per kilowatt-hour). In February 1996, the CPUC approved a
system-wide rate reduction which lowered the average price per kilowatt-
hour from 10.7 cents to 10.1 cents, effective June 1996. Legislation enacted in
September 1996 provides, among other things, at least a 10% rate reduction
for residential and small commercial customers beginning in 1998 (see
Competitive Environment).
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Revenue from diversified operations increased substantially due to
additional revenue associated with the start-up of EME's Loy Yang B Unit
2 and Kwinana projects. These projects began commercial operations during
the fourth quarter of 1996. There was no comparable revenue from these
projects in the first quarter of 1996. In addition, higher pool prices
and increased utilization contributed to increased revenue at EME's First
Hydro project. On March 31, 1997, EME announced that it has entered into
agreements with the State Electricity Commission of Victoria to acquire
the remaining 49% interest of the Loy Yang B power plant near Melbourne,
Australia. This acquisition was completed in May 1997. EME is now the
sole owner of Loy Yang B which consists of two coal-fired 500 megawatt
units and generates approximately 18% of the State of Victoria's
electricity.
Operating Expenses
Fuel expense increased 40% due to higher gas prices and changes in the
fuel mix. A scheduled refueling outage at San Onofre Unit 2 resulted in
higher gas-powered generation. There was no comparable outage in 1996.
Fuel expense also increased at EME due to the start-up of the Loy Yang B
Unit 2 and Kwinana projects in the fourth quarter 1996 and higher costs
for pumping fuel due to increased generation at the First Hydro project
during the first quarter.
Purchased-power expense increased 19%, due to an increase in power
purchased under federally mandated contracts. SCE is required under
federal law to purchase power from certain nonutility generators even
though energy prices under these contracts are generally higher than other
sources. For the twelve months ended March 31, 1997, SCE paid about $1.7
billion (including energy and capacity payments) more for these power
purchases than the cost of power available from other sources. The CPUC
has mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially due
to actual energy costs exceeding CPUC-authorized fuel and purchased-power
cost estimates and undercollections resulting from the accelerated
recovery of SCE's remaining investment in San Onofre Units 2 and 3. These
undercollections were partially offset by overcollections associated with
actual base-rate revenue from kilowatt-hour sales exceeding CPUC-
authorized amounts and incentive pricing associated with operating
efficiencies at San Onofre Units 2 and 3.
Maintenance expense increased 14%, primarily due to the San Onofre Unit
2 scheduled refueling outage for the entire first quarter. There was no
comparable outage for the same period in 1996. Maintenance expense also
increased at EME due to the commercial start-up of the Loy Yang B Unit 2
and Kwinana projects during the fourth quarter of 1996. There were no
comparable maintenance costs associated with these projects during the
same period in 1996.
Depreciation and decommissioning expense increased 29% due to higher
depreciation rates and the accelerated recovery of San Onofre Units 2 and
3 effective April 1996 and of the Palo Verde Nuclear Generating Station
units effective January 1997. Depreciation and decommissioning expense
increased at EME due to the start-up of Loy Yang B Unit 2, which began
commercial operation in October 1996.
Income taxes decreased 14% due to a decrease in pre-tax income.
Property and other taxes decreased 32% due to lower property taxes and
lower payroll taxes related to workforce reductions after SCE's voluntary
retirement programs in 1996.
The provision for rate phase-in plan reflects a CPUC-authorized, 10-year
rate phase-in plan, which deferred the collection of revenue during the
first four years of operation for the Palo Verde units. The deferred
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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.
Minority interest increased substantially, primarily from EME's Loy Yang
B Unit 2 project, which began commercial operation in the fourth quarter
of 1996.
Other nonoperating income decreased, primarily due to increased costs
resulting from the effect of a rise in Edison International's stock price
on SCE's stock option plan and additional accruals at SCE for regulatory
matters.
Interest and Other Expenses
Other interest expense increased substantially, due to an increase in
interest related to balancing account overcollections.
Capitalized interest decreased, primarily due to the completion of EME's
Loy Yang B Unit 2 and other projects in the fourth quarter of 1996.
FINANCIAL CONDITION
Edison International's liquidity is primarily affected by debt maturities,
dividend payments, capital expenditures and investments in partnerships
and unconsolidated subsidiaries. Capital resources include cash from
operations and external financings.
Edison International's board of directors has authorized the repurchase
of up to $800 million of its common stock. Edison International has
repurchased 38.6 million shares ($739 million) through May 5, 1997, funded
by dividends from its subsidiaries and its lines of credit.
For the first quarter of 1997, Edison International's cash flow coverage
of dividends decreased to 5.4 times from 6.9 times for the same period in
1996, as a result of the ongoing share repurchase program. Edison
International's dividend payout ratio for the twelve-month period ended
March 31, 1997, was 62%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $603 million in the
first quarter of 1997, compared to $766 million in the first quarter of
1996. Cash from operations exceeded capital requirements for both periods
presented.
Cash Flows from Financing Activities
At March 31, 1997, Edison International and its subsidiaries had $1.9
billion of borrowing capacity available under lines of credit totaling
$2.2 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 $450 million line of credit with $165 million of borrowing
capacity available. The nonutility companies had available lines of
credit of $700 million, with $600 million of borrowing capacity available
to finance general cash requirements. Edison International's unsecured
lines of credit are at negotiated or bank index rates with various
expiration dates; the majority have five-year terms.
