PAGE
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 1997
---------------------------------------
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
---------------- -----------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P.O. Box 999)
Rosemead, California
(Address of principal 91770
executive offices) (Zip Code)
626-302-2222
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date:
Class Outstanding at August 8, 1997
- -------------------------- ------------------------------
Common Stock, no par value 396,966,715
PAGE
<PAGE>
EDISON INTERNATIONAL
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income--Three and Six
Months Ended June 30, 1997, and 1996 2
Consolidated Balance Sheets--June 30, 1997,
and December 31, 1996 3
Consolidated Statements of Cash Flows--Six Months
Ended June 30, 1997, and 1996 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 15
Part II. Other Information:
Item 1. Legal Proceedings 30
Item 6. Exhibits and Reports on Form 8-K 35
page 1
<PAGE>
EDISON INTERNATIONAL
PART I--FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended
June 30, June 30,
-------------------------- --------------------------
1997 1996 1997 1996
---------- --------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C>
Electric utility revenue $1,843,963 $1,610,989 $3,539,365 $3,371,122
Diversified operations 323,219 202,757 628,543 410,277
---------- ---------- ---------- ----------
Total operating revenue 2,167,182 1,813,746 4,167,908 3,781,399
---------- ---------- ---------- ----------
Fuel 194,328 162,503 394,561 305,680
Purchased power 587,660 560,742 1,216,335 1,088,174
Provisions for regulatory adjustment
clauses -- net (3,850) (201,506) (92,023) (103,682)
Other operating expenses 454,899 419,677 785,171 749,540
Maintenance 116,848 67,611 213,002 151,724
Depreciation and decommissioning 342,254 299,134 682,375 563,661
Income taxes 113,541 127,721 209,616 239,201
Property and other taxes 32,682 45,899 72,992 105,584
---------- ---------- ---------- ----------
Total operating expenses 1,838,362 1,481,781 3,482,029 3,099,882
---------- ---------- ---------- ----------
Operating income 328,820 331,965 685,879 681,517
---------- ---------- ---------- ----------
Provision for rate phase-in plan (11,381) (18,867) (22,690) (47,945)
Allowance for equity funds used
during construction 1,897 3,066 3,900 7,468
Interest and dividend income 19,149 12,771 34,991 28,098
Minority interest (9,724) (14,145) (37,689) (27,869)
Other nonoperating income -- net (6,870) 1,579 (9,732) 10,048
---------- ---------- ---------- ----------
Total other income (deductions) -- net (6,929) (15,596) (31,220) (30,200)
---------- ---------- ---------- ----------
Income before interest and other expenses 321,891 316,369 654,659 651,317
---------- ---------- ---------- ----------
Interest on long-term debt 152,382 146,472 304,806 297,459
Interest on short-term debt 10,532 9,226 19,251 18,235
Other interest expense 14,469 12,650 37,009 27,402
Allowance for borrowed funds used
during construction (2,284) (1,927) (4,696) (4,695)
Capitalized interest (2,899) (17,650) (8,076) (33,648)
Dividends on subsidiary preferred
securities 10,669 11,868 22,531 23,745
---------- ---------- ---------- ----------
Total interest and other expenses -- net 182,869 160,639 370,825 328,498
---------- ---------- ---------- ----------
Net income $ 139,022 $ 155,730 $ 283,834 $ 322,819
========== ========== ========== ==========
Weighted-average shares of common stock
outstanding 408,310 441,035 413,888 442,143
Earnings per share $0.34 $0.35 $0.69 $0.73
Dividends paid per common share $0.25 $0.25 $0.50 $0.50
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 2
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
<TABLE>
<CAPTION>
June 30, December 31,
1997 1996
------------- -----------
(Unaudited)
ASSETS
<S> <C> <C>
Utility plant, at original cost $20,486,816 $20,400,387
Less -- accumulated provision for
depreciation and decommissioning 9,932,564 9,431,071
----------- -----------
10,554,252 10,969,316
Construction work in progress 529,040 556,645
Nuclear fuel, at amortized cost 174,216 176,827
----------- -----------
Total utility plant 11,257,508 11,702,788
----------- -----------
Nonutility property -- less
accumulated provision for
depreciation of $225,665 and $203,256
at respective dates 3,537,766 3,570,237
Nuclear decommissioning trusts 1,670,747 1,485,525
Investments in partnerships and
unconsolidated subsidiaries 1,463,987 1,371,824
Investments in leveraged leases 869,408 584,515
Other investments 137,882 103,973
----------- -----------
Total other property and investments 7,679,790 7,116,074
----------- -----------
Cash and equivalents 895,737 896,594
Receivables, including unbilled
revenue, less allowances of
$21,963 and $26,230 for uncollectible
accounts at respective dates 1,098,407 1,094,498
Fuel inventory 63,046 72,480
Materials and supplies, at average cost 151,986 154,266
Accumulated deferred income taxes -- net 193,749 240,429
Prepayments and other current assets 30,256 113,654
----------- -----------
Total current assets 2,433,181 2,571,921
----------- -----------
Unamortized debt issuance and
reacquisition expense 332,627 346,834
Rate phase-in plan 29,119 50,703
Income tax-related deferred charges 1,615,930 1,741,091
Other deferred charges 1,104,227 1,029,203
----------- -----------
Total deferred charges 3,081,903 3,167,831
----------- -----------
Total assets $24,452,382 $24,558,614
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 3
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
June 30, December 31,
1997 1996
------------- -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
Common shareholders' equity:
Common stock (402,187,847 and 424,524,178
<S> <C> <C>
shares outstanding at respective dates) $ 2,416,578 $ 2,547,403
Cumulative translation adjustments -- net 44,267 63,898
Unrealized gain in equity investments -- net 47,830 33,382
Retained earnings 3,467,360 3,752,549
----------- -----------
5,976,035 6,397,232
Preferred securities of subsidiaries:
Not subject to mandatory redemption 183,755 283,755
Subject to mandatory redemption 425,000 425,000
Long-term debt 7,653,749 7,474,679
----------- -----------
Total capitalization 14,238,539 14,580,666
----------- -----------
Other long-term liabilities 506,066 423,925
----------- -----------
Current portion of long-term debt 650,231 592,143
Short-term debt 642,348 397,098
Accounts payable 413,137 437,657
Accrued taxes 642,470 530,365
Accrued interest 144,407 131,079
Dividends payable 101,752 108,563
Regulatory balancing accounts -- net 86,516 181,488
Deferred unbilled revenue and other
current liabilities 1,027,716 1,059,240
----------- -----------
Total current liabilities 3,708,577 3,437,633
----------- -----------
Accumulated deferred income
taxes -- net 4,139,515 4,283,219
Accumulated deferred investment
tax credits 361,575 372,377
Customer advances and other
deferred credits 1,491,118 753,755
----------- -----------
Total deferred credits 5,992,208 5,409,351
----------- -----------
Minority interest 6,992 707,039
----------- -----------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $24,452,382 $24,558,614
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 4
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
<TABLE>
<CAPTION>
6 Months Ended
June 30,
------------------------
1997 1996
--------- -----------
(Unaudited)
Cash flows from operating activities:
<S> <C> <C>
Net income $ 283,834 $ 322,819
Adjustments for non-cash items:
Depreciation and decommissioning 682,375 563,661
Amortization 35,814 55,730
Rate phase-in plan 21,584 46,005
Deferred income taxes and investment tax
credits (13,317) 30,982
Equity in income from partnerships and
unconsolidated subsidiaries (84,014) (65,787)
Other long-term liabilities 82,141 (10,285)
Other -- net (91,267) (11,743)
Changes in working capital:
Receivables (52,220) 315,052
Regulatory balancing accounts (94,972) (111,039)
Fuel inventory, materials and supplies 11,714 8,463
Prepayments and other current assets 86,223 89,713
Accrued interest and taxes 125,139 9,725
Accounts payable and other current
liabilities (48,768) (94,116)
Distributions from partnerships and
unconsolidated subsidiaries 69,058 50,139
--------- ---------
Net cash provided by operating activities 1,013,324 1,199,319
--------- ---------
Cash flows from financing activities:
Long-term debt issued 1,475,537 1,127,321
Long-term debt repayments (1,142,534) (1,107,082)
Preferred securities redemptions (100,000) --
Nuclear fuel financing -- net (7,061) (5,457)
Common stock issued 4,661 745
Common stock repurchases (500,208) (65,701)
Short-term debt financing -- net 235,592 (50,817)
Dividends paid (209,807) (221,821)
Other -- net (241) --
--------- ---------
Net cash used by financing activities (244,061) (322,812)
--------- ---------
Cash flows from investing activities:
Additions to property and plant (345,975) (434,687)
Funding of nuclear decommissioning trusts (74,573) (72,632)
Investments in partnerships and
unconsolidated subsidiaries (162,076) (171,440)
Unrealized gain in equity investments -- net 14,448 10,798
Other -- net (201,944) 57,131
--------- ---------
Net cash used by investing activities (770,120) (610,830)
--------- ---------
Net increase (decrease) in cash and equivalents (857) 265,677
Cash and equivalents, beginning of period 896,594 507,151
--------- ---------
Cash and equivalents, end of period $895,737 $ 772,828
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
page 5
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments have been made that are
necessary to present a fair statement of the financial position and
results of operations for the periods covered by this report.
