UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1998
------------------------------------------------
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 (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 October 29, 1998
- --------------------------------------- ------------------------------------
Common Stock, no par value 352,708,197
EDISON INTERNATIONAL
INDEX
Page
No
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income -- Three and Nine
Months Ended September 30, 1998, and 1997 1
Consolidated Statements of Comprehensive Income -- Three
and Nine Months Ended September 30, 1998, and 1997 1
Consolidated Balance Sheets -- September 30, 1998,
and December 31, 1997 2
Consolidated Statements of Cash Flows -- Nine Months
Ended September 30, 1998, and 1997 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 12
Part II. Other Information:
Item 1. Legal Proceedings 27
Item 6. Exhibits and Reports on Form 8-K 33
EDISON INTERNATIONAL
PART I -- FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
3 Months Ended 9 Months Ended
September 30, September 30,
- -----------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------
(Unaudited)
Sales to ultimate consumers $2,258,782 $2,349,316 $5,336,067 $5,740,733
Sales to power exchange 687,171 -- 990,856 --
Other 110,710 84,210 274,896 232,161
- -----------------------------------------------------------------------------------------------------------------------
Total electric utility revenue 3,056,663 2,433,526 6,601,819 5,972,894
Diversified operations 384,156 304,255 991,279 932,797
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenue 3,440,819 2,737,781 7,593,098 6,905,691
- -----------------------------------------------------------------------------------------------------------------------
Fuel 101,438 463,069 369,018 857,630
Purchased power -- contracts 908,407 900,781 2,010,269 2,117,116
Purchased power -- power exchange 1,080,910 -- 1,424,694 --
Provisions for regulatory adjustment clauses -- net (447,676) (185,416) (289,314) (277,439)
Other operating expenses 626,763 438,553 1,576,464 1,226,558
Maintenance 104,363 89,883 304,929 302,885
Depreciation, decommissioning and amortization 408,766 342,422 1,224,120 1,024,799
Income taxes 175,816 186,116 411,544 395,732
Property and other taxes 32,460 32,338 106,416 105,329
Loss (gain) on sale of utility plant 89,939 (271) (529,099) (3,105)
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,081,186 2,267,475 6,609,041 5,749,505
- -----------------------------------------------------------------------------------------------------------------------
Operating income 359,633 470,306 984,057 1,156,186
- -----------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan -- (13,218) -- (35,908)
Allowance for equity funds used during construction 3,051 1,691 8,740 5,591
Interest and dividend income 28,202 21,996 83,996 56,987
Minority interest 279 (779) (2,088) (38,468)
Other nonoperating income (deductions) -- net 11,988 (20,419) (6,317) (30,153)
- -----------------------------------------------------------------------------------------------------------------------
Total other income (deductions) -- net 43,520 (10,729) 84,331 (41,951)
- -----------------------------------------------------------------------------------------------------------------------
Income before interest and other expenses 403,153 459,577 1,068,388 1,114,235
- -----------------------------------------------------------------------------------------------------------------------
Interest on long-term debt 165,802 144,139 492,420 448,947
Other interest expense 19,036 34,001 60,568 90,261
Allowance for borrowed funds used during
construction (2,076) (2,036) (5,947) (6,733)
Capitalized interest (4,822) (3,381) (13,187) (11,457)
Dividends on subsidiary preferred securities 8,916 10,063 28,924 32,593
- -----------------------------------------------------------------------------------------------------------------------
Total interest and other expenses -- net 186,856 182,786 562,778 553,611
- -----------------------------------------------------------------------------------------------------------------------
Net income $ 216,297 $ 276,791 $ 505,610 $ 560,624
- -----------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock
outstanding 353,285 394,076 361,417 407,133
Basic earnings per share $.61 $.70 $1.40 $1.38
Diluted earnings per share $.60 $.70 $1.38 $1.37
Dividends declared per common share $.26 $.25 $.78 $ .75
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
3 Months Ended 9 Months Ended
September 30, September 30,
- -----------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $216,297 $276,791 $505,610 $560,624
Cumulative translation adjustments -- net 6,913 (17,058) 7,646 (36,689)
Unrealized gain (loss) on securities -- net (24,665) 8,182 (9,267) 22,630
- -----------------------------------------------------------------------------------------------------------------------
Comprehensive income $198,545 $267,915 $503,989 $546,565
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
September 30, December 31,
1998 1997
- -----------------------------------------------------------------------------------------------------------------------
ASSETS (Unaudited)
Transmission and distribution:
Utility plant, at original cost, subject to
cost-based rate regulation $11,591,649 $11,213,352
Accumulated provision for depreciation (5,841,948) (5,573,742)
Construction work in progress 504,388 492,614
- -----------------------------------------------------------------------------------------------------------------------
6,254,089 6,132,224
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Generation:
Utility plant, at original cost,
not subject to cost-based rate regulation 1,728,929 9,522,127
Accumulated provision for depreciation,
decommissioning and amortization (923,158) (4,970,137)
Construction work in progress 78,181 100,283
Nuclear fuel, at amortized cost 141,569 154,757
- -----------------------------------------------------------------------------------------------------------------------
1,025,521 4,807,030
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Total utility plant 7,279,610 10,939,254
- -----------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision for
depreciation of $278,253 and $238,386 at respective dates 3,075,243 3,178,375
Nuclear decommissioning trusts 2,013,293 1,831,460
Investments in partnerships and
unconsolidated subsidiaries 1,379,371 1,340,853
Investments in leveraged leases 1,569,635 959,646
Other investments 579,090 260,427
- -----------------------------------------------------------------------------------------------------------------------
Total other property and investments 8,616,632 7,570,761
- -----------------------------------------------------------------------------------------------------------------------
Cash and equivalents 1,195,954 1,906,505
Receivables, including unbilled revenue, less allowances of
$21,204 and $26,722 for uncollectible accounts at respective dates 1,407,221 1,077,671
Fuel inventory 50,561 58,059
Materials and supplies, at average cost 121,408 132,980
Accumulated deferred income taxes -- net 271,683 123,146
Regulatory balancing accounts -- net 407,536 193,311
Prepayments and other current assets 207,295 105,811
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Total current assets 3,661,658 3,597,483
- -----------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment -- net 2,387,998 --
Unamortized debt issuance and reacquisition expense 356,018 359,304
Rate phase-in plan -- 3,777
Income tax-related deferred charges 1,454,606 1,543,380
Other deferred charges 1,258,452 1,087,108
- -----------------------------------------------------------------------------------------------------------------------
Total deferred charges 5,457,074 2,993,569
- -----------------------------------------------------------------------------------------------------------------------
Total assets $25,014,974 $25,101,067
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The accompanying notes are an integral part of these financial statements.
2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
September 30, December 31,
1998 1997
- -----------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES (Unaudited)
Common shareholders' equity:
Common stock (352,708,197 and 375,764,429
shares outstanding at respective dates) $2,122,245 $ 2,260,974
Accumulated other comprehensive income:
Cumulative translation adjustments -- net 38,102 30,456
Unrealized gain in equity securities -- net 50,763 60,030
Retained earnings 2,882,897 3,175,883
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5,094,007 5,527,343
- -----------------------------------------------------------------------------------------------------------------------
Preferred securities of subsidiaries:
Not subject to mandatory redemption 128,755 183,755
Subject to mandatory redemption 405,700 425,000
Long-term debt 8,290,435 8,870,781
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Total capitalization 13,918,897 15,006,879
- -----------------------------------------------------------------------------------------------------------------------
Other long-term liabilities 515,930 479,637
- -----------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt 912,322 868,026
Short-term debt 305,599 329,550
Accounts payable 685,863 441,049
Accrued taxes 861,755 576,841
Accrued interest 109,951 131,885
Dividends payable 91,943 95,146
Deferred unbilled revenue and other current liabilities 1,516,769 1,285,679
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,484,202 3,728,176
- -----------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes -- net 4,352,343 4,085,296
Accumulated deferred investment tax credits 327,698 350,685
Customer advances and other deferred credits 1,400,879 1,441,303
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits 6,080,920 5,877,284
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Minority interest 15,025 9,091
- -----------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $25,014,974 $25,101,067
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
3
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
9 Months Ended
September 30,
- ------------------------------------------------------------------------------------------------------------------------
1998 1997
- ------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 505,610 $ 560,624
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 1,224,120 1,024,799
Other amortization 123,953 60,582
Rate phase-in plan 3,777 34,483
Deferred income taxes and investment tax credits 170,246 4,499
Equity in income from partnerships and unconsolidated
subsidiaries (160,710) (164,170)
Other long-term liabilities 36,293 80,809
Regulatory asset related to the sale of utility plant (219,301) --
Net gains on sale of oil and gas plant (551,984) --
Other -- net (214,286) (83,113)
Changes in working capital:
Receivables (351,185) (283,344)
Regulatory balancing accounts (214,225) (282,423)
Fuel inventory, materials and supplies 19,070 20,957
Prepayments and other current assets (91,469) (45,063)
Accrued interest and taxes 262,980 277,924
Accounts payable and other current liabilities 533,401 218,830
Distributions from partnerships and unconsolidated subsidiaries 117,108 126,411
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,193,398 1,551,805
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 944,916 1,474,873
Long-term debt repaid (1,287,354) (2,011,200)
Common stock repurchased (653,740) (884,686)
Preferred securities redeemed (74,300) (100,000)
Rate reduction notes repaid (161,070) --
Nuclear fuel financing -- net (11,478) (12,628)
Short-term debt financing -- net (23,951) 1,046,208
Dividends paid (281,870) (310,354)
Other -- net 367 4,708
- ------------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (1,548,480) (793,079)
- ------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (622,625) (514,396)
Proceeds from sale of plant 1,200,213 151,267
Funding of nuclear decommissioning trusts (118,196) (109,202)
Investments in partnerships and unconsolidated subsidiaries (85,007) (219,819)
Unrealized gain (loss) on securities -- net (9,267) 22,630
Investment in subsidiaries (258,000) --
Investments in leveraged leases (458,509) (326,950)
Other -- net (4,078) (73,830)
- ------------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (355,469) (1,070,300)
- ------------------------------------------------------------------------------------------------------------------------
Net decrease in cash and equivalents (710,551) (311,574)
Cash and equivalents, beginning of period 1,906,505 896,594
- ------------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $1,195,954 $ 585,020
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
4
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 1997 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 1997 Annual Report.