SCE's short-term debt is used to finance fuel inventories, balancing
account undercollections and general cash requirements. EME uses short-
term debt and available credit lines mainly for construction projects
until long-term construction or project loans are secured. Long-term debt
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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 March 31, 1997, SCE could issue approximately $7.9 billion of
additional first and refunding mortgage bonds and $4.5 billion of
preferred stock at current interest and dividend rates.
EME owns, through a wholly-owned subsidiary, 50% of the Brooklyn Navy Yard
project; but funded all of the required equity during construction and
will be required to fund the remaining costs of the project facility until
the close of nonrecourse financing. The estimated total cost is $492
million, of which $450 million had been spent through March 31, 1997. In
December 1995, a tax-exempt bond financing for the project in the amount
of $254 million was obtained through the New York City Industrial
Development Agency (NYCIDA). EME has guaranteed the obligations of the
project pursuant to the financing, as well as an indemnity agreement on
behalf of NYCIDA in the amount of $40 million.
In February 1997, the contractor asserted general monetary claims under
the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. (BNY) and has served a Complaint filed in California State Court for
damages in the amount of $137 million against BNY. In addition to
defending this action, BNY has filed an action against the contractor in
New York State Court asserting general monetary claims in excess of $13
million under the turnkey agreement. EME believes that the outcome of
this litigation will not materially affect its results of operations or
financial position.
EME has firm commitments to make equity and other contributions to its
projects of $353 million, primarily for the Paiton project in Indonesia
and the ISAB project in Italy. EME also has contingent obligations to
make additional contributions of $463 million, primarily for the guarantee
to secure payment of the bonds issued pursuant to the $254 million tax-
exempt financing for the Brooklyn Navy Yard project and equity support
guarantees related to Paiton.
In April 1997, EME completed financing and commenced construction of the
Doga Enerji Cogeneration Project, a 180 megawatt gas-powered power plant
near Istanbul, Turkey. EME will own 80% of this project. In connection
with the financing, EME has guaranteed equity contributions and
subordinated debt totaling $58 million. Commercial operation is scheduled
for late 1998.
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
March 31, 1997, SCE had the capacity to pay $285 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
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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% annual rate. These costs
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 $30
million for the three-month period ended March 31, 1997, compared to $128
million for the same period in 1996.
Edison International's risk management policy allows the use of derivative
financial instruments to mitigate risk. Changes in interest rates,
electricity pool pricing in the United Kingdom and fluctuations in foreign
currency exchange rates can have a significant impact on EME's results of
operations. EME attempts 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 $3 million in the first quarter of 1997 and $2
million in the first quarter of 1996. The maturity dates of several of
EME's interest rate swap agreements do not correspond to the term of the
underlying debt. EME does not believe that interest rate fluctuations will
have a material adverse effect on its results of operations or financial
position.
Projects in the United Kingdom sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly
clearing price for electric 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), related to either the selling or purchase price of power,
whereby a contract specifies a price at which the electricity will be
traded, and the parties to the agreements make payments, calculated based
on the difference between the price in the contract and the half hourly
clearing price for the element of power under contract. These contracts
act as a means of stabilizing production revenue or purchasing costs by
removing an element of First Hydro's net exposure to pool price
volatility. First Hydro's electric revenue increased by $15 million in the
first quarter of 1997, compared to a decrease of $4 million in the
corresponding period of the prior year, 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. At times, EME has hedged a portion of its current
exposure to fluctuations in foreign exchange rates where it deems
appropriate through financial derivatives, offsetting obligations
denominated in foreign currencies, and indexing underlying project
agreements to U.S. dollars or other indices reasonably expected to
correlate with foreign exchange movements. Various statistical
forecasting techniques are used to help assess foreign exchange risk and
the probabilities of various outcomes. There can be no assurance,
however, that fluctuations in exchange rates will be fully offset by
hedges or that currency movements and the relationship between certain
macro economic variables will behave in a manner that is consistent with
historical or forecasted relationships.
Projected Capital Requirements
Edison International's projected capital requirements for the next five
twelve-month periods following March 31, 1997, are: 1997--$861 million;
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1998--$881 million; 1999--$756 million; 2000--$730 million; and 2001--$711
million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month period following March 31, 1997, are: 1998--$573 million;
1999--$544 million; 2000--$664 million; 2001--$279 million; and 2002--$401
million.
REGULATORY MATTERS
SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to
recently enacted legislation which requires that system average rates
remain frozen at the June 10, 1996, level of 10.1 cents per kilowatt-hour (see
discussion in Competitive Environment).
The CPUC's 1997 cost-of-capital decision authorized SCE's common equity
ratio to remain at 48%. SCE's return on common equity also remains at
11.6%. SCE's return on rate base was lowered from 9.55% to 9.49%. This
decision, excluding the effects of other rate actions, would reduce 1997
earnings by approximately 1 cent per share.