Edison International's significant accounting policies were described in
Note 1 of "Notes to Consolidated Financial Statements" included in its
1996 Annual Report on Form 10-K filed with the Securities and Exchange
Commission. Edison International follows the same accounting policies for
interim reporting purposes. This quarterly report should be read in
conjunction with Edison International's 1996 Annual Report.
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on Edison International's basic earnings per share, which replaces primary
earnings per share.
Certain prior-period amounts were reclassified to conform to the June 30,
1997, financial statement presentation.
Note 1. Regulatory Matters
California Electric Utility Industry Restructuring
Restructuring Legislation - In September 1996, the State of California
enacted legislation to provide a transition to a competitive market
structure. The legislation substantially adopts the California Public
Utilities Commission's (CPUC) December 1995 restructuring decision by
addressing stranded-cost recovery for utilities and providing a certain
cost-recovery time period for the transition costs associated with
utility-owned generation-related assets. Transition costs related to
power-purchase contracts would be recovered through the terms of their
contracts while most of the remaining transition costs would be recovered
through 2001. The legislation also includes provisions to finance a
portion of the stranded costs that residential and small commercial
customers would have paid between 1998 and 2001, which would allow
Southern California Edison Company (SCE) to reduce rates by at least 10%
to these customers, beginning January 1, 1998. The financing would occur
with securities issued by the California Infrastructure and Economic
Development Bank, or an entity approved by the Bank. The legislation
includes a rate freeze for all other customers, including large commercial
and industrial customers, as well as provisions for continued funding
for energy conservation, low-income programs and renewable resources.
Despite the rate freeze, SCE expects to be able to recover its revenue
requirement based on cost-of-service regulation during the 1998-2001
transition period. In addition, the legislation mandates the
implementation of a non-bypassable competition transition charge (CTC)
that provides utilities the opportunity to recover costs made uneconomic
by electric utility restructuring. Finally, the legislation contains
provisions for the recovery (through 2006) of reasonable employee-related
transition costs incurred and projected for retraining, severance, early
retirement, outplacement and related expenses for utility workers.
page 6
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rate Reduction Bonds - On May 6, 1997, SCE filed an application with the
CPUC requesting approval of the issuance of an aggregate amount of up to
$3 billion of rate reduction bonds in one or more series or classes and
a 10% rate reduction for the period from January 1, 1998, through March
31, 2002. On the same day, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. With the CPUC's decision expected in September
1997, and subject to the prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and Federal Energy Regulatory
Commission (FERC) directives) for the functional unbundling of its rates
for electric service, beginning January 1, 1998. In response to CPUC and
FERC orders, as well as the new restructuring legislation, this filing
addressed the implementation-level detail for the functional unbundling
of rates into separate charges for energy, transmission, distribution, the
CTC, public benefit programs and nuclear decommissioning. The
transmission component of this rate unbundling process is being addressed
at the FERC through a March 1997 filing. (See PX and ISO discussion
below.) Hearings on SCE's rate unbundling (also known as rate-setting)
plan were concluded in April 1997. On August 1, 1997, the CPUC issued a
decision which adopted the methodology for determining CTC residually (see
CTC discussion below) and adopted SCE's revenue requirement components for
public benefit programs and nuclear decommissioning. The decision also
adjusted SCE's proposed distribution revenue requirement by reallocating
$76 million of it annually to other functions such as generation and
transmission. Under the decision, SCE will be able to recover most of the
annual $76 million through market revenue, the CTC mechanism after
petitioning the CPUC to modify its prior decisions, or another review
process later in the transition period.
PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San
Diego Gas & Electric Company filed a proposal with the FERC regarding the
creation of the PX and the ISO. In November 1996, the FERC conditionally
accepted the proposal and directed the three utilities, the ISO, and the
PX to file more specific information. The filing was made on March 31,
1997, and included SCE's proposed transmission revenue requirement. A
FERC decision is expected in late 1997. In July 1996, the three utilities
jointly filed an application with the CPUC requesting approval to
establish a restructuring trust which would obtain loans up to $250
million for the development of the ISO and PX through January 1, 1998.
The loans are backed by utility guarantees; SCE's share is 45%. The ISO
and PX will repay the trust's loans and recover funds from future ISO and
page 7
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PX Customers. In August 1996, the CPUC issued an interim order
establishing the restructuring trust and the funding level of $250
million, which will be used to build the hardware and software systems for
the ISO and PX.
Direct Customer Access - On May 6, 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC on May 6, 1997,
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
maximum demand above 20 kW (primarily industrial and large commercial) can
choose SCE or any other supplier to provide their metering service. All
other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security. SCE is reviewing the potential effect of these
decisions on its results of operations and financial condition.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D), and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-
end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was
no longer critical to the restructuring process and asked SCE to make
page 8
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
a compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. It is anticipated that the
difference between the CPUC-determined hydroelectric revenue requirement
and the market revenue from hydroelectric generation would flow through
the CTC mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil- and gas-fueled generation
divestiture was requested for late 1997.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, T&D, nuclear decommissioning and public benefit programs).
Nevertheless, the CPUC directed that the amended application provide
estimates of SCE's potential transition costs from 1998 through 2030. SCE
provided two estimates between approximately $13.1 billion (1998 net
present value) assuming the fossil plants have a market value equal to
their net book value, and $13.8 billion (1998 net present value) assuming
the fossil plants have no market value. These estimates are based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect
these estimates. The potential transition costs are comprised of: $7.5
billion from SCE's qualifying facility contracts, which are the direct
result of legislative and regulatory mandates; and $5.6 billion to $6.3
billion from costs pertaining to certain generating plants and regulatory
commitments consisting of costs incurred (whose recovery has been deferred
by the CPUC) to provide service to customers. Such commitments include
the recovery of income tax benefits previously flowed-through to
customers, postretirement benefit transition costs, accelerated recovery
of San Onofre Nuclear Generating Station Units 2 and 3 and the Palo Verde
Nuclear Generating Station units, and certain other costs. In February
1997, SCE filed an update to the CTC filing to reflect approval by
page 9
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde
and the buyout of a power purchase agreement, as well as other minor data
updates. No substantive changes in the total CTC estimates were included.