As a result of industry restructuring legislation enacted by the State of
California and a related change in the application of accounting principles for
rate-regulated enterprises adopted by the Financial Accounting Standards Board's
Emerging Issues Task Force, during the third quarter of 1997, Southern
California Edison Company (SCE) began accounting for its investments in
generation facilities in accordance with accounting principles applicable to
enterprises in general, and Edison International's balance sheets display a
separate caption for its investments in generation. Application of such
accounting principles to SCE's generation assets did not result in any
adjustment of their carrying value; however, SCE's nuclear investments were
reclassified as a regulatory asset in second quarter 1998.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to be recognized on the balance sheet at fair
value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings. Edison
International is studying the impact of the new standard on its nonutility
subsidiaries, and is unable to predict at this time the impact on its financial
statements.
Certain prior-period amounts were reclassified to conform to the September 30,
1998, financial statement presentation.
Note 1. Regulatory Matters
California Electric Utility Industry Restructuring
Restructuring Decision -- The California Public Utilities Commission's (CPUC)
December 1995 decision on restructuring California's electric utility industry
started the transition to a new market structure; competition and customer
choice began on April 1, 1998. Key elements of the CPUC's restructuring decision
included: creation of the power exchange (PX) and independent system operator
(ISO); availability of customer choice for electricity supply and certain
billing and metering services; 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 the competition
transition charge (CTC).
Restructuring Statute -- In September 1996, the State of California enacted
legislation to provide a transition to a competitive market structure. The
Statute substantially adopted 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
are being recovered through the terms of their contracts while most of the
remaining transition costs will be recovered through 2001. The Statute also
5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
included provisions to finance a portion of the stranded costs that residential
and small commercial customers would have paid between 1998 and 2001, which
allowed SCE to reduce rates by at least 10% to these customers, effective
January 1, 1998. The Statute included a rate freeze for all other customers,
including large commercial and industrial customers, as well as provisions for
continued funding for energy conservation, low-income programs and renewable
resources. Despite the rate freeze, SCE expects to be able to recover its
revenue requirement during the 1998-2001 transition period. In addition, the
Statute mandated the implementation of the CTC that provides utilities the
opportunity to recover costs made uneconomic by electric utility restructuring.
Finally, the Statute contained provisions for the recovery (through 2006) of
reasonable employee-related transition costs, incurred and projected, for
retraining, severance, early retirement, outplacement and related expenses. A
voter initiative, known as California Proposition 9, seeks to overturn major
portions of the Statute. A more detailed discussion of Proposition 9 is in Note
2 to the Consolidated Financial Statements.
Rate Reduction Notes -- In December 1997, after receiving approval from both the
CPUC and the California Infrastructure and Economic Development Bank, a limited
liability company created by SCE issued approximately $2.5 billion of rate
reduction notes. Residential and small commercial customers, whose 10% rate
reduction began January 1, 1998, are repaying the notes over the expected
10-year term through non-bypassable charges based on electricity consumption.
Proposition 9 seeks to prohibit the collection of these non-bypassable charges,
or if the charges are found enforceable by a court, require SCE to offset such
charges with an equal credit to customers. See Note 2 to the Consolidated
Financial Statements.
Rate-setting -- In August 1997, the CPUC issued a decision which adopted a
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 (see "PBR" discussion below) 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 reallocated amount through
market revenue, other rate-making mechanisms or operation and maintenance
contracts with the new owners of the divested generation plants. Beginning
January 1, 1998, SCE's rates were unbundled into separate charges for energy,
transmission, distribution, the CTC, public benefit programs and nuclear
decommissioning. The transmission component is being collected through Federal
Energy Regulatory Commission (FERC)-approved rates, subject to refund.
PX and ISO -- On March 31, 1998, both the PX and ISO began accepting bids and
schedules for April 1, 1998, when the ISO took over operational control of the
transmission system. The hardware and software systems being utilized by the PX
and ISO in their bidding and scheduling activities were financed through loans
of $300 million (backed by utility guarantees) obtained by restructuring trusts
established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans
through charges for service to future PX and ISO customers. The restructuring
implementation costs related to the start-up and development of the PX, which
are paid by the utilities, will be recovered from all retail customers over the
four-year transition period. SCE's share of the charge is $45 million, plus
interest and fees. SCE's share of the ISO's start-up and development costs
(approximately $16 million per year) will be paid over a 10-year period.
Direct Customer Access -- Effective April 1, 1998, customers are now able to
choose to remain utility customers with either bundled electric service or an
hourly PX pricing option from SCE (which is purchasing its power through the
PX), or choose direct access, which means the customer can contract directly
with either independent power producers or energy service providers (ESPs) such
as power brokers, marketers and aggregators. Additionally, all
investor-owned-utility customers are paying the CTC whether or not they choose
to buy power through SCE. Electric utilities are continuing to provide the core
distribution service of delivering energy through their distribution system
regardless of a customer's choice of electricity supplier. The CPUC is
continuing to regulate the prices and service obligations related to
distribution services.
6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Cycle Services -- Effective April 1, 1998, customers have options
regarding metering, billing and related services (referred to as revenue cycle
services) that have been provided by California's investor-owned utilities. Now
ESPs can provide their customers with one consolidated bill for their services
and the utility's services, request the utility to provide a consolidated bill
to the customer or elect to have both the ESP and the utility bill the customer
for their respective charges. In addition, customers with maximum demand above
20 kW (primarily industrial and medium 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 September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they elect
to obtain revenue cycle services from someone other than SCE. Although the
decision adopted SCE's recommendation of using the net avoided cost, it also
adopted a methodology which results in higher credits to customers but requires
ESPs to pay service fees to SCE for the costs that SCE incurs as a result of
dealing with the ESP.
PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D)
PBR mechanism for SCE which began on January 1, 1997. Beginning in April 1998,
the transmission portion was separated from PBR and subject to ratemaking under
the rules of the FERC. The distribution-only PBR will extend through December
2001. Key elements of 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.
The CPUC is considering unbundling SCE's cost of capital based on major utility
function. In May 1998, SCE filed an application on this issue. A CPUC decision
is expected in early 1999.
Beginning in 1998, SCE's hydroelectric plants are operating under a PBR-type
mechanism. The mechanism sets the hydroelectric revenue requirement and
establishes a formula for extending it through the duration of the electric
industry restructuring transition period, or until market valuation of the
hydroelectric facilities, whichever occurs first. The mechanism provides that
power sales revenue from hydroelectric facilities in excess of the hydroelectric
revenue requirement be credited against the costs to transition to a competitive
market (see "CTC" discussion below).
Divestiture -- In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all 12 of its gas- and oil-fueled generation
plants. Under this proposal, SCE would continue to operate and maintain the
divested power plants for at least two years following their sale, as mandated
by the restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be impacted
by divestiture-related job reductions. In September 1997, the CPUC approved
SCE's proposal to auction the 12 plants.
SCE has sold and transferred ownership of all 12 of its gas- and oil-fueled
generation plants. The total sales price of the 12 plants was $1.2 billion, over
$500 million more than the combined book value. Net proceeds of the sales were
used to reduce stranded costs, which otherwise were expected to be collected
through the CTC mechanism.
CTC -- The costs to transition to a competitive market are being recovered
through a non-bypassable CTC. This charge applies to all customers who were
using or began using utility services on or after the CPUC's December 20, 1995,
decision date. The CTC is being determined residually by subtracting other rate
components for the PX, T&D, nuclear decommissioning and public benefit programs
from the frozen rate levels. SCE currently estimates its transition costs to be
approximately $10.6 billion (1998 net present value) from 1998 through 2030.
This estimate is 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 $6.4
billion from SCE's qualifying
7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
facilities contracts, which are the direct result of prior legislative and
regulatory mandates, and $4.2 billion from costs pertaining to certain
generating assets (successful completion of the sale of SCE's oil- and
gas-fueled generation plants has reduced this estimate of transition costs for
SCE-owned generation) 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 (San Onofre) Units 2 and 3 and
the Palo Verde Nuclear Generating Station (Palo Verde) units and certain other
costs. This issue was separated into two phases; Phase 1 addressed the
rate-making issues and Phase 2 the quantification issues.
Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the
establishment of a transition cost balancing account and annual transition cost
proceedings; the setting of a market rate forecast for 1998 transition costs;
the requirement that generation-related regulatory assets be amortized ratably
over a 48-month period; the establishment of calculation methodologies and
procedures for SCE to collect its transition costs from 1998 through the end of
the rate freeze; and the reduction of SCE's authorized rate of return on certain
assets eligible for transition cost recovery (primarily fossil- and
hydroelectric-generation related assets) beginning July 1997, five months
earlier than anticipated. SCE has filed an application for rehearing on the 1997
rate of return issue.
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described 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). During the third quarter of 1997, SCE discontinued
application of accounting principles for rate-regulated enterprises for its
investment in generation facilities based on new accounting guidance. The
financial reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the new guidance did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
new guidance did not specifically address the application of asset impairment
standards to these assets. SCE has retained 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. The
regulatory assets relate primarily to the recovery of accelerated income tax
benefits previously flowed through to customers, purchased power contract
termination payments and unamortized losses on reacquired debt. The new
accounting guidance also permits the recording of new generation-related
regulatory assets during the transition period that are probable of recovery
through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed relating to
the application of asset impairment standards to these assets. Using this
guidance has resulted in SCE reducing its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recording a regulatory asset on its
balance sheet for the same amount. For this impairment assessment, the fair
value of the investment was calculated by discounting future net cash flows.
This reclassification had no effect on SCE's results of operations.
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 (approximately $2.5
billion, after tax, at September 30, 1998) as a one-time, non-cash charge
against earnings.
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.
8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Contingencies
In addition to the matters disclosed in these notes, Edison International is
involved in other 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 other proceedings
will not materially affect its results of operations or liquidity.
California Voter Initiative
On November 3, 1998, California voters will vote on Proposition 9, an initiative
supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric industry
restructuring legislation. Proposition 9 purports to: (1) require SCE and the
other California investor-owned utilities to provide at least a 20% rate
reduction to their residential and small commercial customers to be achieved
through cutting payments for nuclear and other fossil generation transition
costs; (2) eliminate cost recovery for nuclear generation plants and related
assets and obligations (other than reasonable decommissioning costs), except to
the extent such costs are recovered from competitive market sales through the PX
or contracts with the ISO; (3) eliminate cost recovery for non-nuclear
generation plants and related assets and obligations (other than costs
associated with QFs), except to the extent such costs are recovered from
competitive market sales through the PX or contracts with the ISO, unless the
CPUC finds that the utilities would be deprived of the opportunity to earn a
fair rate of return; and (4) prohibit the collection of any customer charges
necessary to pay principal, interest and other costs on the rate reduction bonds
(Fixed Transition Amounts or FTAs) or, if a court finds that the CPUC orders
authorizing the collection of FTAs are nevertheless enforceable, require the
FTAs to be offset with a concurrent equal credit. Proposition 9's purported rate
reduction would be in lieu of the 10% rate reduction for residential and small
commercial customers that went into effect on January 1, 1998.