The CPUC has authorized revised rate-making plans for SCE's nuclear
facilities, which calls for the accelerated recovery of its nuclear
investments in exchange for a lower authorized rate of return. SCE's
nuclear assets are now earning an annual rate of return of 7.35%, compared
to the current 9.49% for other assets. In addition, the San Onofre plan
authorizes a fixed rate of approximately 4 cents per kilowatt-hour generated
for incremental operating costs, including incremental capital costs, and
nuclear fuel and nuclear fuel financing costs. The San Onofre plan
commenced in April 1996, and ends in December 2001 for accelerated
recovery portion and in December 2003 for the incremental pricing portion.
Palo Verde's incremental operating costs, including incremental capital
costs, and nuclear fuel and nuclear fuel financing costs, are subject to
balancing account treatment. The Palo Verde plan commenced in January
1997 and ends in December 2001.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994 record
periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowances have been
consolidated into one proceeding. SCE and the ORA have filed several
rounds of testimony on this issue. Hearings concluded in February 1997.
A decision is expected in late 1997.
COMPETITIVE ENVIRONMENT
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing. The generation sector has experienced
competition from nonutility power producers and regulators are
restructuring California's electric utility industry.
California Electric Utility Industry Restructuring
The CPUC's December 1995 decision on restructuring California's electric
utility industry started the transition to a new market structure, which
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is expected to provide competition and customer choice and is scheduled
to begin January 1, 1998. Key elements of the CPUC's restructuring
decision include: creation of an independent power exchange (PX) and
independent system operator (ISO); availability of direct customer access
and customer choice; performance-based ratemaking (PBR) for those
utility services not subject to competition; voluntary divestiture of
at least 50% of utilities' gas-fueled generation, and implementation of
a non-bypassable charge to all customers called the competition transition
charge (CTC).
In September 1996, the State of California enacted legislation to provide
a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision by
addressing stranded-cost recovery for utilities, and providing a certain
cost-recovery time period for the transition costs associated with
utility-owned generation-related assets. Transition costs related to
power-purchase contracts would be recovered through the terms of their
contracts while most of the remaining transition costs would be recovered
through 2001. The legislation also includes provisions to finance a
portion of the stranded costs that residential and small commercial
customers would have paid between 1998 and 2001, which would allow
Southern California Edison Company (SCE), a subsidiary of Edison
International, to reduce rates by at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of a
non-bypassable CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Finally, the
legislation contains provisions for the recovery (through 2006) of
reasonable employee-related transition costs incurred and projected for
retraining, severance, early retirement, outplacement and related expenses
for utility workers.
On May 6, 1997, SCE filed an application with the CPUC requesting approval
of the issuance of an aggregate amount of up to $3 billion of rate
reduction bonds in one or more series or classes and a 10% rate reduction
for the period from January 1, 1998, through May 31, 2002. On the same
day, SCE filed an application with the California Infrastructure and
Economic Development Bank for approval to issue the bonds. Residential
and small commercial customers will repay the bonds over the expected 10-
year term through non-bypassable charges based on electricity consumption.
With the CPUC's decision expected in September 1997, and subject to the
prior approval of the Infrastructure Bank, it is anticipated that the rate
reduction bonds will be issued in the fourth quarter of 1997.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the Federal Energy Regulatory
Commission (FERC) regarding the creation of the PX and the ISO. In
November 1996, the FERC conditionally accepted the proposal and directed
the three utilities to file more specific information which was filed on
March 31, 1997. In July 1996, the three utilities jointly filed an
application with the CPUC requesting approval to establish a restructuring
trust which would obtain loans up to $250 million for the development of
the ISO and PX through January 1, 1998. The loans would be backed by
utility guarantees; SCE's share would be 45%. The ISO and PX will repay
the trust's loans and recover funds from future ISO and PX customers. In
August 1996, the CPUC issued an interim order establishing the
restructuring trust and the funding level of $250 million which will be
used to build the hardware and software systems for the ISO and PX.
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On May 6, 1997, the CPUC issued a decision describing how all California
investor-owned utility customers will be able to choose who will provide
them with electric generation service. Beginning January 1, 1998,
customers will be able to choose to purchase power from the PX through
SCE, or choose direct access, which means the customer can contract
directly with either independent power producers or retail electric
service providers such as power brokers, marketers and aggregators.
Additionally, all investor-owned utility customers must pay the CTC
whether or not they choose to buy power through SCE. Electric utilities
will continue to provide the core distribution service of delivering
energy through its distribution system regardless of a customer's choice
of electricity supplier. The CPUC will continue to regulate the prices
and service obligations related to distribution services. If the new
competitive market cannot accommodate the volume of direct access
transactions, the CPUC could implement a contingency plan. However, the
CPUC believes it is likely that interest in and migration to direct access
will be gradual.
A second decision issued by the CPUC on May 6, 1997, introduces customer
choice to metering, billing and related services (referred to as revenue
cycle services) that are now provided by California's investor-owned
utilities. Under this revenue cycle services "unbundling" decision,
beginning in January 1998, customers may choose to have either SCE or
their electric generation service provider render consolidated (energy and
distribution) bills, or they may choose to have separate billings from
each service provider. In addition, beginning in January 1998, customers
with maximum demand above 20 kW (primarily industrial and large
commercial) can choose SCE or any other supplier to provide their metering
service. All other customers will have this option beginning in January
1999. In determining whether any credit should be provided by the utility
to firms providing customers with revenue cycle services, and the amount
of any such credit, the CPUC has indicated that it is appropriate to "net"
the cost incurred by the utility and the cost avoided by the utility as
a result of such services being provided by the other firm rather than by
the utility.