This issue has been separated into two phases: Phase 1 captures the
ratemaking issues and Phase 2 the quantification issues. Hearings on
Phase 1 were held in December 1996 and a decision was issued on June 11,
1997, which, among other things, required the establishment of a
transition cost balancing account and annual transition cost proceedings,
set a market rate forecast for 1998 transition costs, and required that
generation-related regulatory assets be amortized ratably over a 48-month
period. Hearings on Phase 2 were held in May and June 1997. A decision
on Phase 2 is expected in the fourth quarter of 1997.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be
subject to a lower authorized rate of return).
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting.
If, as expected, this consensus is formally issued by the EITF, SCE will
be required to discontinue application of these regulatory accounting
standards immediately for its generation-related operations. The net
plant investment related to these operations is approximately $5.0
billion. SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $800 million
at June 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed-through to customers,
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
rate phase-in plan. The consensus reached at the July EITF meeting also
permits the recording of new generation-related assets during the
transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the
recovery of these generation-related regulatory assets no longer probable,
SCE would be required to write off the remaining balance of such assets
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
page 10
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
opportunity to recover stranded costs associated with existing wholesale
customers, retail-turned-wholesale customers and retail wheeling when the
state regulatory body does not have authority to address retail stranded
costs. Even though the CPUC is currently addressing stranded cost
recovery through the CTC proceedings, the FERC has also asserted primary
jurisdiction over the recovery of stranded costs associated with retail-
turned-wholesale customers, such as a new municipal electric system or a
municipal annexation. However, the FERC did clarify that it does not
intend to prevent or interfere with a state's authority and that it has
discretion to defer to a state stranded-cost-calculation method. In
January 1997, the FERC accepted the open access transmission tariff SCE
filed in compliance with the April 1996 decision. The rates included in
the tariff are being collected subject to refund. In May 1997, SCE filed
a revised open access tariff to reflect the few revisions set forth in the
March 1997 order.
Canadian Gas Contracts
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994
record periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowances have been
consolidated into one proceeding. SCE and the ORA filed several rounds
of testimony on this issue. Hearings concluded in February 1997. On July
11, 1997, SCE and the ORA executed an agreement that settles all pending
and future issues related to these contracts. The settlement agreement,
which was filed on July 16, 1997, is subject to CPUC approval and has been
fully reflected in the financial statements. A decision is expected in
late 1997.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 during
construction and will be required to fund all remaining costs of the
project facility until the close of non-recourse financing. Estimated
total cost is $492 million, of which $454 million has been spent through
June 30, 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.
Environmental Protection
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site using currently available
information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level
of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure.
Unless there is a probable amount, Edison International records the lower
end of this reasonably likely range of costs (classified as other long-
term liabilities at undiscounted amounts). While Edison International has
numerous insurance policies that it believes may provide coverage for some
of these liabilities, it does not recognize recoveries in its financial
statements until they are realized.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached an agreement with the California Coastal Commission
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
in 1991 to restore certain marine mitigation sites. The restorations
include two sites incorporating particular wetlands and the construction
of an artificial kelp reef off the California coast. After SCE requested
certain modifications to the agreement, the Coastal Commission issued a
final ruling in April 1997 to reduce the scope of remediation required at
these two sites. SCE elected to pay for the costs of marine mitigation
in lieu of placing the funds into a trust. Rate recovery of these costs
is occurring through the San Onofre incentive pricing plan.
Edison International's recorded estimated minimum liability to remediate
its 56 identified sites (55 at SCE and 1 at EME) is $186 million, which
includes $75 million for the two sites discussed above. The ultimate
costs to clean up Edison International's identified sites may vary from
its recorded liability due to numerous uncertainties inherent in the
estimation process, such as: the extent and nature of contamination; the
scarcity of reliable data for identified sites; the varying costs of
alternative cleanup methods; developments resulting from investigatory
studies; the possibility of identifying additional sites; and the time
periods over which site remediation is expected to occur. Edison
International believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to
$245 million. The upper limit of this range of costs was estimated using
assumptions least favorable to Edison International among a range of
reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $99 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 $160 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates. This
amount includes $60 million of marine mitigation costs remaining to be
recovered through the San Onofre incentive pricing plan.
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.
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EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased
the maximum private primary insurance available ($200 million). The
balance is covered by the industry's retrospective rating plan that uses
deferred premium charges to every reactor licensee if a nuclear incident
at any licensed reactor in the U.S. results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary
level, effective June 1994. The maximum deferred premium for each nuclear
incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its
ownership interests, SCE could be required to pay a maximum of $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability
claims and are subject to adjustment for inflation. If the public
liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500 million
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 $33 million per year.
Insurance premiums are charged to operating expense.
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EDISON INTERNATIONAL
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
In the following Management's Discussion and Analysis of Results of
Operations and Financial Condition and elsewhere in this quarterly report,
the words "estimates," "expects," "anticipates," "believes," and other
similar expressions, are intended to identify forward-looking information
that involves risks and uncertainties. Actual results or outcomes could
differ materially as a result of such important factors as the outcome of
state and federal regulatory proceedings affecting the restructuring of
the electric utility industry, the impacts of new laws and regulations
relating to restructuring and other matters, the effects of increased
competition in the electric utility business, and changes in prices of
electricity and costs for fuel.
RESULTS OF OPERATIONS
Earnings
Edison International's earnings per share for the three and six months
ended June 30, 1997, were 34 cents and 69 cents, respectively, compared
with 35 cents and 73 cents for the same periods in 1996. In the second
quarter of 1997, a 3-cent one-time gain on sale of oil and gas properties
at Edison Mission Energy (EME) was offset by a 3-cent charge related to the
refinancing of debt at EME's Loy Yang B project in conjunction with the
purchase of the remaining 49% interest in the project. Non-recurring
charges were 4 cents (net) in the second quarter of 1996 (a 7-cent charge
at Southern California Edison Company (SCE) for workforce adjustments and
a 3-cent gain on sale of geothermal projects at EME). Before one-time
items, SCE's earnings for the three and six months ended June 30, 1997,
were 30 cents and 57 cents, respectively, down 5 cents and 9 cents from
the year-earlier periods, primarily due to the impact of the
extended refueling outages at the San Onofre Nuclear Generating Station.
These decreases were partially offset by a reduction in costs from
operations and an increase in electricity sales. The combined earnings
of EME, Edison Capital and Mission Land for the three and six months ended
June 30, 1997, were 7 cents and 16 cents (before non-recurring items),
respectively, up 2 cents and 3 cents from the year-earlier periods, mainly
due to new leveraged leases at Edison Capital and improved operating
performance at EME. Edison Enterprises (consisting of Edison Source,
Edison Select and Edison EV) and the parent company had combined expenses
for the three and six months ended June 30, 1997, of 3 cents and 4 cents,
respectively, which is 2 cents more for expenses in each period than the
same periods in 1996, primarily due to start-up costs at Edison Enterprises.
Edison International's earnings per share also benefited from the effects
of the ongoing share repurchase program.
Operating Revenue
Electric utility revenue increased 15% during the three months ended June
30, 1997, due to a higher volume of sales within all customer groups
compared to the same period last year and increased demand for electricity
due to unseasonably warm weather during the month of May 1997. The higher
volume is also attributable to an increase in the number of customers over
the prior year. Electric revenue for the six months ended June 30, 1997
increased slightly from 1996. Average retail rates were approximately 8%
higher during the second quarter of 1997, compared with same period of the
prior year. Over 98% of SCE's electric utility revenue is from retail
sales. Retail rates are regulated by the California Public Utilities
Commission (CPUC) and wholesale rates are regulated by the Federal Energy
Regulatory Commission (FERC).
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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 (financed through the
issuance of rate reduction bonds) beginning in 1998 (see Competitive
Environment).