If Proposition 9 is approved and implemented, and if SCE were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid, then
under applicable accounting principles SCE would be required to write off
generation-related regulatory assets and certain investments in electric
generation plant to the extent SCE were to conclude that such assets were no
longer probable of recovery due to reductions in future revenue. SCE anticipates
that such a one-time write-off would amount to as much as $3.4 billion pre-tax.
This pre-tax write-off would result in an after-tax write-off of as much as $1.9
billion, or approximately $5 per share, representing 50% of SCE's total
shareholders' equity of $3.8 billion at September 30, 1998.
Such an after-tax write-off, which would exceed SCE's current retained earnings
($820 million as of September 30, 1998), would severely impair SCE's ability to
pay dividends to its preferred shareholders and Edison International's ability
to pay dividends to its common shareholders. The potential earnings reductions
described below also would impair the payment of dividends. In addition, an
after-tax write-off of $1.9 billion would reduce the common equity ratio of
SCE's capital structure from approximately 49% to approximately 30%.
The duration and amount of the rate decrease contemplated by Proposition 9 is
uncertain and, if Proposition 9 is approved, will be subject to interpretation
by the courts and regulatory agencies. If all provisions of Proposition 9
ultimately are upheld against legal challenge and interpreted in an adverse
manner, the amount of the average earnings reductions to SCE could be as much as
$210 million per year from 1999 through 2001, and gradually decreasing to as
much as $10 million in 2007.
The earnings reduction and write-off estimates ultimately will depend on how the
courts and regulators interpret Proposition 9 and how future rate changes
unrelated to Proposition 9 affect SCE's electric revenue.
9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The financial impacts described above, either singly or in combination, would
likely cause the rating agencies that rate SCE's debt and preferred securities
to lower those ratings substantially, which would immediately reduce the market
value of SCE's $4.2 billion in outstanding debt and preferred securities,
increase the cost of raising new capital, and possibly preclude the use of
certain financial instruments for raising capital.
If the voters approve Proposition 9, then legal challenges by the California
utilities, including SCE, and others will ensue. SCE intends to vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions pending court review of the merits of its challenge. Although SCE
believes the litigation arguments challenging the enforceability of Proposition
9 would be compelling, no assurances can be given whether or when Proposition 9
would be overturned.
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).
Edison International's recorded estimated minimum liability to remediate its 50
identified sites is $177 million. 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 $247
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. SCE has sold all of its gas- and oil-fueled generation plants and has
retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $90 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 $145 million for its estimated minimum
environmental-cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is
a lack of currently available information, including the nature and magnitude of
contamination and the extent, if any, that Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can now be made for these sites.
10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $4 million to $10 million.
Based on currently available information, Edison International believes it is
unlikely that it will incur amounts in excess of the upper limit of the
estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs ultimately
recorded will not materially affect its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of
new sites, will not require material revisions to such estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.9
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 United States 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 $88 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 $175
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 $25 million per year. Insurance premiums are charged to operating expense.
11
EDISON INTERNATIONAL
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
Results of Operations
Earnings
Edison International's basic earnings per share for the three and nine months
ended September 30, 1998, were 61(cent) and $1.40, respectively, compared with
70(cent) and $1.38 for the same periods in 1997. Southern California Edison
Company's (SCE) earnings for the three and nine months ended September 30, 1998,
were 46(cent) and $1.04, respectively, down 11(cent) and 9(cent) from the
year-earlier periods, primarily due to reduced authorized returns on generating
assets and a lower earning asset base. The lower earning asset base is mainly
the result of the accelerated recovery of investments and divestiture of gas-
and oil-fueled generation assets. Edison Mission Energy (EME) and Edison Capital
had combined earnings for the three and nine months ended September 30, 1998, of
21(cent) and 48(cent), respectively, up 6(cent) and 17(cent) from the
year-earlier periods. The increases were primarily due to earnings generated by
Edison Capital's investments in affordable housing and cross-border lease
transactions in the Netherlands, South Australia and South Africa. Edison
Enterprises and the parent company were responsible for the following negative
income effects: 6(cent) per share for third quarter 1998 and 12(cent) for the
nine months ended September 30, 1998, compared to 2(cent) and 6(cent) for the
same periods in 1997, primarily due to continued start-up costs at Edison
Enterprises (Edison International's retail businesses: Edison Source, Edison
Select and Edison Utility Services).
Operating Revenue
Since April 1, 1998, SCE is required to sell all of its generated power to the
power exchange (PX). For more details, see "Competitive Environment." Excluding
the sales to the PX, electric utility revenue decreased 3% and 6%, respectively,
for the three and nine months ended September 30, 1998, compared to the
year-earlier periods. The decreases reflect lower average residential rates
(mandated by legislation enacted in September 1996). The quarterly decrease was
partially offset by a 5% increase in retail sales volume due to the unusually
warm weather in third quarter 1998. Over 99% of electric utility revenue
(excluding sales to the PX) 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).
Legislation enacted in September 1996 provided for, among other things, at least
a 10% rate reduction (financed through the issuance of rate reduction notes) for
residential and small commercial customers in 1998 and other rates to remain
frozen at June 1996 levels (system average of 10.1(cent) per kilowatt-hour). See
discussion in "Competitive Environment."
Revenue from diversified operations increased 26% and 6%, respectively, for the
three and nine months ended September 30, 1998, compared to the same periods in
1997. The increases were primarily due to increased revenue at Edison Capital,
related to its cross-border lease transactions and increased revenue at Edison
Source.
Operating Expenses
Fuel expense decreased 78% and 57%, respectively, for the three and nine months
ended September 30, 1998, compared to the same periods in 1997. The decreases
resulted from the sale of SCE's gas- and oil-fueled generation plants. The
year-to-date decrease also reflects significantly lower gas prices at SCE in the
first quarter of 1998.
Since April 1, 1998, SCE is required to purchase all of its power from the PX
for distribution to its retail customers. SCE is continuing to purchase power
from certain nonutility generators (known as qualifying facilities) and under
existing inter-utility contracts. This purchased power is sold to the PX. SCE is
required under federal law to purchase power from certain qualifying facilities
even though energy prices
12
under these contracts are generally higher than other sources. For the twelve
months ended September 30, 1998, SCE paid about $1.5 billion (including energy
and capacity payments) more for these power purchases than the cost of power
available from other sources. The CPUC has mandated the prices for these
contracts.
Provisions for regulatory adjustment clauses decreased for the quarter and nine
months ended September 30, 1998, compared to the same periods in 1997. The
quarterly decrease is primarily due to undercollections in the transition cost
balancing account resulting from high qualifying facilities energy costs. The
year-to-date decrease was mainly due to undercollections related to the issuance
of the rate reduction notes in December 1997. These undercollections were
partially offset by overcollections related to the gain on sales of the gas- and
oil-fueled generation plants in second quarter 1998 and other transition costs.
The year-to-date decrease in the provision was also offset by overcollections
related to the administration of public-purpose funds.
Other operating expenses increased for the three and nine months ended September
30, 1998, compared to the same periods in 1997, primarily due to must-run
reliability services, direct access activities, and PX and independent system
operator (ISO) activities at SCE, as well as higher expenses at Edison Source.
The year-to-date increase also reflects storm damage expense at SCE resulting
from a harsher winter in 1998.
Maintenance expense increased 16% for the quarter ended September 30, 1998,
compared to the year-earlier period, mainly due to additional expenses incurred
at SCE's distribution facilities.
Depreciation, decommissioning and amortization expense increased 19% for both
the quarter and nine months ended September 30, 1998, compared to the same
periods in 1997. The increases are primarily due to the further acceleration of
San Onofre Nuclear Generating Station Units 2 and 3 and the Palo Verde Nuclear
Generating Station units and the amortization of the loss on plant sales. The
year-to-date increase also reflects accelerated recovery of the gas- and
oil-fueled generation plants. The amortization of the loss on plant sales, as
well as the accelerated recoveries implemented in 1998 are part of the
competition transition charge (CTC) mechanism (see further discussion under
"California Electric Utility Industry Restructuring").
Income taxes decreased 6% for the three months ended September 30, 1998,
compared to the same period in 1997, primarily due to lower pre-tax income at
SCE, partially offset by additional amortization at SCE related to the CTC
mechanism and higher pre-tax income and a lower United Kingdom deferred tax
adjustment at EME. Also, this additional amortization related to the CTC
mechanism will continue to cause an increase in the effective tax rate.
Loss (gain) on sale of utility plant resulted from the sale of SCE's 12 gas- and
oil-fueled generation plants in 1998. Gain on sales of SCE's gas- and oil-fueled
plants was used to reduce stranded costs. Loss on sales will be recovered from
customers over the transition period.
Other Income and Deductions
The provision for rate phase-in plan reflected 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) was collected evenly over the final six years of each unit's plan. The
plan ended in February 1996, September 1996 and January 1998 for Units 1, 2 and
3, respectively. The provision was a non-cash offset to the collection of
deferred revenue.
Interest and dividend income increased 28% and 47%, respectively, for the three
and nine months ended September 30, 1998, compared to the year-earlier periods.
The increases reflect higher investment balances due to the sale of SCE's gas-
and oil-fueled generation plants, as well as increases in interest earned on
higher balancing account undercollections.
Minority interest decreased for the nine months ended September 30, 1998,
compared to the same period last year, due to EME's May 1997 acquisition of the
remaining 49% ownership interest in the Loy Yang B project.
13
Other nonoperating income increased for the three and nine months ended
September 30, 1998, compared to the year-earlier periods, mostly due to
additional accruals in 1997 at SCE for regulatory matters.
Interest and Other Expenses
Interest on long-term debt increased 15% and 10%, respectively, for the three
and nine months ended September 30, 1998, compared to the year-earlier periods,
mainly due to an increase at SCE related to the issuance of rate reduction notes
in December 1997. The year-to-date increase was partially offset by lower
expenses at EME due to lower principal balances on outstanding debt. Interest on
the rate reduction notes was $37 million and $113 million, respectively, for the
three and nine months ended September 30, 1998.