The unbundling of revenue cycle services is likely to expose SCE to the
loss of revenue, higher stranded costs and a reduction in revenue
security. SCE is reviewing the potential effect of these decisions on its
results of operations and financial condition.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. 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. In September 1996, the CPUC
adopted a non-generation transmission and distribution (T&D) PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
In November 1996, SCE filed an application with the CPUC to voluntarily
divest, by auction, all of its oil- and gas-fueled generation assets.
This application builds on SCE's March 1996 plan which outlined how SCE
proposed to divest 50% of these assets. Under the new proposal, SCE would
continue to operate and maintain the divested power plants for at least
two years following their sale, as mandated by the recent restructuring
legislation. In addition, SCE would offer workforce transition programs
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to those employees who may be impacted by divestiture-related job
reductions. SCE's proposal is contingent on the overall electric industry
restructuring implementation process continuing on a satisfactory path.
CPUC approval of the oil- and gas-fueled generation divestiture was
requested for late 1997.
In December 1996, SCE filed a more comprehensive plan (elaborating on its
July 1996 filing related to the conceptual aspects of separating costs as
requested by CPUC and FERC directives) for the functional unbundling of
its rates for electric service, beginning on January 1, 1998. In response
to CPUC and FERC orders, as well as the new restructuring legislation,
this filing addressed the implementation-level detail for the functional
unbundling of rates in separate charges for energy, transmission,
distribution, the CTC, public benefit programs and nuclear
decommissioning. Hearings on SCE's rate unbundling plan were concluded
in April 1997. A final decision on this matter is expected in the third
quarter of 1997.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value), assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value), assuming
the fossil plants have no market value. These estimates are based on
incurred costs, and forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of legislative and regulatory mandates; and $5.6 billion to $6.3
billion from costs pertaining to certain generating plants and regulatory
commitments consisting of costs incurred (whose recovery has been deferred
by the CPUC) to provide service to customers. Such commitments include
the recovery of income tax benefits previously flowed-through to
customers, postretirement benefit transition costs, accelerated recovery
of San Onofre and Palo Verde and certain other costs. On February 14,
1997, SCE submitted an update to the CTC filing to reflect approval by the
CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and
the buyout of a power purchase agreement, as well as other minor data
updates. No substantive changes in the total CTC estimates were included.
Hearings on various phases of this issue began in December 1996 and will
continue throughout 1997. A decision is expected before January 1, 1998.
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
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996, SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
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indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and the other
major California electric utilities met with the SEC in March 1997.
Subsequently, the SEC asked a series of questions to be answered by each
of California's major electric utilities. SCE responded to the SEC's
questions in early April 1997. The authority to require SCE to discontinue
applying regulatory accounting standards rests with the SEC, although
matters such as this can be referred to the Financial Accounting Standards
Board's Emerging Issues Task Force (EITF) for resolution. On April 28,
1997, this regulatory accounting matter was added to the EITF's agenda for
discussion at its May 21-22, 1997 meeting. If the EITF is able to reach
a consensus on this matter, SCE will be required to follow the EITF's
guidance. If SCE is required to discontinue the application of these
regulatory accounting standards for its generation-related assets, and the
EITF does not change the current requirements of these standards, SCE
would have to write off generation-related regulatory assets, which at
March 31, 1997, totaled approximately $500 million on an after-tax basis,
primarily for the recovery of income tax benefits previously flowed-
through to customers, purchased-power agreement termination payments,
unamortized loss on reacquired debt and the Palo Verde phase-in plan.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
recovery of stranded costs, which are prior-service costs incurred under
the current regulatory framework. In addition to providing recovery of
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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 in July 1996. The tariff became effective on an interim basis,
subject to refund, as of its filing date. The FERC accepted SCE's
compliance filing in February 1997. SCE will revise its tariff to reflect
the few revisions set forth in the March 1997 order.
ENVIRONMENTAL PROTECTION
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
As further discussed in Note 2 of "Notes to 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
range of costs.
Edison International's recorded estimated minimum liability to remediate
its 55 identified sites (54 at SCE and 1 at EME) was $112 million at March
31, 1997. One of SCE's sites, a former pole-treating facility, is
considered a federal Superfund site and represents 72% 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
$211 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 $96 million of Edison International's recorded
liability, through an incentive mechanism (SCE may request to include
additional sites). Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with
the opportunity to recover these costs from insurance carriers and other
third parties. SCE has successfully settled insurance claims with all
responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $101 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 $10 million.
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Based on currently available information, Edison International believes
it is unlikely that it will incur amounts in excess of the upper limit of
the estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs
ultimately recorded will not 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 U.S. In addition, another study is in progress to
determine the specific impact of air contaminant emissions from the Mohave
Coal Generating Station on visibility in Grand Canyon National Park. The
potential effect of these studies on sulfur dioxide emissions regulations
for Mohave is unknown.