Revenue from diversified operations increased substantially due to the
sale of real estate by Mission Land Company valued at $63 million during
the second quarter and 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 second quarter of 1996. In
addition, higher pool prices and increased utilization contributed to
increased revenue at EME's First Hydro project. In May 1997, EME completed
the acquisition of the remaining 49% interest of the Loy Yang B power
plant near Melbourne, Australia. 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 20% and 29%, respectively, for the three- and six-
month periods ended June 30, 1997. The increases are due to higher gas
prices and the extended refueling outages at San Onofre. San Onofre Unit
2 was shut down the entire first quarter of 1997 and Unit 3 was shut down
80 days of the second quarter, thus resulting in an overall increase in
gas-powered generation for both periods presented. There were no
comparable outages 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 of 1996 and higher costs for pumping fuel at the First Hydro
project due to increased generation and higher prices during both the
first and second quarters of 1997.
Purchased-power expense increased slightly during the quarter and
increased 12% during the six-month period ended June 30, 1997. The
increase is due to an increase in purchases in the open market
particularly in the Southwest and increases in power purchased under
federally mandated contracts. SCE is required under federal law to
purchase power from certain nonutility generators even though energy
prices under these contracts are generally higher than other sources. For
the twelve months ended June 30, 1997, SCE paid about $1.6 billion
(including energy and capacity payments) more for these power purchases
than the cost of power available from other sources. The CPUC has
mandated the prices for these contracts.
Provisions for regulatory adjustment clauses increased substantially for
the three months ended June 30, 1997, compared to the year-earlier period.
The quarterly increase is primarily due to the effect of the 1996 CPUC-
ordered $237 million refund to customers for energy cost balancing account
overcollections of which $179 million was paid in the second quarter of
1996. There was no comparable refund paid in 1997. The quarterly
increase is also attributable to the San Onofre Units 2 and 3 refueling
outages. Undercollections in the second quarter of 1996 at San Onofre
(the San Onofre units operated at higher capacities than estimated) were
partially offset by overcollections in the second quarter of 1997 due to
decreased nuclear generation as a result of the outages at Units 2 and 3.
Another contribution to the quarterly increase is overcollections due to
the accelerated recovery of SCE's remaining investment at San Onofre. For
the six months ended June 30, 1997, the provisions increased 11%, compared
with the same period in 1996. The year-to-date increase is primarily due
to overcollections related to: the San Onofre second quarter factors
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discussed above; actual base-rate revenue from kilowatt-hour sales
exceeding CPUC-authorized estimates; and the effect of the 1996 CPUC-
ordered refund, also discussed above. However, these overcollections were
almost completely offset by actual energy costs exceeding CPUC-authorized
fuel and purchased-power cost estimates.
Maintenance expense increased substantially in all periods presented
compared with the year-earlier periods, due to scheduled refueling outages
at the San Onofre units and increased maintenance costs for SCE's electric
plant assets. There were no comparable outages for the nuclear units
during the same periods 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 periods
in 1996.
Depreciation and decommissioning expense increased 14% and 21%,
respectively, for the quarter and year-to-date ended June 30, 1997, due
to increases in plant assets and the accelerated recovery of San Onofre
Units 2 and 3 effective April 1996 and the accelerated recovery of the
Palo Verde Nuclear Generating Station units effective January 1997.
Depreciation and decommissioning expense increased at EME due to the
start-up of the Loy Yang B Unit 2 and Kwinana projects which began
commercial operation in the fourth quarter of 1996.
Income taxes decreased 11% and 12%, respectively, for the quarter and
year-to-date ended June 30, 1997, compared to the year-earlier periods,
due to a decrease in pre-tax income.
Property and other taxes decreased 29% and 31%, respectively, for the
three and six months ended June 30, 1997, compared to the same periods in
1996, due to changes in SCE's internal payroll tax allocation methods in
1997 from 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
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 decreased 31% for the three-month period ending June 30,
1997, primarily from the May 1997 acquisition of the remaining 49%
interest in EME's Loy Yang B project. For the six months ended June 30,
1997, minority interest increased 35% due to Loy Yang B Unit 2 commencing
commercial operation in October 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, partially offset by prior-year accruals for
regulatory expenses and other operating reserves at SCE.
Interest and Other Expenses
Other interest expense increased 14% and 35% for the three and six months
ended June 30, 1997, due to balancing account overcollections at SCE and
increases in interest expense at EME resulting from the inclusion of
interest on $450 million of securities issued by Edison Mission Energy
Funding Corp. in December 1996. This was partially offset by the December
1996 repayment of a 200 million Australian dollar loan.
Capitalized interest decreased, primarily due to the completion of
construction of Loy Yang B Unit 2 and other projects in the fourth quarter
of 1996.
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FINANCIAL CONDITION
Edison International's liquidity is primarily affected by debt maturities,
dividend payments, capital expenditures and investments in partnerships
and unconsolidated subsidiaries. Capital resources include cash from
operations and external financings.
Edison International's Board of Directors has authorized the repurchase
of up to $2.3 billion of its outstanding shares of common stock. Edison
International has repurchased 52.2 million shares ($1.1 billion)
between January 1995 and August 1, 1997, funded by dividends from its
subsidiaries and its lines of credit.
For the six months ended June 30, 1997, Edison International's cash flow
coverage of dividends decreased to 4.8 times from 5.4 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 June 30, 1997, was 63%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.0 billion for the
six-month period ended June 30, 1997, compared with $1.2 billion in 1996.
Cash from operations exceeded capital requirements for both periods
presented.
Cash Flows from Financing Activities
At June 30, 1997, Edison International and its subsidiaries had $2.5
billion of borrowing capacity available under lines of credit totaling
$3.2 billion. SCE had available lines of credit of $1.8 billion, with $1.3
billion for general purpose, short-term debt and $500 million for the
long-term refinancing of its variable-rate pollution-control bonds. The
parent company had a $650 million line of credit with $145 million of
borrowing capacity available. The nonutility companies had available
lines of credit of $800 million, with $585 million of borrowing capacity
available to finance general cash requirements. Edison International's
unsecured lines of credit are at negotiated or bank index rates with
various expiration dates; the majority have five-year terms.
SCE's short-term debt is used to finance fuel inventories, balancing
account undercollections and general cash requirements. EME uses short-
term debt and available credit lines mainly for construction projects
until long-term construction or project loans are secured. Long-term debt
is used mainly to finance capital expenditures. SCE's external financings
are influenced by market conditions and other factors, including
limitations imposed by its articles of incorporation and trust indenture.
As of June 30, 1997, SCE could issue approximately $8.7 billion of
additional first and refunding mortgage bonds and $4.7 billion of
preferred stock at current interest and dividend rates.
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 $454 million had been spent through June 30, 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
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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.
In April 1997, EME completed financing and commenced construction of the
Doga Energi 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 $25 million in equity contributions
and will continue making equity contributions until commercial operation
begins which is scheduled for late 1998.
EME has firm commitments to make equity and other contributions to its
projects of $355 million, primarily for the Paiton project in Indonesia,
the ISAB project in Italy, and the Doga Energi Project in Turkey. EME
also has contingent obligations to make additional contributions of $482
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.
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
June 30, 1997, SCE had the capacity to pay $512 million in additional
dividends and continue to maintain its authorized capital structure.
These restrictions are not expected to affect Edison International's
ability to meet its cash obligations.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant, the nonutilities' investments in partnerships and
unconsolidated subsidiaries, and funding of nuclear decommissioning
trusts. Decommissioning costs are accrued and recovered in rates over the
term of each nuclear generating facility's operating license through
charges to depreciation expense. SCE estimates that it will spend
approximately $12.7 billion between 2013-2070 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar decommissioning
costs ($2.0 billion), escalated using a 6.65% 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 $389
million for the six-month period ended June 30, 1997, compared with $175
million for the same period in 1996.