Other interest expense decreased 44% and 33%, respectively, for the three and
nine months ended September 30, 1998, compared to the same periods in 1997. The
decreases are due to lower overall short-term debt balances in 1998,
particularly short-term debt at SCE used to finance fuel inventories. These fuel
inventories are no longer needed because of the divestiture of the gas- and
oil-fueled plants.
Financial Condition
Edison International's liquidity is primarily affected by debt maturities,
dividend payments and 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
$2.8 billion (increased from $2.3 billion in July 1998) of its outstanding
shares of common stock. Edison International has repurchased 95.5 million shares
($2.2 billion) between January 1995 and October 30, 1998, funded by dividends
from its subsidiaries and the issuance of rate reduction notes.
Edison International's cash flow coverage of dividends for the nine months ended
September 30, 1998, was 4.2 times, compared to 5.0 times for the same period in
1997. The decrease was primarily due to the ongoing share repurchase program, as
well as the gain on sale of SCE's 12 gas- and oil-fueled generation plants.
Edison International's dividend payout ratio for the twelve-month period ended
September 30, 1998, was 58%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.2 billion for the
nine-month period ended September 30, 1998, compared with $1.6 billion in 1997.
Cash from operations exceeded capital requirements for both periods presented.
Cash Flows from Financing Activities
At September 30, 1998, Edison International and its subsidiaries had $2.3
billion of borrowing capacity available under lines of credit totaling $2.6
billion. SCE had available lines of credit of $1.3 billion, with $735 million
for general purpose short-term debt and $515 million for the long-term
refinancing of its variable-rate pollution-control bonds. The parent company had
total lines of credit of $500 million, with $300 million available. The
nonutility companies had total lines of credit of $800 million, with $710
million available to finance general cash requirements. Edison International's
unsecured lines of credit are at negotiated or bank index rates with various
expiration dates.
SCE's short-term debt is used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital expenditures.
SCE's external financings are influenced by market conditions and other factors,
including limitations imposed by its articles of incorporation and trust
indenture. As of September 30, 1998, SCE could issue approximately $12.0 billion
of additional first and refunding mortgage bonds and $4.5 billion of preferred
stock at current interest and dividend rates.
14
EME has firm commitments of $265 million to make equity and other contributions,
primarily for the ISAB project in Italy, the Paiton project in Indonesia, the
Tri Energy project in Thailand, and the Doga project in Turkey. EME also has
contingent obligations to make additional contributions of $199 million,
primarily for 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 and funds available from EME's
revolving line of credit.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure,
limiting the dividends it may pay Edison International. At September 30, 1998,
SCE had the capacity to pay $800 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.
In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE
is the sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. The proceeds of the rate reduction notes were used by
the SPE to purchase from SCE an enforceable right known as transition property.
Transition property is a current property right created pursuant to the
restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a non-bypassable
tariff levied on residential and small commercial customers. Notwithstanding the
legal sale of the transition property by SCE to the SPE, the amounts reflected
as assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to the SPE, and the liabilities of the SPE for the rate
reduction notes are for accounting purposes reflected as long-term liabilities
on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities.
The rate reduction notes have maturities ranging from one to 10 years, and bear
interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are
secured solely by the transition property and certain other assets of the SPE,
and there is no recourse to SCE or Edison International.
Although the SPE is consolidated with SCE in the financial statements, as
required by generally accepted accounting principles, the SPE is legally
separate from SCE, the assets of the SPE are not available to creditors of SCE
or Edison International, and the transition property is legally not an asset of
SCE or Edison International.
A voter initiative, known as California Proposition 9 on the November 1998
ballot, proposes to, among other things, prohibit the collection of any charges
in connection with the financing order for the purpose of making payments on
rate reduction notes. If Proposition 9 is voted into law and is not immediately
overturned or is not stayed pending judicial review of its merits, the
collection of charges necessary to pay the certificates while the litigation is
pending could be precluded, which would adversely affect the certificates and
the secondary market for the certificates, including pricing, liquidity, dates
of maturity, and weighted-average lives of the certificates. In addition, if
Proposition 9 is voted into law and upheld by the courts, it could have a
further material adverse effect on the certificates and the holders of the
certificates could incur a loss on their investment. A more detailed discussion
is in "California Voter Initiative."
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, the nonutilities' investments in partnerships and unconsolidated
subsidiaries, proceeds from the sale of plant (see discussion in "Competitive
Environment -- Divestiture"), and funding of nuclear decommissioning trusts.
Decommissioning costs are accrued and recovered in rates over the term of each
nuclear generating
15
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 ($2.2 billion), escalated using a 6.65%
annual rate. These costs are expected to be funded from independent
decommissioning trusts, which will receive SCE contributions of approximately
$100 million per year. Any plan to decommission San Onofre Unit 1 prior to 2013
is not expected to affect SCE's annual contributions to the decommissioning
trusts.
Cash used for the nonutility subsidiaries' investing activities was $606 million
for the nine-month period ended September 30, 1998, compared to $519 million for
the same period in 1997. The increase is primarily due to Edison Capital's
investment in leveraged leases.
Market Risk Exposures
Edison International's primary market risk exposures arise from fluctuations in
energy prices, interest rates and foreign exchange rates. Edison International's
risk management policy allows the use of derivative financial instruments to
manage its financial exposures, but prohibits the use of these instruments for
speculative or trading purposes.
As a result of the rate freeze established in the restructuring statute, SCE's
transition costs are recovered as the residual component of rates once the costs
for distribution, transmission, public purpose programs, nuclear decommissioning
and the cost of supplying power to its customers through the PX and ISO have
already been recovered. Accordingly, more revenue will be available to cover
transition costs when market prices in the PX and ISO are low than when PX and
ISO prices are high. Market prices in the PX and ISO to date have generally been
reasonable, though some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap of $250/MW on the market for such
services until certain actions have been completed to improve the functioning of
those markets. Similarly, the ISO currently maintains a cap of $250/MWh on its
market for imbalance energy while a software problem affecting the efficient
operation of that market persists. The caps in these markets mitigate the risk
of costly price spikes that would reduce the revenue available to SCE to pay
transition costs. During the upcoming year, the ISO will be considering removing
these price caps, which could increase the risk of high market prices. SCE's
exposure to high electricity prices is also partially mitigated by hedges
against high natural gas prices, since increases in natural gas prices tend to
raise the price of electricity purchased from the PX.
Changes in interest rates, electricity pool pricing and fluctuations in foreign
currency exchange rates can have a significant impact on EME's results of
operations. EME has 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 includes $16 million in
the nine months ended September 30, 1998, compared to $14 million for the same
period in 1997. The maturity dates of several of EME's interest rate swap and
collar 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 electric energy and capacity through a
centralized electricity pool, which establishes a half-hourly clearing price or
pool price for electric 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
purchasing price of power, where 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
pool price for the element of power under contract. These contracts can be sold
in two structures: one-way contracts, where a specified monthly amount is
received in advance and difference payments are made when the pool price is
above the price specified in the contract, and two-way contracts, where the
counterparty pays First Hydro when the pool price is below the contract priced
instead of a specified monthly amount. These contracts act as a means of
stabilizing production
16
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 $36
million for the nine months ended September 30, 1998, compared to an increase of
$27 million for the same period in 1997, as a result of electricity rate swap
agreements. A proposal to replace the current structure of the forward-contracts
market and the pool has been made by the Director General of Electricity Supply,
at the request of the Minister of Science, Energy and Industry in the United
Kingdom. The Minister has recommended that the proposal be implemented by April
2000. Further definition of the proposal will be required before the effects of
the changes can be evaluated. Implementation of the proposal may also require
legislation.
Loy Yang B sells its electric energy through a centralized electricity pool,
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
described below. Vesting contracts were put into place by the State Government
of Victoria (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. These contracts
are accounted for as electricity rate swap agreements. 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 increased by $52 million for the nine months ended
September 30, 1998, compared to an increase of $43 million for the same period
in 1997, as a result of hedging contract arrangements.
As EME continues to expand into foreign markets, fluctuations in foreign
currency exchange rates can affect the amount of its equity contributions to,
distributions from and results of operations of its foreign projects. At times,
EME has hedged a portion of its current exposure to fluctuations in foreign
exchange rates where it deems appropriate through financial derivatives,
offsetting obligations denominated in foreign currencies, and indexing
underlying project agreements to U.S. dollars or other indices reasonably
expected to correlate with foreign exchange movements. 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 macroeconomic variables will behave in a manner that is
consistent with historical or forecasted relationships.
Construction on the two-unit Paiton project is approximately 97% complete, and
commercial operation is expected in the first half of 1999. The tariff is higher
in the early years and steps down over time, and the tariff for the Paiton
project includes infrastructure to be used in common by other units at the
Paiton complex. The plant's output is fully contracted with the state-owned
electricity company for payment in U.S. dollars and supported by the Indonesian
government. The projected rate of growth of the Indonesian economy and the
exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated
significantly since the Paiton project was contracted, approved and financed.
The project received substantial finance and insurance support from the
Export-Import Bank of the United States, The Export-Import Bank of Japan, the
U.S. Overseas Private Investment Corporation and the Ministry of International
Trade and Industry of Japan. The Paiton project's senior debt ratings have been
reduced from investment grade to speculative grade based on the rating agencies'
perceived increased risk that the state-owned electricity company might not be
able to honor the electricity sales contract with Paiton. The Indonesian
government has arranged to reschedule sovereign debt owed to foreign governments
and has entered into discussions about rescheduling sovereign debt owed to
private lenders. A presidential decree has deemed some independent power
projects, but not including the Paiton project, subject to review, postponement
or cancellation. The Indonesian government has announced that it will propose a
policy related to independent power projects, which is expected in fourth
quarter 1998. The
17
Paiton project continues to discuss the situation in Indonesia with the
state-owned electricity company, the Indonesian government and its officials and
commercial lenders. EME continues to monitor the situation closely.
Projected Capital Requirements
Edison International's projected construction expenditures for the next five
years are: 1998 -- $861 million; 1999 -- $815 million; 2000 -- $674 million;
2001 -- $680 million; and 2002 -- $655 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1998, are: 1999 -- $889 million;
2000 -- $956 million; 2001 -- $857 million; 2002 -- $444 million; and 2003 --
$703 million.
Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1998, are: 1999 through 2001 -- zero; 2002 -- $105
million; and 2003 -- $9 million.
Generating Station Acquisition
On August 2, 1998, EME entered into agreements to acquire the 1,884-MW Homer
City Generating Station for approximately $1.8 billion. Homer City, jointly
owned by subsidiaries of GPU, Inc. and New York State Electric & Gas
Corporation, is the only major regional coal-fired facility with direct high
voltage interconnection to the New York Power Pool and the Pennsylvania-New
Jersey-Maryland Power Pool. The plant is located near Pittsburgh, Pennsylvania.
EME will operate the plant, which is one of the lowest-cost generation
facilities in the region. The sale is subject to approval by the Pennsylvania
Public Utility Commission, the New York State Public Service Commission and
other regulatory agencies, and is expected to be completed by the first quarter
of 1999. EME plans to finance this acquisition with a combination of debt
secured by the project, EME corporate debt and cash. The acquisition is expected
to have no effect on 1999 earnings and a positive effect on earnings in 2000 and
beyond.
Regulatory Matters
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction for residential and small commercial customers in 1998 and other
rates to remain frozen at June 1996 levels (system average of 10.1(cent) per
kilowatt-hour). See further discussion in "Competitive Environment
- --Restructuring Statute."
In 1998, revenue is determined by various mechanisms depending on the utility
operation. Revenue related to distribution operations is determined through a
performance-based rate-making mechanism (PBR) (see discussion in "Competitive
Environment -- PBR") and the distribution assets have the opportunity to earn a
CPUC-authorized 9.49% return. Until the ISO began operation, transmission
revenue was determined by the same mechanism as distribution operations. After
March 31, 1998, transmission revenue is determined through FERC-authorized rates
and transmission assets earn a 9.43% return. These rates are subject to refund.
See discussion in "Competitive Environment -- Rate-setting."
Revenue from generation-related operations is determined through the CTC
mechanism, nuclear rate-making agreements and the competitive market. Revenue
related to fossil and hydroelectric generation operations is recovered from two
sources. The portion that is made uneconomic by electric industry restructuring
is recovered through the CTC mechanism. The portion that is economic is
recovered through the market. In 1998, fossil and hydroelectric generation
assets earn a 7.22% return. A more detailed discussion is in "Competitive
Environment -- CTC."
The CPUC has authorized revised rate-making plans for SCE's nuclear facilities,
which call for the accelerated recovery of its nuclear investments in exchange
for a lower authorized rate of return. SCE's nuclear assets are earning an
annual rate of return of 7.35%. In addition, the San Onofre plan authorizes a
fixed rate of approximately 4(cent) per kilowatt-hour generated for 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
18
the incentive pricing portion. Palo Verde's 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. Beginning January 1, 1998, both the San
Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
The changes in revenue from the regulatory mechanisms discussed above, excluding
the effects of other rate actions, are expected to have a minimal impact on 1998
earnings. However, the issuance of the rate reduction notes in December 1997,
which enabled the repurchase of debt and equity, will have a negative impact on
1998 earnings of approximately $97 million. The impact on earnings per share is
mitigated by the repurchase of common stock from the rate reduction note
proceeds.
Prior to the restructuring of the electric utility industry, SCE recovered its
non-nuclear capital additions to utility plant through depreciation rates
authorized in the general rate case. As part of the CTC Phase 2 decision, the
CPUC authorized recovery of the December 31, 1995, balances of non-nuclear
generating facilities through the CTC mechanism. The CPUC stated that rate
recovery for capital additions to the non-nuclear generating facilities should
be sought through a separate filing. In October 1997, SCE filed an application
with the CPUC requesting rate recovery of $61 million of 1996 capital additions
to its non-nuclear generating facilities. Hearings were held in early 1998. The
CPUC's Office of Ratepayer Advocates and The Utility Reform Network recommended
a combined total disallowance of $37 million. On September 21, 1998, a CPUC
administrative law judge proposed a $4 million disallowance. A final CPUC
decision is expected in fourth quarter 1998. In fourth quarter 1998, SCE plans
to file an application for rate recovery of capital additions to these same
generating facilities for the period January 1, 1997, through March 31, 1998, or
the date of divestiture for divested facilities.
Competitive Environment
SCE currently operates in a highly regulated environment in which it has an
obligation to deliver 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 Decision -- The CPUC's December 1995 decision on restructuring
California's electric utility industry started the transition to a new market
structure; competition and customer choice began on April 1, 1998. Key elements
of the CPUC's restructuring decision included: creation of the PX and ISO;
availability of customer choice for electricity supply and certain billing and
metering services; PBR for those utility services not subject to competition;
voluntary divestiture of at least 50% of utilities' gas-fueled generation; and
implementation of the CTC.
Restructuring Statute -- In September 1996, the State of California enacted
legislation to provide a transition to a competitive market structure. The
Statute substantially adopted 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
are being recovered through the terms of their contracts while most of the
remaining transition costs will be recovered through 2001. The Statute also
included provisions to finance a portion of the stranded costs that residential
and small commercial customers would have paid between 1998 and 2001, which
allowed SCE to reduce rates by at least 10% to these customers, effective
January 1, 1998. The Statute included a rate freeze for all other customers,
including large commercial and industrial customers, as well as provisions for
continued funding for energy conservation, low-income programs and renewable
resources. Despite the rate freeze, SCE expects to be able to recover its
revenue requirement during the 1998-2001 transition period. In addition, the
Statute mandated the implementation of the CTC that provides utilities the
opportunity to recover costs made uneconomic by electric utility restructuring.
Finally, the Statute contained provisions for the recovery (through 2006) of
reasonable employee-related transition costs, incurred and projected, for
retraining, severance, early retirement, outplacement and related expenses. A
voter initiative, known as California Proposition 9, seeks to overturn major
portions of the Statute. A more detailed discussion of Proposition 9 is in
"California Voter Initiative."
19
Rate Reduction Notes -- In December 1997, after receiving approval from both the
CPUC and the California Infrastructure and Economic Development Bank, a limited
liability company created by SCE issued approximately $2.5 billion of rate
reduction notes. Residential and small commercial customers, whose 10% rate
reduction began January 1, 1998, are repaying the notes over the expected
10-year term through non-bypassable charges based on electricity consumption.
Proposition 9 seeks to prohibit the collection of these non-bypassable charges,
or if the charges are found enforceable by a court, require SCE to offset such
charges with an equal credit to customers. See discussion in "Cash Flows from
Financing Activities."
Rate-setting -- In August 1997, the CPUC issued a decision which adopted a
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 (see "PBR" discussion below) 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 reallocated amount through
market revenue, other rate-making mechanisms or operation and maintenance
contracts with the new owners of the divested generation plants. Beginning
January 1, 1998, SCE's rates were unbundled into separate charges for energy,
transmission, distribution, the CTC, public benefit programs and nuclear
decommissioning. The transmission component is being collected through
FERC-approved rates, subject to refund.
PX and ISO -- On March 31, 1998, both the PX and ISO began accepting bids and
schedules for April 1, 1998, when the ISO took over operational control of the
transmission system. The hardware and software systems being utilized by the PX
and ISO in their bidding and scheduling activities were financed through loans
of $300 million (backed by utility guarantees) obtained by restructuring trusts
established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans
through charges for service to future PX and ISO customers. The restructuring
implementation costs related to the start-up and development of the PX, which
are paid by the utilities, will be recovered from all retail customers over the
four-year transition period. SCE's share of the charge is $45 million, plus
interest and fees. SCE's share of the ISO's start-up and development costs
(approximately $16 million per year) will be paid over a 10-year period.
Direct Customer Access -- Effective April 1, 1998, customers are now able to
choose to remain utility customers with either bundled electric service or an
hourly PX pricing option from SCE (which is purchasing its power through the
PX), or choose direct access, which means the customer can contract directly
with either independent power producers or energy service providers (ESPs) such
as power brokers, marketers and aggregators. Additionally, all
investor-owned-utility customers are paying the CTC whether or not they choose
to buy power through SCE. Electric utilities are continuing to provide the core
distribution service of delivering energy through their distribution system
regardless of a customer's choice of electricity supplier. The CPUC is
continuing to regulate the prices and service obligations related to
distribution services. As of October 1, 1998, approximately 42,000 of SCE's 4.3
million customers have requested the direct access option.
Revenue Cycle Services -- Effective April 1, 1998, customers have options
regarding metering, billing and related services (referred to as revenue cycle
services) that have been provided by California's investor-owned utilities. Now
ESPs can provide their customers with one consolidated bill for their services
and the utility's services, request the utility to provide a consolidated bill
to the customer or elect to have both the ESP and the utility bill the customer
for their respective charges. In addition, customers with maximum demand above
20 kW (primarily industrial and medium 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 September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they elect
to obtain revenue cycle services from someone other than SCE. Although the
decision adopted SCE's recommendation of using the net avoided cost, it also
adopted a methodology which results in higher credits to customers but requires
ESPs to pay service fees to SCE for the costs that SCE incurs as a result of
dealing with the ESP. SCE may experience a reduction in revenue security as a
result of this unbundling.
20
PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D)
PBR mechanism for SCE which began on January 1, 1997. Beginning in April 1998,
the transmission portion was separated from PBR and subject to ratemaking under
the rules of the FERC. The distribution-only PBR will extend through December
2001. Key elements of 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.
The CPUC is considering unbundling SCE's cost of capital based on major utility
function. In May 1998, SCE filed an application on this issue. A CPUC decision
is expected in early 1999.
Beginning in 1998, SCE's hydroelectric plants are operating under a PBR-type
mechanism. The mechanism sets the hydroelectric revenue requirement and
establishes a formula for extending it through the duration of the electric
industry restructuring transition period, or until market valuation of the
hydroelectric facilities, whichever occurs first. The mechanism provides that
power sales revenue from hydroelectric facilities in excess of the hydroelectric
revenue requirement be credited against the costs to transition to a competitive
market (see "CTC" discussion below).
Divestiture -- In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all 12 of its gas- and oil-fueled generation
plants. Under this proposal, SCE would continue to operate and maintain the
divested power plants for at least two years following their sale, as mandated
by the restructuring legislation enacted in September 1996. In addition, SCE
would offer workforce transition programs to those employees who may be impacted
by divestiture-related job reductions. In September 1997, the CPUC approved
SCE's proposal to auction the 12 plants.