Edison International's projected capital expenditures to protect the
environment are $831 million for the 1997-2001 period, mainly for
aesthetics treatment, including undergrounding certain transmission and
distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects is receiving increased
attention. The scientific community has not yet reached a consensus on
the nature of any health effects of EMF. However, the CPUC has issued a
decision which provides for a rate-recoverable research and public
education program conducted by California electric utilities, and
authorizes these utilities to take no-cost or low-cost steps to reduce EMF
in new electric facilities. SCE is unable to predict when or if the
scientific community will be able to reach a consensus on any health
effects of EMF, or the effect that such a consensus, if reached, could
have on future electric operations.
PALO VERDE STEAM TUBE RUPTURE
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in Unit 2 will have to be replaced within five to ten years.
SCE estimates its share of the steam generator replacement costs to be
between $16 million and $30 million, plus replacement power costs. SCE
is evaluating APS' analyses, conducting its own review, and has not yet
decided whether it supports replacement of the steam generators.
SAN ONOFRE STEAM GENERATOR TUBES
The San Onofre Units 2 and 3 steam generators have performed relatively
well through the first 15 years of operation, with low rates of ongoing
tube degradation. During the most recent Unit 2 refueling and inspection
outage, however, an increased rate of degradation was identified,
resulting in removing 1.8% of the tubes from service. The cumulative
total of Unit 2's tubes removed from service is now 5.5%, well below the
maximum 10% allowed in the steam generator design before the rating
capacity of the unit must be reduced. As a result of the increased
degradation, a mid-cycle inspection outage will be conducted in 1998 for
Unit 2. Depending on the results of the current refueling and inspection
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outage for Unit 3, a mid-cycle inspection outage may also be required in
1998 for that unit.
During the current, scheduled 75-day refueling outage of Unit 3, which
began in April 1997, inspections of structural supports for steam
generator tubes identified several areas where the thickness of the
supports had been reduced, apparently by erosion during normal plant
operation. Additional inspection and analysis is continuing, and the
results will be reviewed with the Nuclear Regulatory Commission in early
June 1997. Corrective actions may include removing a limited number of
tubes from service by plugging, which could be completed within the
scheduled outage. Additional actions could be required which might extend
the outage. In the recent inspection of Unit 2's steam generators, the
similar tube supports showed no signs of the erosion affecting Unit 3.
NEW EARNINGS PER SHARE STANDARD
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on reported earnings per share.
PROPOSED NEW ACCOUNTING STANDARD
During 1996, the Financial Accounting Standards Board issued an exposure
draft that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for the decommissioning of its nuclear power plants, obligations for coal
mine reclamation costs and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
The nonutility subsidiaries are currently reviewing what impact the
exposure draft may have on their results of operations and financial
position.
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PART II--OTHER INFORMATION
Item 1. Legal Proceedings
Edison Mission Energy
PMNC Litigation
In February 1997, a civil action was commenced in the Superior Court of
the State of California, Orange County, entitled The Parsons Corporation
and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy
New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which
plaintiffs assert general monetary claims under the construction turnkey
agreement in the amount of $136.8 million. In addition to defending this
action, Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy
Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc.,
Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons
Corporation in the Supreme Court of the State of New York, Kings County,
Index No. 5966/97 asserting general monetary claims in excess of $13
million under the construction turnkey agreement. EME believes that the
outcome of this litigation will not have a material adverse effect on its
consolidated financial position or results of operations.
Southern California Edison Company
QF Litigation
On May 20, 1993, four geothermal QFs filed a lawsuit against SCE in Los
Angeles County Superior Court, claiming that SCE underpaid, and continues
to underpay, the plaintiffs for energy. SCE denied the allegations in its
response to the complaint. The action was brought on behalf of Vulcan/BN
Geothermal Power Company, Elmore L.P., Del Ranch L.P., and Leathers L.P.,
each of which was partially owned by a subsidiary of Edison Mission Energy
(a subsidiary of Edison International) at the time of filing. In April
1996, Edison Mission Energy's 50% share in these projects was sold to
CalEnergy. In October 1994, plaintiffs submitted an amended complaint to
the court to add causes of action for unfair competition and restraint of
trade. In July 1995, after several motions to strike had been heard by
the court, the plaintiffs served a fourth amended complaint, which omitted
the previous claims based on alleged restraint of trade. The plaintiffs
allege in the fourth amended complaint that past underpayments have
totaled at least $21 million. In other court filings, plaintiffs contend
that additional contract payments owing from the beginning of the alleged
underpayments through the end of the contract term could total
approximately $60 million. Plaintiffs also seek unspecified punitive
damages and an injunction to enjoin SCE from "future" unfair competition.
After SCE's motion to strike portions of the fourth amended complaint was
denied, SCE filed an answer to the fourth amended complaint which denies
its material allegations.
On May 1, 1996, the parties entered into an agreement for a settlement of
all claims in dispute. Pursuant to the agreement, the specific terms of
which are confidential, a settlement amount has been paid and the parties
have entered into mutual general releases, with respect to the period
before January 1, 1996. SCE intends to seek recovery of this payment
through rates. SCE has also agreed, subject to CPUC approval, to increase
payments to plaintiffs for specified levels of energy deliveries for the
period after December 31, 1995. Plaintiffs have reserved the right to
continue the litigation with respect to the period after December 31,
1995, if CPUC approval is not obtained. On August 8, 1996, the Company
filed its application with the CPUC for approval of the settlement as it
pertains to the period after 1995. On December 20, 1996, the ORA filed
a protest to the application. In its protest, the ORA requests that the
CPUC not grant the application or, in the alternative, that the CPUC
conduct hearings on the application. On January 17, 1997, the Company
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filed a reply to the ORA's request. On February 27, 1997, a prehearing
conference was held, at which time SCE's application was set for hearing
to commence on April 23, 1997. This hearing date was subsequently vacated
by the assigned ALJ due to ongoing discussions to resolve issues raised
by ORA's protest.