Edison International's risk management policy allows the use of derivative
financial instruments to mitigate risk. Changes in interest rates,
electricity pool pricing in the United Kingdom and Australia and
fluctuations in foreign currency exchange rates can have a significant
impact on EME's results of operations. EME has mitigated the risk of
interest rate fluctuations by arranging for fixed rate or variable rate
financing with interest rate swaps or other hedging mechanisms for the
majority of its project financings. As a result of interest rate hedging
mechanisms, interest expense increased $7 million and $4 million,
respectively, for the six months ended June 30, 1997, and 1996. The
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maturity dates of several of EME's interest rate swap agreements do not
correspond to the term of the underlying debt. EME does not believe that
interest rate fluctuations will have a material adverse effect on its
results of operations or financial position.
Projects in the United Kingdom sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly
clearing price for electrical energy. The pool price is extremely
volatile, and can vary by a factor of ten or more over the course of a few
hours due to large differentials in demand according to the time of day.
First Hydro mitigates a portion of the market risk of the pool by entering
into contracts for differences (electricity rate swap agreements), related
to either the selling or purchase price of power, whereby a contract
specifies a price at which the electricity will be traded, and the parties
to the agreements make payments, calculated based on the difference
between the price in the contract and the half hourly clearing price for
the element of power under contract. These contracts act as a means of
stabilizing production revenue or purchasing costs by removing an element
of First Hydro's net exposure to pool price volatility. First Hydro's
electric revenue increased by $20 million for the six months ended June
30, 1997, compared to a decrease of $2 million in the corresponding period
of the prior year, as a result of electricity rate swap agreements.
Loy Yang B sells their electrical energy through a centralized electricity
pool (Victorian Wholesale Electricity Market which will be integrated into
the National Electricity Market), which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing
market for each half-hour of every day. The Victorian Power Exchange,
operator and administrator of the pool, determines a system marginal price
each half-hour. To mitigate the exposure to price volatility of the
electricity traded in the pool, Loy Yang B has entered into a number of
financial hedges. From May 8, 1997, to December 31, 2000, approximately
53% to 64% of the plant output sold is hedged under vesting contracts with
the remainder of the plant capacity hedged under the state hedge. Vesting
contracts were put into place by the State, between each generator and
each distributor, prior to the privatization of electric power
distributors in order to provide more predictable pricing for those
electricity customers that were unable to choose their electricity
retailer. Vesting contracts set base strike prices at which the
electricity will be traded, and the parties to the agreement make
payments, calculated based on the difference between the price in the
contract and the half-hourly pool clearing price for the element of power
under contract. These contracts can be sold as one-way or two-way
contracts which are structured similar to the electricity rate swap
agreements described above. The state hedge is a long-term contractual
arrangement based upon a fixed price commencing May 8, 1997, and
terminating October 31, 2016. The State guarantees the State Electricity
Commission of Victoria's obligations under the state hedge. Loy Yang B's
electric revenue was increased by $14 million for the period ended June
30, 1997, as a result of hedging contract arrangements.
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.
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Projected Capital Requirements
Edison International's projected capital requirements for the next five
years are: 1997--$896 million; 1998--$998 million; 1999--$757 million;
2000--$730 million; and 2001--$712 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 1997, are: 1998--$630 million;
1999--$606 million; 2000--$636 million; 2001--$554 million; and 2002--$215
million.
Preferred stock redemption requirements for the five twelve-month periods
following June 30, 1997, are: 1998 through 2001--zero and 2002--$105
million.
REGULATORY MATTERS
SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to
recently enacted legislation which requires that rates remain frozen at
the June 10, 1996, level (system average of 10.1 cents per kilowatt-hour).
See further discussion in Competitive Environment.
The CPUC's 1997 cost-of-capital decision authorized 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 the accelerated
recovery portion and in December 2003 for the incremental pricing portion.
Palo Verde's incremental operating costs, including incremental capital
costs, and nuclear fuel and nuclear fuel financing costs, are subject to
balancing account treatment. The Palo Verde plan commenced in January
1997 and ends in December 2001.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994 record
periods. The report recommends a disallowance of $13 million for
excessive costs incurred from November 1993 through March 1994 associated
with SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding SCE's Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs under these contracts be reviewed on a yearly basis. In
October 1996, the ORA issued its report for the 1995 record period
recommending a $38 million disallowance for excessive costs incurred from
April 1994 through March 1995. Both proposed disallowances have been
consolidated into one proceeding. SCE and the ORA filed several rounds
of testimony on this issue. Hearings concluded in February 1997. On July
11, 1997, SCE and the ORA executed an agreement that settles all pending
and future issues related to these contracts. The settlement agreement,
which was filed on July 16, 1997, is subject to CPUC approval and has been
fully reflected in the financial statements. A decision is expected in
late 1997.
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COMPETITIVE ENVIRONMENT
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing. The generation sector has experienced
competition from nonutility power producers and regulators are
restructuring California's electric utility industry.
California Electric Utility Industry Restructuring
Restructuring Legislation - In September 1996, the State of California
enacted legislation to provide a transition to a competitive market
structure. The legislation substantially adopts the CPUC's December 1995
restructuring decision by addressing stranded-cost recovery for utilities
and providing a certain cost-recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which would
allow SCE to reduce rates by at least 10% to these customers, beginning
January 1, 1998. The financing would occur with securities issued by the
California Infrastructure and Economic Development Bank, or an entity
approved by the Bank. The legislation includes a rate freeze for all
other customers, including large commercial and industrial customers, as
well as provisions for continued funding for energy conservation, low-
income programs and renewable resources. Despite the rate freeze, SCE
expects to be able to recover its revenue requirement based on cost-of-
service regulation during the 1998-2001 transition period. In addition,
the legislation mandates the implementation of a non-bypassable
competition transition charge (CTC) that provides utilities the
opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses for utility workers.
Rate Reduction Bonds - On May 6, 1997, SCE filed an application with the
CPUC requesting approval of the issuance of an aggregate amount of up to
$3 billion of rate reduction bonds in one or more series or classes and
a 10% rate reduction for the period from January 1, 1998, through March
31, 2002. On the same day, SCE filed an application with the California
Infrastructure and Economic Development Bank for approval to issue the
bonds. Residential and small commercial customers will repay the bonds
over the expected 10-year term through non-bypassable charges based on
electricity consumption. With the CPUC's decision expected in September
1997, and subject to the prior approval of the Infrastructure Bank, it is
anticipated that the rate reduction bonds will be issued in the fourth
quarter of 1997.
CPUC Restructuring Decision - The CPUC's December 1995 decision on
restructuring California's electric utility industry started the
transition to a new market structure, which is expected to provide
competition and customer choice and is scheduled to begin January 1, 1998.
Key elements of the CPUC's restructuring decision include: creation of
an independent power exchange (PX) and independent system operator (ISO);
availability of direct customer access and customer choice; performance-
based ratemaking (PBR) for those utility services not subject to
competition; voluntary divestiture of at least 50% of utilities' gas-
fueled generation, and implementation of a non-bypassable charge to all
customers called the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
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separating costs as requested by CPUC and FERC directives) for the
functional unbundling of its rates for electric service, beginning January
1, 1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates into separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The transmission component of this rate
unbundling process is being addressed at the FERC through a March 1997
filing. (See PX and ISO discussion below.) Hearings on SCE's rate
unbundling (also known as rate-setting) plan were concluded in April 1997.
On August 1, 1997, the CPUC issued a decision which adopted the
methodology for determining CTC residually (see CTC discussion below) and
adopted SCE's revenue requirement components for public benefit programs
and nuclear decommissioning. The decision also adjusted SCE's proposed
distribution revenue requirement by reallocating $76 million of it
annually to other functions such as generation and transmission. Under
the decision, SCE will be able to recover most of the annual $76 million
through market revenue, the CTC mechanism after petitioning the CPUC to
modify its prior decisions, or another review process later in the
transition period.
PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San
Diego Gas & Electric Company filed a proposal with the FERC regarding the
creation of the PX and the ISO. In November 1996, the FERC conditionally
accepted the proposal and directed the three utilities, the ISO and the
PX to file more specific information. The filing was made on March 31,
1997, and included SCE's proposed transmission revenue requirement. A
FERC decision is expected in late 1997. In July 1996, the three utilities
jointly filed an application with the CPUC requesting approval to
establish a restructuring trust which would obtain loans up to $250
million for the development of the ISO and PX through January 1, 1998.
The loans are backed by utility guarantees; SCE's share is 45%. The ISO
and PX will repay the trust's loans and recover funds from future ISO and
PX customers. In August 1996, the CPUC issued an interim order
establishing the restructuring trust and the funding level of $250
million, which will be used to build the hardware and software systems
for the ISO and PX.
Direct Customer Access - On May 6, 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service.
Beginning January 1, 1998, customers will be able to choose to remain
utility customers with bundled electric service from SCE (which will
purchase its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or retail electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned-utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through its distribution system regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC believes it is likely that interest in and migration to
direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC on May 6, 1997,
introduces customer choice to metering, billing and related services
(referred to as revenue cycle services) that are now provided by
California's investor-owned utilities. Under this revenue cycle services
"unbundling" decision, beginning in January 1998, direct access customers
may choose to have either SCE or their electric generation service
provider render consolidated (energy and distribution) bills, or they may
choose to have separate billings from each service provider. However, not
all electric generation service providers will necessarily offer each
billing option. In addition, beginning in January 1998, customers with
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maximum demand above 20 kW (primarily industrial and large commercial)
can choose SCE or any other supplier to provide their metering service.
All other customers will have this option beginning in January 1999. In
determining whether any credit should be provided by the utility to firms
providing customers with revenue cycle services, and the amount of any
such credit, the CPUC has indicated that it is appropriate to "net" the
cost incurred by the utility and the cost avoided by the utility as a
result of such services being provided by the other firm rather than by
the utility. The unbundling of revenue cycle services is likely to expose
SCE to the loss of revenue, higher stranded costs and a reduction in
revenue security. SCE is reviewing the potential effect of these
decisions on its results of operations and financial condition.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D) and power generation. With the
CPUC's 1995 restructuring decision and the passage of restructuring
legislation in 1996, the majority of power generation ratemaking
(primarily fossil-fueled and nuclear) was assigned to other mechanisms.
In July 1996, SCE filed a PBR proposal for its hydroelectric plants and
a proposed structure for performance-based local reliability contracts for
certain fossil-fueled plants. In April 1997, a CPUC interim order
determined that the proposed structure for the fossil-fueled plants' local
reliability contracts should be determined by the ISO, and therefore would
be under the FERC's jurisdiction. A FERC decision is expected by year-end
1997. In June 1997, the CPUC determined that a hydroelectric PBR was no
longer critical to the restructuring process and asked SCE to make a
compliance filing to determine the revenue requirement necessary for
hydroelectric generation operations. It is anticipated that the
difference between the CPUC-determined hydroelectric revenue requirement
and the market revenue from hydroelectric generation would flow through
the CTC mechanism. A final CPUC decision is expected by year-end 1997.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil-and gas-fueled generation
divestiture was requested for late 1997.
CTC - Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
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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. In February 1997,
SCE filed an update to the CTC filing to reflect approval by the CPUC of
settlements regarding ratemaking for SCE's share of Palo Verde and the
buyout of a power purchase agreement, as well as other minor data updates.
No substantive changes in the total CTC estimates were included. This
issue has been separated into two phases: Phase 1 captures the ratemaking
issues and Phase 2 the quantification issues. Hearings on Phase 1 were
held in December 1996 and a decision was issued on June 11, 1997, which,
among other things, required the establishment of a transition cost
balancing account and annual transition cost proceedings, set a market
rate forecast for 1998 transition costs, and required that generation-
related regulatory assets be amortized ratably over a 48-month period.
Hearings on Phase 2 were held in May and June 1997. A decision on Phase
2 is expected in the fourth quarter of 1997.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be
subject to a lower authorized rate of return).
As previously reported, since November 1996, SCE and the other major
California electric utilities have been engaged in discussions with the
Securities and Exchange Commission staff regarding the proper application
of regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting.
If, as expected, this consensus is formally issued by the EITF, SCE will
be required to discontinue application of these regulatory accounting
standards immediately for its generation-related operations. The net
plant investment related to these operations is approximately $5.0
billion. SCE will not be required to write off any of its generation-
related assets, including regulatory assets of approximately $800 million
at June 30, 1997. SCE will retain these assets on its balance sheet
because the legislation and restructuring plan referred to above make
probable their recovery through a non-bypassable CTC to distribution
customers. These regulatory assets relate primarily to the recovery of
accelerated income tax benefits previously flowed-through to customers,
purchased power contract termination payments, unamortized losses on
reacquired debt, and the recovery of amounts deferred under the Palo Verde
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rate phase-in plan. The consensus reached at the July EITF meeting also
permits the recording of new generation-related assets during the
transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the
recovery of these generation-related regulatory assets no longer probable,
SCE would be required to write off the remaining balance of such assets
as a one-time, non-cash charge against earnings. If such a write-off were
to be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
FERC Restructuring Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision, reaffirmed
in a March 1997 FERC order, requires all electric utilities subject to the
FERC's jurisdiction to file transmission tariffs which provide competitors
with increased access to transmission facilities for wholesale
transactions and also establishes information requirements for the
transmission utility. The decision also provides utilities with the
opportunity to recover stranded costs associated with existing wholesale
customers, retail-turned-wholesale customers and retail wheeling when the
state regulatory body does not have authority to address retail stranded
costs. Even though the CPUC is currently addressing stranded cost
recovery through the CTC proceedings, the FERC has also asserted primary
jurisdiction over the recovery of stranded costs associated with retail-
turned-wholesale customers, such as a new municipal electric system or a
municipal annexation. However, the FERC did clarify that it does not
intend to prevent or interfere with a state's authority and that it has
discretion to defer to a state stranded-cost-calculation method. In
January 1997, the FERC accepted the open access transmission tariff SCE
filed in compliance with the April 1996 decision. The rates included in
the tariff are being collected subject to refund. In May 1997, SCE filed
a revised open access tariff to reflect the few revisions set forth in the
March 1997 order.
ENVIRONMENTAL PROTECTION
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
As further discussed in Note 2 of the Consolidated Financial Statements,
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
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likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site. Unless there is a
probable amount, Edison International records the lower end of this range
of costs.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached agreement with the California Coastal Commission in
1991 to restore certain marine mitigation sites. The restorations include
two sites incorporating particular wetlands and the construction of an
artificial kelp reef off the California coast. After SCE requested
certain modifications to the agreement, the Coastal Commission issued a
final ruling in April 1997 to reduce the scope of remediation required at
these two sites. SCE elected to pay for the costs of marine mitigation
in lieu of placing the funds into a trust. Rate recovery of these costs
is occurring through the San Onofre incentive pricing plan.
Edison International's recorded estimated minimum liability to
remediate its 55 identified sites is $186 million, which includes $75
million for the two sites discussed above. One of SCE's sites, a former
pole-treating facility, is considered a federal Superfund site and
represents 43% of 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 $245 million. The upper limit of this
range of costs was estimated using assumptions least favorable to Edison
International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its
sites, representing $99 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 $160 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates. This
amount includes $60 million of marine mitigation costs remaining to be
recovered through the San Onofre incentive pricing plan.
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.
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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
steam generator tube degradation. However, during the Unit 2 scheduled
refueling and inspection outage, which was completed in Spring 1997, an
increased rate of tube degradation was identified, resulting in removing
1.8% of the tubes from service. The cumulative total of Unit 2's tubes
removed from service is now 5.5%, well below the maximum 10% allowed in
the steam generator design before the rating capacity of the unit must be
reduced. As a result of the increased degradation, a mid-cycle inspection
outage will be conducted in 1998 for Unit 2.