SCE has sold and transferred ownership of all 12 of its gas- and oil-fueled
generation plants. The total sales price of the 12 plants was $1.2 billion, over
$500 million more than the combined book value. Net proceeds of the sales were
used to reduce stranded costs, which otherwise were expected to be collected
through the CTC mechanism.
CTC -- The costs to transition to a competitive market are being recovered
through a non-bypassable CTC. This charge applies to all customers who were
using or began using utility services on or after the CPUC's December 20, 1995,
decision date. The CTC is being determined residually by subtracting other rate
components for the PX, T&D, nuclear decommissioning and public benefit programs
from the frozen rate levels. SCE currently estimates its transition costs to be
approximately $10.6 billion (1998 net present value) from 1998 through 2030.
This estimate is 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 $6.4
billion from SCE's qualifying facilities contracts, which are the direct result
of prior legislative and regulatory mandates, and $4.2 billion from costs
pertaining to certain generating assets (successful completion of the sale of
SCE's gas-fired generating plants has reduced this estimate of transition costs
for SCE-owned generation) 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 Units 2 and 3 and the Palo Verde units (as
discussed in "Regulatory Matters"), and certain other costs. This issue was
separated into two phases; Phase 1 addressed the rate-making issues and Phase 2
the quantification issues.
Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the
establishment of a transition cost balancing account and annual transition cost
proceedings; the setting of a market rate forecast for 1998 transition costs;
the requirement that generation-related regulatory assets be amortized ratably
over a 48-month period; the establishment of calculation methodologies and
procedures for SCE to collect its transition costs from 1998 through the end of
the rate freeze; and the reduction of SCE's authorized rate of return on certain
assets eligible for transition cost recovery (primarily fossil- and
hydroelectric-generation related assets) beginning July 1997, five months
earlier than anticipated. SCE has filed an application for rehearing on the 1997
rate of return issue.
21
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described 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). During the third quarter of 1997, SCE discontinued
application of accounting principles for rate-regulated enterprises for its
investment in generation facilities based on new accounting guidance. The
financial reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the new guidance did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
new guidance did not specifically address the application of asset impairment
standards to these assets. SCE has retained 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. The
regulatory assets relate primarily to the recovery of accelerated income tax
benefits previously flowed through to customers, purchased power contract
termination payments and unamortized losses on reacquired debt. The new
accounting guidance also permits the recording of new generation-related
regulatory assets during the transition period that are probable of recovery
through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed relating to
the application of asset impairment standards to these assets. Using this
guidance has resulted in SCE reducing its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recording a regulatory asset on its
balance sheet for the same amount. For this impairment assessment, the fair
value of the investment was calculated by discounting future net cash flows.
This reclassification had no effect on SCE's results of operations.
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 (approximately $2.5
billion, after tax, at September 30, 1998) as a one-time, non-cash charge
against earnings.
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.
California Voter Initiative
On November 3, 1998, California voters will vote on Proposition 9, an initiative
supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric industry
restructuring legislation. Proposition 9 purports to: (1) require SCE and the
other California investor-owned utilities to provide at least a 20% rate
reduction to their residential and small commercial customers to be achieved
through cutting payments for nuclear and other fossil generation transition
costs; (2) eliminate cost recovery for nuclear generation plants and related
assets and obligations (other than reasonable decommissioning costs), except to
the extent such costs are recovered from competitive market sales through the PX
or contracts with the ISO; (3) eliminate cost recovery for non-nuclear
generation plants and related assets and obligations (other than costs
associated with QFs), except to the extent such costs are recovered from
competitive market sales through the PX or contracts with the ISO, unless the
CPUC finds that the utilities would be deprived of the opportunity to earn a
fair rate of return; and (4) prohibit the collection of any customer charges
necessary to pay principal, interest and other costs on the rate reduction bonds
(Fixed Transition Amounts or FTAs) or, if a court finds that the CPUC orders
authorizing the collection of FTAs are nevertheless enforceable, require the
FTAs to be offset with a concurrent equal credit. Proposition 9's purported rate
reduction would be in lieu of the 10% rate reduction for residential and small
commercial customers that went into effect on January 1, 1998.
If Proposition 9 is approved and implemented, and if SCE were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid, then
under applicable accounting principles SCE would
22
be required to write off generation-related regulatory assets and certain
investments in electric generation plant to the extent SCE were to conclude that
such assets were no longer probable of recovery due to reductions in future
revenue. SCE anticipates that such a one-time write-off would amount to as much
as $3.4 billion pre-tax. This pre-tax write-off would result in an after-tax
write-off of as much as $1.9 billion, or approximately $5 per share,
representing 50% of SCE's total shareholders' equity of $3.8 billion at
September 30, 1998.
Such an after-tax write-off, which would exceed SCE's current retained earnings
($820 million as of September 30, 1998), would severely impair SCE's ability to
pay dividends to its preferred shareholders and Edison International's ability
to pay dividends to its common shareholders. The potential earnings reductions
described below also would impair the payment of dividends. In addition, an
after-tax write-off of $1.9 billion would reduce the common equity ratio of
SCE's capital structure from approximately 49% to approximately 30%.
The duration and amount of the rate decrease contemplated by Proposition 9 is
uncertain and, if Proposition 9 is approved, will be subject to interpretation
by the courts and regulatory agencies. If all provisions of Proposition 9
ultimately are upheld against legal challenge and interpreted in an adverse
manner, the amount of the average earnings reductions to SCE could be as much as
$210 million per year from 1999 through 2001, and gradually decreasing to as
much as $10 million in 2007.
The earnings reduction and write-off estimates ultimately will depend on how the
courts and regulators interpret Proposition 9 and how future rate changes
unrelated to Proposition 9 affect SCE's electric revenue.
The financial impacts described above, either singly or in combination, would
likely cause the rating agencies that rate SCE's debt and preferred securities
to lower those ratings substantially, which would immediately reduce the market
value of SCE's $4.2 billion in outstanding debt and preferred securities,
increase the cost of raising new capital, and possibly preclude the use of
certain financial instruments for raising capital.
If the voters approve Proposition 9, then legal challenges by the California
utilities, including SCE, and others will ensue. SCE intends to vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions pending court review of the merits of its challenge. Although SCE
believes the litigation arguments challenging the enforceability of Proposition
9 would be compelling, no assurances can be given whether or when Proposition 9
would be overturned.
Environmental Protection
Edison International is subject to numerous environmental laws and regulations,
which require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.
As further discussed in Note 2 to the Consolidated Financial Statements, Edison
International records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup costs can
be estimated. Edison International reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site. Unless there is a probable amount, Edison International records the lower
end of this likely range of costs.
Edison International's recorded estimated minimum liability to remediate its 50
identified sites is $177 million. One of SCE's sites, a former pole-treating
facility, is considered a federal Superfund site and represents 40% of its
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 $247 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. SCE has sold all of
its gas- and oil-fueled power plants and has retained some liability associated
with the divested properties.
23
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $90 million of its recorded liability, through an incentive
mechanism. Under this mechanism, SCE will recover 90% of cleanup costs through
customer rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. Costs
incurred at SCE's remaining sites are expected to be recovered through customer
rates. SCE has recorded a regulatory asset of $145 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer
rates.
Edison International's identified sites include several sites for which there is
a lack of currently available information, including the nature and magnitude of
contamination, and the extent, if any, that Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can be made for these sites.
Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $4 million to $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.
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 environmental capital expenditures are $935
million for the 1998-2002 period, mainly for aesthetics treatment, including
undergrounding certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF) emanating
from power lines, household appliances and other electric sources may result in
adverse health effects has been the subject of scientific research. After many
years of research, scientists have not found that exposure to EMF causes disease
in humans. Research on this topic is continuing. However, the CPUC has issued a
decision which provides for a rate-recoverable research and public education
program conducted by California electric utilities, and authorizes these
utilities to take no-cost or low-cost steps to reduce EMF in new electric
facilities. SCE is unable to predict when or if the scientific community will be
able to reach a consensus on any health effects of EMF, or the effect that such
a consensus, if reached, could have on future electric operations.
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, which resulted in the removal of more tubes from
service than had been expected. The steam generator design allows for the
removal of up to 10% of the tubes before the rated capacity of the unit must be
reduced. As a result of the increased degradation, a mid-cycle inspection outage
was conducted in early 1998 for Unit 2. Continued degradation was found during
this inspection. Monitoring of this degradation will occur at the next scheduled
refueling outage in January 1999. An additional mid-cycle inspection outage may
be required early in 2000. With the results from the February 1998 outage, 7% of
the tubes have now been removed from service. In September 1998, San
24
Onofre Unit 2 experienced a small amount of leakage from a steam generator tube
plug which required an 11-day outage to repair.
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. A follow-up mid-cycle inspection indicated that the
erosion had been stabilized. Additional monitoring inspections are planned
during the next scheduled refueling outage in 1999. To date, 5% of Unit 3's
tubes have been removed from service. During Unit 2's February 1998 mid-cycle
outage, similar tube supports showed no significant levels of such erosion.
New Accounting Rules
A recently issued accounting rule requires that costs related to start-up
activities be expensed as incurred, effective January 1, 1999. Edison
International currently expenses its start-up costs and therefore does not
expect this new accounting rule to materially affect its results of operations
or financial position.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to be recognized on the balance sheet at fair
value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings. Edison
International is studying the impact of the new standard on its nonutility
subsidiaries, and is unable to predict at this time the impact on its financial
statements.
Year 2000 Issue
Many of Edison International's existing computer systems were originally
programmed to represent any date by using six digits (e.g., 12/31/99) rather
than eight digits (e.g., 12/31/1999). Accordingly, such programs could fail or
create erroneous results when attempting to process information containing dates
after December 31, 1999. This situation has been referred to generally as the
Year 2000 Issue.
SCE has a comprehensive program in place to address potential Year 2000 impacts.
SCE divides its Year 2000 activities into five phases: inventory, impact
assessment, remediation, testing and implementation. SCE's plan for the Year
2000 readiness of critical systems is to be 75% complete by year-end 1998, and
100% complete by July 1999. A critical system is defined as those applications
and systems, including embedded processor technology, which if not appropriately
remediated, may have a significant impact on customers, the revenue stream,
regulatory compliance, or the health and safety of personnel.
The scope of this program includes three categories: mainframe computing,
distributed computing and physical assets (also known as embedded processors).