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189 million in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
Superior Court case granted the plaintiffs' motion seeking summary
adjudication that the contract language in question is not reasonably
susceptible to SCE's position that there is only a single, 10-year period
of fixed payments. Following the March 1 ruling, a ninth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first eight. SCE subsequently responded to the complaint
in the new lawsuit by denying its material allegations. On April 5, 1995,
SCE filed a petition for Writ of Mandate, Prohibition or Other Appropriate
Relief, requesting that the Court of Appeal of the State of California,
Second Appellate District issue a writ directing the Los Angeles Superior
Court to vacate its March 1 order granting summary adjudication. In a
decision filed August 9, 1995, the Court of Appeal issued a writ directing
that the order be overturned, and a new order be entered denying the
motion. In light of the Court of Appeal decision in the lead Los Angeles
case, a summary adjudication motion in the Kern County case was withdrawn.
On March 25, 1996, pursuant to a court-approved stipulation, all but one
of the cases were consolidated for trial in Los Angeles Superior Court.
Shortly thereafter, on April 3, 1997, pursuant to stipulation of the
parties, the Kern County case was ordered to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. Trial on the
consolidated cases began on March 11, 1997, and is presently in progress.
No trial date has been set in the ninth unconsolidated case.
Environmental Litigation
Electric and Magnetic Fields ("EMF")
SCE is involved in three lawsuits alleging that various plaintiffs
developed cancer as a result of exposure to EMF from SCE facilities. SCE
denied the material allegations in its responses to each of these
lawsuits.
The first lawsuit was filed in Orange County Superior Court and served on
SCE in June 1994. There are five named plaintiffs and six named
defendants, including SCE. Three of the five plaintiffs are presently or
were formerly employed by Grubb & Ellis, a real estate brokerage firm with
offices located in a commercial building known as the Koll Center in
Newport Beach. Two of the named plaintiffs are spouses of the other
plaintiffs. Grubb & Ellis and the owners and developers of the Koll
Center are also named as defendants in the lawsuit. This lawsuit alleges,
among other things, that the three plaintiffs employed by Grubb & Ellis
developed various forms of cancer as a result of exposure to EMF from
electrical facilities owned by SCE and/or the other defendants located on
Koll Center property. No specific damage amounts are alleged in the
complaint, but supplemental documentation prepared by the plaintiffs
indicates that plaintiffs allege compensatory damages of approximately $8
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million, plus unspecified punitive damages. In December 1995, the court
granted SCE's motion for summary judgment and dismissed the case.
Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but
no date for oral argument has been set.
A second lawsuit was filed in Orange County Superior Court and served on
SCE in January 1995. This lawsuit arises out of the same fact situation
as the June 1994 lawsuit described above and involves the same defendants.
There are four named plaintiffs, two of whom were formerly employed by
Grubb & Ellis and now allegedly have various forms of cancer. The other
two plaintiffs are the spouses of those two individuals. No specific
damage amounts are alleged in the complaint, but supplemental
documentation prepared by the plaintiffs indicates that plaintiffs will
allege compensatory damages of approximately $13.5 million, plus
unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a
cross-complaint against the other co-defendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. This case has been stayed pending
appellate review of the trial judge's sanction order against the
plaintiffs' attorneys. The Court of Appeals has heard oral argument on
this issue, but no decision has been issued.
A third case was filed in Orange County Superior Court and served on SCE
in March 1995. The plaintiff alleges, among other things, that he
developed cancer as a result of EMF emitted from SCE distribution lines
which he alleges were not constructed in accordance with CPUC standards.
No specific damage amounts are alleged in the complaint but supplemental
documentation prepared by the plaintiff indicates that plaintiff will
allege compensatory damages of approximately $5.5 million, plus
unspecified punitive damages. No trial date has been set in this case.
San Onofre Personal Injury Litigation
An SCE engineer employed at San Onofre died in 1991 from cancer of the
abdomen. On February 6, 1995, his children sued SCE and SDG&E, as well
as Combustion Engineering, the manufacturer of the fuel rods for the
plant, in the U.S. District court for the Southern District of California.
Plaintiffs alleged that the former employee's illness resulted from, and
was aggravated by, exposure to radiation at San Onofre, including contact
with radioactive fuel particles released from failed fuel rods.
Plaintiffs sought unspecified compensatory and punitive damages. On April
3, 1995, the court granted the defendants' motion to dismiss 14 of the
plaintiffs' claims. SCE's April 20, 1995, answer to the complaint denied
all material allegations. On October 10, 1995, the court granted
plaintiffs' motion to include the Institute of Nuclear Power Operations
(an organization dedicated to achieving excellence in nuclear power
operations) as a defendant in the suit. On December 7, 1995, the court
granted SCE's motion for summary judgment on the sole outstanding claim
against it, basing the ruling on the worker's compensation system being
the exclusive remedy for the claim. Plaintiffs have appealed this ruling
to the Ninth Circuit Court of Appeals. All trial court proceedings have
been stayed pending the ruling of the Court of Appeals. The impact to
SCE, if any, from further proceedings in this case against the remaining
defendants cannot be determined at this time.