During Unit 3's refueling outage, which was completed in July 1997,
inspections of structural supports for steam generator tubes identified
several areas where the thickness of the supports had been reduced,
apparently by erosion during normal plant operation. As a result, a mid-
cycle outage is planned for 1998. However, during Unit 2's Spring 1997
inspection outage, similar tube supports showed no signs of such erosion.
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NEW EARNINGS PER SHARE STANDARD
A new accounting pronouncement establishes standards for computing and
presenting earnings per share. The standard must be implemented for year-
end 1997 financial reports and, in some instances, will require
restatement of prior-period earnings per share data; earlier application
of the standard is not permitted. The standard will not have any effect
on Edison International's basic earnings per share, which replaces primary
earnings per share.
PROPOSED NEW ACCOUNTING STANDARD
During 1996, the Financial Accounting Standards Board issued an exposure
draft that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for the decommissioning of its nuclear power plants, obligations for coal
mine reclamation costs and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
The nonutility subsidiaries are currently reviewing what impact the
exposure draft may have on their results of operations and financial
position.
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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 Southern
California Edison Company (SCE) in Los Angeles County Superior Court,
claiming that SCE underpaid, and continues to underpay, the plaintiffs for
energy. SCE denied the allegations in its response to the complaint. The
action was brought on behalf of Vulcan/BN Geothermal Power Company, Elmore
L.P., Del Ranch L.P. and Leathers L.P., each of which was partially owned
by a subsidiary of Edison Mission Energy (a subsidiary of Edison
International) at the time of filing. In April 1996, Edison Mission
Energy's 50% share in these projects was sold to CalEnergy. In October
1994, plaintiffs submitted an amended complaint to the court to add causes
of action for unfair competition and restraint of trade. In July 1995,
after several motions to strike had been heard by the court, the
plaintiffs served a fourth amended complaint, which omitted the previous
claims based on alleged restraint of trade. The plaintiffs allege in the
fourth amended complaint that past underpayments have totaled at least $21
million. In other court filings, plaintiffs contend that additional
contract payments owing from the beginning of the alleged underpayments
through the end of the contract term could total approximately $60
million. Plaintiffs also seek unspecified punitive damages and an
injunction to enjoin SCE from "future" unfair competition. After SCE's
motion to strike portions of the fourth amended complaint was denied, SCE
filed an answer to the fourth amended complaint which denies its material
allegations.
On May 1, 1996, the parties entered into an agreement for a settlement of
all claims in dispute. Pursuant to the agreement, the specific terms of
which are confidential, a settlement amount has been paid and the parties
have entered into mutual general releases, with respect to the period
before January 1, 1996. SCE intends to seek recovery of this payment
through rates. SCE has also agreed, subject to California Public
Utilities Commission (CPUC) approval, to increase payments to plaintiffs
for specified levels of energy deliveries for the period after December
31, 1995. Plaintiffs have reserved the right to continue the litigation
with respect to the period after December 31, 1995, if CPUC approval is
not obtained. On August 8, 1996, SCE filed its application with the CPUC
for approval of the settlement as it pertains to the period after 1995.
On December 20, 1996, the CPUC's Office of Ratepayer Advocates (ORA) filed
a protest to the application. In its protest, the ORA requests that the
page 30
<PAGE>
CPUC not grant the application or, in the alternative, that the CPUC
conduct hearings on the application. On January 17, 1997, SCE filed
a reply to the ORA's request. On February 27, 1997, a prehearing
conference was held, at which time SCE's application was set for hearing
to start on April 23, 1997. This hearing date was subsequently vacated
by the assigned administrative law judge due to ongoing discussions to
resolve issues raised by ORA's protest. As a result of those discussions,
SCE and the ORA entered into a stipulation and agreement (Stipulation)
effective July 11, 1997. In the Stipulation, the ORA agrees to withdraw
its protest and support SCE's application in return for SCE's agreement
that the cost recovery issues presented in the application may be
transferred for a decision in SCE's 1992 Energy Cost Adjustment Clause
(ECAC) proceeding, where related issues are currently pending. The
Stipulation further provides for SCE and the ORA to file a joint motion
for approval of the Stipulation, which SCE expects to file in August 1997.
In light of the Stipulation, plaintiffs and SCE have entered into two
amendments to the May 1, 1996, settlement agreement. The first amendment
provides for the post-1995 portion of the settlement to become effective
through 1997 upon CPUC approval consistent with the Stipulation. The
second amendment provides for plaintiffs to dismiss the lawsuit without
prejudice pending final CPUC resolution of the issues raised by SCE's
application. Accordingly, the application remains pending but without a
hearing date.
Wind Generators' Litigation
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189 million in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
Superior Court case granted the plaintiffs' motion seeking summary
adjudication that the contract language in question is not reasonably
susceptible to SCE's position that there is only a single, 10-year period
of fixed payments. Following the March 1 ruling, a ninth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first eight. SCE subsequently responded to the complaint
in the new lawsuit by denying its material allegations. On April 5, 1995,
SCE filed a petition for Writ of Mandate, Prohibition or Other Appropriate
Relief, requesting that the Court of Appeal of the State of California,
Second Appellate District issue a writ directing the Los Angeles Superior
Court to vacate its March 1 order granting summary adjudication. In a
decision filed August 9, 1995, the Court of Appeal issued a writ directing
that the order be overturned, and a new order be entered denying the
motion. In light of the Court of Appeal decision in the lead Los Angeles
case, a summary adjudication motion in the Kern County case was withdrawn.
On March 25, 1996, pursuant to a court-approved stipulation, all but one
of the cases were consolidated for trial in Los Angeles Superior Court.
Shortly thereafter, on April 3, 1997, pursuant to stipulation of the
parties, the Kern County case was ordered to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. Trial of the
consolidated cases, beginning with the lead case, commenced on March 10,
1997. The consolidated cases are to be tried one after another in
bifurcated fashion with the liability phase of each and all of the cases
to be tried before commencement of the damages phase, if applicable.
Testimony and arguments in the liability phase of the lead case concluded
on May 20, 1997 and is currently under submission. No trial date has been
set for the single case not consolidated for trial with the others.
page 31
<PAGE>
Electric and Magnetic Fields (EMF) Litigation
SCE is involved in three lawsuits alleging that various plaintiffs
developed cancer as a result of exposure to EMF from SCE facilities. SCE
denied the material allegations in its responses to each of these
lawsuits.
The first lawsuit was filed in Orange County Superior Court and served on
SCE in June 1994. There are five named plaintiffs and six named
defendants, including SCE. Three of the five plaintiffs are presently or
were formerly employed by Grubb & Ellis, a real estate brokerage firm with
offices located in a commercial building known as the Koll Center in
Newport Beach. Two of the named plaintiffs are spouses of the other
plaintiffs. Grubb & Ellis and the owners and developers of the Koll
Center are also named as defendants in the lawsuit. This lawsuit alleges,
among other things, that the three plaintiffs employed by Grubb & Ellis
developed various forms of cancer as a result of exposure to EMF from
electrical facilities owned by SCE and/or the other defendants located on
Koll Center property. No specific damage amounts are alleged in the
complaint, but supplemental documentation prepared by the plaintiffs
indicates that plaintiffs allege compensatory damages of approximately $8
million, plus unspecified punitive damages. In December 1995, the court
granted SCE's motion for summary judgment and dismissed the case.
Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but
no date for oral argument has been set.
A second lawsuit was filed in Orange County Superior Court and served on
SCE in January 1995. This lawsuit arises out of the same fact situation
as the June 1994 lawsuit described above and involves the same defendants.