For mainframe financial systems, Year 2000 remediation was completed in the
fourth quarter of 1997. Remediation for the material management system was
completed in the second quarter of 1998. The customer information and billing
system is scheduled to be replaced by the first quarter of 1999 with a system
designed to be Year 2000-ready. Distributed computing assets include operations
and business information systems. The critical operations information systems
include outage management, power management, and plant monitoring and access
retrieval systems. Business information systems include a data acquisition
system for billing, the computer call center support system, credit support and
maintenance management. The physical asset portfolio includes systems in the
generation, transmission, distribution, telecommunications and facilities areas.
SCE has completed the inventory and impact assessment phases. Remediation,
testing and implementation activities are in progress for each of the three
categories. SCE is on schedule to
25
have its mainframe computing, distributed computing and physical assets Year
2000-ready within the timeframe discussed above.
The other essential component of the SCE Year 2000 readiness program is to
identify and assess vendor products and business partners (external parties) for
Year 2000 readiness, as these external parties may have the potential to impact
SCE's Year 2000 readiness. SCE has a process in place to identify and contact
vendors and business partners to determine their Year 2000 status, and is
evaluating the responses. SCE's general policy requires that all newly purchased
products be Year 2000-ready or otherwise designed to allow SCE to determine
whether such products present Year 2000 issues. SCE is also working to address
Year 2000 issues related to all ISO and PX interfaces, as well as joint
ownership facilities. SCE also intends to exchange Year 2000 readiness
information (including, but not limited to, test results and related data) with
certain external parties as part of SCE's internal Year 2000 readiness efforts.
The current estimate of the costs to complete these modifications, including the
cost of new hardware and software application modification, is $80 million,
about half of which is expected to be capital costs. SCE's Year 2000 costs
expended through September 30, 1998, were $20 million. SCE expects current rate
levels for providing electric service to be sufficient to provide funding for
these modifications.
Although SCE is confident that its critical systems will be fully Year
2000-ready prior to year-end 1999, SCE believes that prudent business practices
call for the development of contingency plans. Such contingency plans shall
include developing strategies for dealing with the most reasonably likely worst
case scenario concerning Year 2000-related processing failures or malfunctions
due to SCE's internal systems or from external parties. As noted above, SCE is
currently in the remediation and testing phases for many of its internal systems
and is assessing risks posed by external parties. SCE is working with certain
industry groups, including the North American Electric Reliability Council and
the Electric Power Research Institute, in an effort to help define a reasonably
likely worst case scenario and in the development of contingency plans. SCE's
contingency plans are expected to be completed by March 1999; therefore, these
risk factors are not yet fully known, and SCE's reasonably likely worst case
scenario also is unknown at this time. Edison International does not expect the
Year 2000 issue to have a material adverse effect on its results of operation or
financial position; however, if not effectively remediated, negative effects
from Year 2000 issues, including those related to internal systems, vendors,
business partners, the ISO, the PX or customers, could cause results to differ.
Edison Mission Energy is continuing its Year 2000 Issue review at its power
projects and does not anticipate material expenditures to resolve this issue.
Forward-looking Information
In the preceding 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 further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business, including direct customer access to retail energy suppliers and the
unbundling of revenue cycle services such as metering and billing; changes in
prices of electricity and fuel costs; changes in market interest or currency
exchange rates; foreign currency devaluation; new or increased environmental
liabilities; the effects of the Year 2000 Issue; the passage and implementation
of California Proposition 9; and other unforeseen events.
26
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings
Edison International
Tradename Litigation
As previously reported in Part II, Item 1 of the Registrant's Quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, on
September 30, 1997, an action was filed against Edison International in the
United States District Court for the Southern District of New York alleging
trademark infringement under the Lanham Act and related state causes of action
for unfair competition. The complaint requested injunctive relief restraining
Edison International from using various tradenames and trademarks utilizing the
"Edison" name and sought to recover unspecified damages in profits from Edison
International allegedly arising from infringing activities. On November 19,
1997, Edison International filed and served its answer to the complaint denying
all of the substantive allegations and asserting affirmative defenses. After an
initial status conference, the court stayed discovery in this matter to allow
the parties to discuss a resolution of the matter. Such discussions are
continuing and the stay of discovery has been extended by agreement of the
parties.
Geothermal Generators' Litigation
Edison International, along with Southern California Edison Company (SCE), The
Mission Group and Mission Power Engineering Company, has been named as a
defendant in a lawsuit more fully described under "Southern California Edison
Company - Geothermal Generators' Litigation."
Edison Mission Energy
PMNC Litigation
As previously reported in Part II, Item 1 of the Registrant's Quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, 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. (Brooklyn Navy Yard), Mission
Energy New York, Inc. and B-41 Associates, L.P., 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, asserting general monetary claims in excess of
$13 million under the construction turnkey agreement. On March 26, 1998, the
Superior Court in the California action granted PMNC's motion for attachment
against Brooklyn Navy Yard in the amount of $43 million. PMNC subsequently
attached three checking accounts in the approximate amount of $500,000. On the
same day, the court stayed all proceedings in the California action pending an
order by the New York Appellate Court of the appeal by PMNC of a denial of its
motion to dismiss the New York action.
Southern California Edison Company
Wind Generators' Litigation
As previously reported in Part II, Item 1 of the Registrant's Quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, 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 alleged 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
sought declaratory relief regarding
27
the proper interpretation of the contracts. Plaintiffs alleged a combined total
of approximately $189 million in which included consequential damages claimed in
seven of the eight lawsuits. Following the March 1 ruling, a ninth lawsuit was
filed in Los Angeles County 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.
After receiving a favorable decision in the liability phase of the lead case,
SCE agreed to settle with the plaintiffs in seven of the lawsuits on terms
whereby SCE waived its rights to recover costs against such plaintiffs in
exchange for their agreement that there is only one fixed price period under
each of their power purchase contracts with SCE and a mutual dismissal with
prejudice of claims. SCE also entered into a settlement agreement with the
plaintiff in another of the lawsuits which resolved the issue of multiple fixed
price periods on the same terms and which also resolved a related issue unique
to that plaintiff in exchange for a nominal payment by SCE. This settlement was
subject to bankruptcy court approval in bankruptcy proceedings involving the
plaintiff. On April 24, 1998, the bankruptcy court issued an order approving the
settlement. Although the court has not yet set a date for trial of the
outstanding issues in the lead case related to SCE's cross-claim for damages, a
trial setting conference has been set for December 3, 1998.
Geothermal Generators' Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, on June
9, 1997, SCE filed a complaint in Los Angeles County Superior Court against an
independent power producer of geothermal generation and six of its affiliated
entities (Coso parties). SCE alleges that in order to avoid power production
plant shutdowns caused by excessive noncondensable gas in the geothermal field
brine, the Coso parties routinely vented highly toxic hydrogen sulfide gas from
unmonitored release points beginning in 1990 and continuing through at least
1994, in violation of applicable federal, state and local environmental law.
According to SCE, these violations constituted material breaches by the Coso
parties of their obligations under their contracts with SCE and applicable law.
The complaint sought termination of the contracts and damages for excess power
purchase payments made to the Coso parties. The Coso parties' motion to transfer
venue to Inyo County Superior Court was granted on August 31, 1997.
The Coso parties have also asserted various claims against SCE, as well as The
Mission Group and Mission Power Engineering (Mission parties) in a
cross-complaint filed in the action commenced by SCE as well as in a separate
action filed against SCE by three of the Coso parties in Inyo County Superior
Court. Following a hearing on November 20, 1997, the court struck all but two
causes of action asserted in the separate action on the grounds that they should
have been raised as part of the Coso parties' cross-complaint, and ordered the
remaining two causes of action consolidated for all purposes with the action
filed by SCE.
As a result of motion practice by SCE and the Mission parties, the Coso parties
filed a second amended cross-complaint on December 29, 1997, and a third amended
cross-complaint on August 21, 1998. The third amended cross-complaint names SCE,
the Mission parties and Edison International. As against SCE, the third amended
cross-complaint purports to state causes of action for declaratory relief;
breach of the covenant of good faith and fair dealing; inducing breach of
agreements between the Coso parties and their former employees; breach of an
earlier settlement agreement between the Mission parties and the Coso parties;
slander and disparagement; injunctive relief and restitution for unfair business
practices; anticipatory breach of the contracts; and violations of Public
Utilities Code ss.ss. 453, 702 and 2106. As against the Mission parties, the
third amended cross-complaint seeks damages for breach of warranty of authority
with respect to the settlement agreement and equitable indemnity. The third
amended cross-complaint seeks restitution, compensatory damages in excess of
$115,000,000, punitive damages in an amount not less than $400,000,000,
interest, attorney's fees, declaratory relief and injunctive relief.
On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting appropriate
affirmative defenses. In addition, SCE filed a cross-complaint for reformation
of the contracts alleging that if they are not susceptible to SCE's
28
interpretation, they should be reformed to reflect the parties' true intention.
At this time, the Coso parties have not filed a response to SCE's
cross-complaint.
SCE has also filed a motion for summary adjudication with respect to the fourth
cause of action of the third amended cross-complaint for inducing breach of
employment agreements. The hearing on the motion is currently scheduled for
November 4, 1998.
The Mission parties and Edison International demurred to and moved to strike
portions of the third amended cross-complaint. These matters were heard by the
court on October 22, 1998. On October 27, 1998, the court issued an order
continuing the hearing on Edison International's demurrer to December 17, 1998,
and stayed discovery with respect to Edison International until that time. The
Mission parties' demurrer and motion to strike are still under submission. The
court's further disposition of these matters may result in the filing of further
amended pleadings with respect to Edison International and/or SCE.
On October 19, 1998, the Coso parties purported to file a first amended
cross-complaint against Edison International only. In the amended pleading, the
Coso parties assert, among other things, that SCE and Edison International are
alter egos; that SCE engaged in anticompetitive conduct; and that SCE violated
rules of the California Public Utilities Commission governing transactions
between SCE and its affiliates. These allegations are similar to those set forth
in the second amended complaint filed by three of the Coso parties, described
below. In its reply brief in support of its demurrer and at the October 22
hearing, described in the preceding paragraph, Edison International objected to
the filing of the first amended cross-complaint on the grounds that it was filed
without leave of court and has no legal effect. On October 27, 1998, the court
issued an order striking the purported first amended cross-complaint in its
entirety.