On July 5, 1995, a former SCE reactor operator and his wife sued SCE and
SDG&E in the U.S. District court for the Southern District of California.
Plaintiffs also named Combustion Engineering, the manufacturer of the fuel
rods for the plant, and the Institute of Nuclear Power Operations as
defendants. The former employee died of leukemia shortly after the
complaint was filed. Plaintiffs allege that the former operator's illness
resulted from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles released from failed
fuel rods. Plaintiffs seek unspecified compensatory and punitive damages.
On November 22, 1995, the complaint was amended to allege wrongful death
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and added the former employee's two children as plaintiffs. On December
22, 1995, SCE filed a motion to dismiss or, in the alternative, for
summary judgment based on worker's compensation exclusivity. On March 25,
1996, the court granted SCE's motion for summary judgment. Plaintiffs
have appealed this ruling to the Ninth Circuit Court of Appeals. All
trial court proceedings have been stayed pending the ruling of the Court
of Appeals in this case and in the case described in the above paragraph.
The impact to SCE, if any, from further proceedings in this case against
the remaining defendants cannot be determined at this time.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District court for the Southern
District of California. Plaintiffs also named Combustion Engineering, the
manufacturer of fuel rods for the plant, and the Institute of Nuclear
Power Operations as defendants. The security officer worked for a
contractor in 1982, worked for SCE as a temporary employee (1982-1984),
and later worked as an SCE security supervisor (1984-1994). The officer
died of leukemia in 1994. Plaintiffs allege that the former officer's
illness resulted from, and was aggravated by, his exposure to radiation
at San Onofre, including contact with radioactive fuel particles released
from failed fuel rods. Plaintiffs seek unspecified compensatory and
punitive damages. SCE's November 13, 1995, answer to the complaint denied
all material allegations. All trial court proceedings have been stayed
pending the rulings of the Court of Appeals in the cases described in the
above two paragraphs.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S.
District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering, the manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs alleged that the employee transported radioactive
byproducts on his person, clothing and/or tools to his home where his wife
was then exposed to radiation that caused her leukemia. Plaintiffs seek
unspecified compensatory and punitive damages. SCE's December 19, 1995,
partial answer to the complaint denied all material non-employment related
allegations. SCE's motion to dismiss the employee's employment related
allegations based on worker's compensation exclusivity was granted on
March 19, 1996. The employee's wife died on August 15, 1996. On
September 20, 1996, the complaint was amended to allege wrongful death and
to add the employee's two children as plaintiffs. SCE's motion for
summary judgment was denied on April 9, 1997. The trial is scheduled to
begin on November 24, 1997.
On November 28, 1995, a former contract worker at San Onofre, her husband,
and her son, sued SCE in the U.S. District Court for the Southern District
of California. Plaintiffs also named Combustion Engineering, the
manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege
that the former contract worker transported radioactive byproducts on her
person and clothing to her home where her son was then exposed to
radiation that caused his leukemia. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's January 2, 1996, answer denied
all material allegations. On August 12, 1996, the Court dismissed the
claims of the former worker and her husband with prejudice. This case is
expected to go to trial in early 1998, after completion of the trial in
the case described in the preceding paragraph.
Employment Discrimination Litigation
On September 21, 1994, nine African-American employees filed a lawsuit
against Edison International and SCE on behalf of a class of African-
American employees, alleging racial discrimination in job advancement,
pay, training and evaluation. The lawsuit was filed in the United States
District Court for the Central District of California. The plaintiffs
sought injunctive relief, as well as an unspecified amount of compensatory
and punitive damages, attorneys' fees, costs and interest. Edison
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International and SCE responded by denying the material allegations of the
complaint and asserting several affirmative defenses.
Simultaneous with discovery, the parties entered into settlement
discussions. The parties agreed to include the Equal Employment
Opportunity Commission (EEOC) in their settlement discussions after that
agency indicated its intent to intervene in the lawsuit in support of the
plaintiffs. The parties and EEOC agreed upon settlement terms and
submitted a proposed Consent Decree to the court for approval. After
certain issues raised by the court were addressed through a modification
of the proposed Decree, the court granted preliminary approval of the
modified Consent Decree on August 5, 1996, ordered that notice be given
to the class members, and scheduled a final fairness hearing on September
26, 1996.
Fifteen individuals and an organization filed timely objections to the
proposed Consent Decree and a motion to intervene in the lawsuit.
Thirteen individuals filed timely requests to be excluded from the
monetary provisions of the proposed Decree. On September 25, 1996, the
court denied the motion to intervene. After the hearing on September 26,
at which the court heard oral argument from the objectors, the court on
September 30, 1996, overruled the objections and granted final approval
of the Consent Decree.
The Decree provides that a settlement fund of $8.15 million for back pay
claims and $3.1 million for emotional distress claims be established, and
it contains an expedited claim review process for class members who make
claims to the settlement fund. The Decree also provides for improvements
in 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 object to the Consent Decree served notice of appeal from
the court's orders denying intervention and approving the Consent Decree.