There are four named plaintiffs, two of whom were formerly employed by
Grubb & Ellis and now allegedly have various forms of cancer. The other
two plaintiffs are the spouses of those two individuals. No specific
damage amounts are alleged in the complaint, but supplemental
documentation prepared by the plaintiffs indicates that plaintiffs will
allege compensatory damages of approximately $13.5 million, plus
unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a
cross-complaint against the other co-defendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. Although stayed for a time pending
appellate review of sanctions imposed against plaintiffs' attorneys by the
trial court, the case has been remanded back to the trial court following
the Court of Appeal's decision modifying the sanctions order. To date,
no further proceedings have been scheduled.
A third case was filed in Orange County Superior Court and served on SCE
in March 1995. The plaintiff alleges, among other things, that he
developed cancer as a result of EMF emitted from SCE distribution lines
which he alleges were not constructed in accordance with CPUC standards.
No specific damage amounts are alleged in the complaint but supplemental
documentation prepared by the plaintiff indicates that plaintiff will
allege compensatory damages of approximately $5.5 million, plus
unspecified punitive damages. No trial date has been set in this case.
San Onofre Personal Injury Litigation
An SCE engineer employed at San Onofre died in 1991 from cancer of the
abdomen. On February 6, 1995, his children sued SCE and San Diego Gas &
Electric (SDG&E), as well as Combustion Engineering, the manufacturer of
the fuel rods for the plant, in the U.S. District court for the Southern
District of California. Plaintiffs alleged that the former employee's
illness resulted from, and was aggravated by, exposure to radiation at San
Onofre, including contact with radioactive fuel particles released from
failed fuel rods. Plaintiffs sought unspecified compensatory and punitive
damages. On April 3, 1995, the court granted the defendants' motion to
dismiss 14 of the plaintiffs' 15 claims. SCE's April 20, 1995, answer to
page 32
<PAGE>
the complaint denied all material allegations. On October 10, 1995, the
court granted plaintiffs' motion to include the Institute of Nuclear Power
Operations (an organization dedicated to achieving excellence in nuclear
power operations) as a defendant in the suit. On December 7, 1995, the
court granted SCE's motion for summary judgment on the sole outstanding
claim against it, basing the ruling on the worker's compensation system
being the exclusive remedy for the claim. Plaintiffs have appealed this
ruling to the Ninth Circuit Court of Appeals. All trial court proceedings
have been stayed pending the ruling of the Court of Appeals. The impact
on SCE, if any, from further proceedings in this case against the
remaining defendants cannot be determined at this time.
On July 5, 1995, a former SCE reactor operator and his wife sued SCE and
SDG&E in the U.S. District court for the Southern District of California.
Plaintiffs also named Combustion Engineering, the manufacturer of the fuel
rods for the plant, and the Institute of Nuclear Power Operations as
defendants. The former employee died of leukemia shortly after the
complaint was filed. Plaintiffs allege that the former operator's illness
resulted from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles released from failed
fuel rods. Plaintiffs seek unspecified compensatory and punitive damages.
On November 22, 1995, the complaint was amended to allege wrongful death
and added the former employee's two children as plaintiffs. On December
22, 1995, SCE filed a motion to dismiss or, in the alternative, for
summary judgment based on worker's compensation exclusivity. On March 25,
1996, the court granted SCE's motion for summary judgment. Plaintiffs
have appealed this ruling to the Ninth Circuit Court of Appeals. All
trial court proceedings have been stayed pending the ruling of the Court
of Appeals in this case and in the case described in the above paragraph.
The impact on SCE, if any, from further proceedings in this case against
the remaining defendants cannot be determined at this time.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District court for the Southern
District of California. Plaintiffs also named Combustion Engineering, the
manufacturer of fuel rods for the plant, and the Institute of Nuclear
Power Operations as defendants. The security officer worked for a
contractor in 1982, worked for SCE as a temporary employee (1982-1984),
and later worked as an SCE security supervisor (1984-1994). The officer
died of leukemia in 1994. Plaintiffs allege that the former officer's
illness resulted from, and was aggravated by, his exposure to radiation
at San Onofre, including contact with radioactive fuel particles released
from failed fuel rods. Plaintiffs seek unspecified compensatory and
punitive damages. SCE's November 13, 1995, answer to the complaint denied
all material allegations. All trial court proceedings have been stayed
pending the rulings of the Court of Appeals in the cases described in the
above two paragraphs.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S.
District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering, the manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs 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 in this case is
scheduled to begin on November 24, 1997.
page 33
<PAGE>
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
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 motion was granted, and the appeal
was dismissed.
page 34
<PAGE>
Oil Pipeline Litigation
On November 1, 1996, plaintiff, a crude oil pipeline company, filed a
lawsuit against SCE and the City of Los Angeles (the City) in the United
States District Court for the Central District of California claiming that
SCE and the City had interfered with its attempt to construct a proposed
132-mile oil pipeline (Pacific Pipeline) designed to transport oil from
the San Joaquin Valley and Santa Barbara to the Los Angeles refineries.
Plaintiff alleges, among other things, that SCE and the City wrongfully
initiated administrative and other legal proceedings in an attempt to
derail and obstruct the construction of the Pacific Pipeline. Plaintiff
alleges that these acts constitute unfair competition, tortious
interference with economic advantage and violate state and federal
antitrust laws. Plaintiff further claims that because of the alleged
delays, it could suffer losses in excess of $300 million. Additionally,
plaintiff seeks treble and punitive damages.
On June 30, 1997, SCE filed an answer to the complaint denying the
substantive allegations and raising appropriate defenses.
Environmental Settlement
In July 1997, SCE reached a settlement with the San Bernardino County Fire
Department of alleged violations of environmental laws and regulations in
connection with the 1995 decommissioning of acid and caustic tanks at one
of its sites. The settlement calls for SCE to pay $150,000 in penalties
and $7,832 in costs, for a total payment to the San Bernardino County Fire
Department of $157,832.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
23. Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
May 21, 1997 Item 5. Other Events
Edison International adopted a new program to
repurchase $1.5 Billion worth of outstanding shares
of its common stock.
page 35
<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
August 12, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Edison International Financial Data Schedule - Exhibit 27
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $11,257,508
<OTHER-PROPERTY-AND-INVEST> 7,679,790
<TOTAL-CURRENT-ASSETS> 2,433,181
<TOTAL-DEFERRED-CHARGES> 3,081,903
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 24,452,382
<COMMON> 2,416,578
<CAPITAL-SURPLUS-PAID-IN> 92,097
<RETAINED-EARNINGS> 3,467,360
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,976,035
425,000
183,755
<LONG-TERM-DEBT-NET> 3,203,782
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 4,401,519
<COMMERCIAL-PAPER-OBLIGATIONS> 344,485
<LONG-TERM-DEBT-CURRENT-PORT> 650,231
0
<CAPITAL-LEASE-OBLIGATIONS> 48,448
<LEASES-CURRENT> 20,179
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,198,948
<TOT-CAPITALIZATION-AND-LIAB> 24,452,382
<GROSS-OPERATING-REVENUE> 4,167,908
<INCOME-TAX-EXPENSE> 209,616
<OTHER-OPERATING-EXPENSES> 3,272,413
<TOTAL-OPERATING-EXPENSES> 3,482,029
<OPERATING-INCOME-LOSS> 685,879
<OTHER-INCOME-NET> (31,220)
<INCOME-BEFORE-INTEREST-EXPEN> 654,659
<TOTAL-INTEREST-EXPENSE> 348,294
<NET-INCOME> 306,365
22,531
<EARNINGS-AVAILABLE-FOR-COMM> 283,834
<COMMON-STOCK-DIVIDENDS> 204,224
<TOTAL-INTEREST-ON-BONDS> 181,744
<CASH-FLOW-OPERATIONS> 1,013,324
<EPS-PRIMARY> $0.69
<EPS-DILUTED> $0.68
</TABLE>
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report included in this quarterly report on Form
10-Q for the quarter ended June 30, 1997, of 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
August 12, 1997