The Court of Appeals ordered that the appellants file their opening brief
by March 12, 1997, and that appellees file any responsive brief by April
11, 1997. Appellants moved for an extension of time to file their opening
brief, and appellees filed a joint motion to dismiss the appeal for lack
of prosecution. On April 29, 1997, the Court of Appeals granted
appellees' motion and ordered that the appeal be dismissed.
Oil Pipeline Litigation
On November 1, 1996, plaintiff, a crude oil pipeline company, filed a
lawsuit against SCE and the City of Los Angeles (the "City") in the United
States District Court for the Central District of California claiming that
SCE and the City had interfered with its attempt to construct a proposed
132-mile oil pipeline ("Pacific Pipeline") designed to transport oil from
the San Joaquin Valley and Santa Barbara to the Los Angeles refineries.
Plaintiff alleges, among other things, that SCE and the City wrongfully
initiated administrative and other legal proceedings in an attempt to
derail and obstruct the construction of the Pacific Pipeline. Plaintiff
alleges that these acts constitute unfair competition, tortious
interference with economic advantage and violate state and federal
antitrust laws. Plaintiff further claims that because of the alleged
delays, it could suffer losses in excess of $300 million. Additionally,
plaintiff seeks treble and punitive damages.
The deadline for filing a response to the complaint has been continued
pending the outcome of a motion by plaintiff filed in a related lawsuit
seeking to dismiss the City of Los Angeles' complaint therein against the
U.S. Forest Service and plaintiff. SCE intends to deny the substantive
allegations of the complaint.
page 31
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
Election of Directors
At Edison International's Annual Meeting of Shareholders on April 17,
1997, shareholders elected eighteen nominees to the Board of Directors.
The number of broker non-votes for each nominee was zero. The number of
votes cast for and withheld from each Director-nominee were as follows:
Name Number of Votes
---- ---------------------------
For Withheld
----------- ----------
Howard P. Allen 342,527,189 10,674,181
John E. Bryson 342,669,433 10,531,936
Winston H. Chen 343,210,005 9,991,365
Stephen E. Frank 343,034,201 10,167,169
Camilla C. Frost 342,852,388 10,348,981
Joan C. Hanley 343,150,402 10,050,967
Carl F. Huntsinger 343,176,300 10,025,069
Charles D. Miller 343,164,009 10,037,361
Luis G. Nogales 342,958,278 10,243,092
Ronald L. Olson 343,119,801 10,081,569
J. J. Pinola 342,920,165 10,281,204
James M. Rosser 343,119,686 10,081,684
E. L. Shannon, Jr. 343,048,766 10,152,604
Robert H. Smith 343,219,811 9,981,559
Thomas C. Sutton 343,254,213 9,947,156
Daniel M. Tellep 343,215,086 9,986,283
James D. Watkins 342,914,600 10,286,770
Edward Zapanta 343,136,392 10,064,978
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
None
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 and
Assistant Secretary
May 15, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Edison International Financial Data Schedule - Exhibit 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,561,432
<OTHER-PROPERTY-AND-INVEST> 7,179,591
<TOTAL-CURRENT-ASSETS> 2,125,874
<TOTAL-DEFERRED-CHARGES> 3,079,541
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 23,946,438
<COMMON> 2,491,241
<CAPITAL-SURPLUS-PAID-IN> 77,622
<RETAINED-EARNINGS> 3,639,305
<TOTAL-COMMON-STOCKHOLDERS-EQ> 6,208,168
425,000
283,755
<LONG-TERM-DEBT-NET> 4,141,431
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 3,036,996
<COMMERCIAL-PAPER-OBLIGATIONS> 252,694
<LONG-TERM-DEBT-CURRENT-PORT> 505,047
0
<CAPITAL-LEASE-OBLIGATIONS> 68,344
<LEASES-CURRENT> 18,706
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,006,297
<TOT-CAPITALIZATION-AND-LIAB> 23,946,438
<GROSS-OPERATING-REVENUE> 2,000,725
<INCOME-TAX-EXPENSE> 96,076
<OTHER-OPERATING-EXPENSES> 1,547,589
<TOTAL-OPERATING-EXPENSES> 1,643,665
<OPERATING-INCOME-LOSS> 357,060
<OTHER-INCOME-NET> (24,291)
<INCOME-BEFORE-INTEREST-EXPEN> 332,769
<TOTAL-INTEREST-EXPENSE> 176,095
<NET-INCOME> 156,674
11,862
<EARNINGS-AVAILABLE-FOR-COMM> 144,812
<COMMON-STOCK-DIVIDENDS> 103,670
<TOTAL-INTEREST-ON-BONDS> 91,189
<CASH-FLOW-OPERATIONS> 603,268
<EPS-PRIMARY> $0.35
<EPS-DILUTED> $0.34
</TABLE>
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report included in this quarterly report on Form
10-Q for the quarter ended March 31, 1997, of Edison International into
the previously filed Registration Statements which follow:
Registration Form File No. Effective Date
----------------- -------- --------------
Form S-3 333-08115 July 15, 1996
Form S-8 333-30913 May 16, 1996
Form S-8 33-32302 June 2, 1993
Form S-8 33-46713 June 2, 1993
Form S-8 33-46714 June 2, 1993
Form S-3 33-44148 September 17, 1993
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
May 14, 1997