On August 21, 1998, the court granted SCE's motion to set aside a default
entered with respect to the first amended complaint filed by three of the Coso
parties in the separately filed (now consolidated) action. SCE filed an answer
to the first amended complaint on September 21, 1998, generally denying its
allegations and asserting appropriate affirmative defenses. Since then, the
parties have agreed to stipulate to the filing of a second amended complaint,
and it is likely that the court will approve the filing of the amended pleading,
which names SCE and Edison International. The proposed second amended complaint
seeks injunctive relief and restitution for unfair competition with respect to a
broad range of purported anticompetitive conduct by SCE with respect to its
administration and interpretation of standard offer contracts and with respect
to implementation and operation of the restructured power market. In addition,
the proposed second amended complaint alleges that SCE engaged in false
advertising with respect to the cost and reliability of power generated by
qualifying facilities, such as the facilities owned by the Coso parties. The
proposed amended pleading also alleges violations of Public Utilities Code ss.
2106. The proposed amended pleading seeks restitution, injunctive relief,
unspecified compensatory damages and punitive damages in an amount not less than
$500,000,000. Assuming that the court grants the Coso parties leave to file the
second amended complaint in its current form, Edison International and SCE
intend to file a demurrer and a motion to strike.
On June 29, 1998, the Court adopted a revised discovery plan which provides for
approximately eighteen months of discovery and periodic status conferences.
Discovery and motion practice related to discovery is active, except that the
court has stayed discovery with respect to Edison International through at least
December 17, 1998. On August 28, 1998, following the first status conference,
the court set a trial date of March 1, 2000. The court reserved jurisdiction to
advance or continue the trial date. The materiality of net final judgments
against Edison International or SCE in these actions would be largely dependent
on the extent to which any damages or additional payments which might result
therefrom are recoverable through rates.
Electric and Magnetic Fields (EMF) Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, 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.
29
In December 1995, the court granted SCE's motion for summary judgment in the
first lawsuit and dismissed the case. Plaintiffs have filed a Notice of Appeal.
Briefs have been submitted but no date for oral argument has been set.
The second lawsuit has been dismissed by the plaintiffs. However, one of the
named plaintiffs is now deceased and a wrongful death action was filed by her
husband and children on May 7, 1998. This action was dismissed by the court
without leave to amend on September 16, 1998.
On July 23, 1998, the court granted SCE's motion for summary judgment in the
third lawsuit and dismissed this case.
A California Court of Appeal decision, Cynthia Jill Ford et al. v. Pacific Gas
and Electric Co. (Ford), has held that the Superior Courts do not have
jurisdiction to decide issues, such as those concerning EMF, which are regulated
by the CPUC. The California Supreme Court recently denied the plaintiffs'
petition for review in Ford and it is now binding throughout California. SCE
intends to seek dismissal of the remaining case in light of the Court of
Appeal's decision.
San Onofre Personal Injury Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, SCE is
involved in six lawsuits alleging personal injuries relating to San Onofre.
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 Company
(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 in the first lawsuit. 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 appealed this ruling to the Ninth Circuit Court of Appeals. On
May 28, 1998, the Ninth Circuit Court affirmed the lower court's judgment in
favor of SCE.
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 in a second
lawsuit. Plaintiffs also named Combustion Engineering and the Institute of
Nuclear Power Operations as defendants. 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 appealed this ruling to the Ninth Circuit Court of
Appeals. On May 28, 1998, the Ninth Circuit Court affirmed the lower court's
judgment in favor of SCE.
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 in the third lawsuit. Plaintiffs also named Combustion
Engineering and the Institute of Nuclear Power Operations as defendants. All
trial court proceedings have been stayed pending the ruling of the Court of
Appeals, issued by the Ninth Circuit on May 28, 1998 affirming the lower court's
judgment in favor of SCE, in the cases described in the above two paragraphs. A
trial date has not yet been set.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California in the fourth lawsuit. Plaintiffs
also named Combustion Engineering. The trial in this case took place over
approximately 22 days between January and March 1998 and resulted in a jury
verdict for both defendants. On March 19, 1998, the plaintiffs filed a motion
for a new trial. That motion was denied on June 9, 1998. On July 6, 1998,
plaintiffs filed a notice of appeal stating that they will appeal the trial
court's judgment to the Ninth Circuit Court of Appeals.
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 in the fifth lawsuit. Plaintiffs also named Combustion Engineering.
On August 12, 1996, the Court dismissed the claims of the former worker and her
husband with prejudice. This case, with only the son as plaintiff, is expected
to go to trial in early 1999.
30
On November 20, 1997, a former contract worker at San Onofre and his wife sued
SCE in the Superior Court of California, County of San Diego in the sixth
lawsuit. The case was removed to the U.S. District Court for the Southern
District of California. SCE filed a motion to dismiss the complaint for failure
to state a claim. In April 1998, the plaintiffs and SCE stipulated that SCE's
motion to dismiss be granted and that the plaintiffs be given leave to file an
amended complaint on or before May 11, 1998. On May 11, 1998, the plaintiffs
filed a first amended complaint. On May 22, 1998, SCE filed an answer denying
the material allegations of the first amended complaint. A pre-trial conference
is scheduled for May 17, 1999.
False Claims Act Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, in
September 1997, SCE became aware of a complaint filed in the Southern District
of the U.S. District Court of California by a former San Onofre employee, acting
at his own initiative on behalf of the United States under the False Claims Act,
against SCE and SDG&E. SCE and SDG&E filed separate motions to dismiss this
lawsuit on November 6, 1997. The former employee responded to both motions on
December 20, 1997. SCE and SDG&E replied to the former employee's responses on
January 13, 1998. Oral argument on the motion to dismiss was heard on January
20, 1998. On July 1, 1998, the U.S. District Court granted SCE's motion to
dismiss. The court found that the filed rate doctrine barred the former
employee's federal claims, but declined to rule on whether the state law claims
would be likewise barred. Instead, the court declined to exercise jurisdiction
over the state law claims in the wake of the dismissal of the federal claims.
The period for appeal of the U.S. District Court's decision has passed. Mr.
Rubaii did not file an appeal. As a result, this litigation at the U.S. District
Court is now dismissed with prejudice.
Mohave Generating Station Environmental Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Reports
on Form 10-Q for the quarters ended March 31, 1998, and June 30, 1998, on
February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in the
U.S. District Court of Nevada against SCE, which operates Mohave, and the other
three co-owners of the Mohave Generating Station. The lawsuit alleges that
Mohave has been violating various provisions of the Clean Air Act, the Nevada
state implementation plan, certain Environmental Protection Agency orders, and
applicable pollution permits relating to opacity and sulfur dioxide emission
limits over the last five years. The plaintiffs seek declaratory and injunctive
relief as well as civil penalties. Under the Clean Air Act, the maximum civil
penalty obtainable is $25,000 per day per violation. SCE and the co-owners
obtained an extension to respond to the complaint and on April 10, 1998, a
motion to dismiss was filed. The plaintiffs filed an opposition to the motion to
dismiss and a motion for partial summary judgment on May 8, 1998. On May 29,
1998, SCE and the co-owners filed their reply brief to the plaintiffs'
opposition. On June 15, 1998, the plaintiffs filed their final reply brief. SCE
and the co-owners filed their final reply to plaintiffs' opposition on June 25,
1998. The initial ruling by the court on these motions is expected in early
1999.
In addition, on June 4, 1998, the plaintiffs served SCE and its co-owners with a
60-day supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On October 9,
1998, Plaintiffs filed a motion to extend time to add a party and amend
complaint. Notwithstanding their supplemental notice of intent to sue,
Plaintiffs missed the deadline pursuant to the court's Discovery Plan and
Scheduling Order to file an amended complaint. On October 26, 1998, the
co-owners filed a combined opposition to plaintiffs' motion to extend time to
add a party and amend the complaint. Various discovery motions have been filed
by both parties. It is not expected that these additional filings will
substantially change the timetable for the court's initial ruling on the pending
motions to dismiss and for partial summary judgment.
California Proposition 9 Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Report
on Form 10-Q for the quarter ended June 30, 1998, California voters will vote on
Proposition 9, an initiative supported by various consumer groups, in
California's November 3, 1998, general election. Proposition 9 would overturn
31
major portions of California's electric industry restructuring legislation.
Proposition 9 purports to: (1) require SCE and the other California
investor-owned utilities to provide at least a 20% rate reduction to their
residential and small commercial customers to be achieved through cutting
payments for nuclear and other fossil generation transition costs; (2) eliminate
cost recovery for nuclear generation plants and related assets and obligations
(other than reasonable decommissioning costs), except to the extent such costs
are recovered from competitive market sales through the Power Exchange or
contracts with the Independent System Operator; (3) eliminate cost recovery for
non-nuclear generation plants and related assets and obligations (other than
costs associated with qualifying facilities), except to the extent such costs
are recovered from competitive market sales through the Power Exchange or
contracts with the Independent System Operator, unless the CPUC finds that the
utilities would be deprived of the opportunity to earn a fair rate of return;
and (4) prohibit the collection of any customer charges necessary to pay
principal, interest and other costs on the rate reduction bonds or, if a court
finds that the CPUC orders authorizing the collection of such charges are
nevertheless enforceable, require the charges to be offset with a concurrent
equal credit. Proposition 9's purported rate reduction would be in lieu of the
10% rate reduction for residential and small commercial customers that went into
effect on January 1, 1998.
In May 1998, a coalition of California business organizations and utilities
filed a petition for writ of mandate challenging Proposition 9 as illegal and
unconstitutional on its face and seeking to have it removed from the November
1998 ballot. In July 1998, the petition was denied by the California Court of
Appeal and an appeal was denied by the California Supreme Court.
Under the terms of a servicing agreement relating to the rate reduction notes,
SCE (acting as the servicer) is required to take such legal or administrative
actions as may be reasonably necessary to block or overturn any attempts to
cause a repeal of, modification of, or supplement to the electric industry
restructuring legislation, the financing order issued by the CPUC, or the rights
of holders of the property right authorized by the legislation and the financing
order, by legislative enactment, voter initiative or constitutional amendment
that would be adverse to holders of the rate reduction certificates.
Bankers Trust Company of California, N.A., acting as trustee for the holders of
rate reduction certificates, has sent a letter to the holders of record on
October 14, 1998, notifying them about certain actions the trustee is taking
related to Proposition 9. The letter states that Proposition 9, if approved by
the voters and upheld by the courts, would impair the rights of the holders and
would lead to a default in the payment of principal and interest. The letter
also states that Proposition 9, if approved, would breach the statutory and
contractual pledge by the State of California not to limit or alter payment of
principal and interest on the rate reduction certificates, and that such breach
would constitute an event of default under the agreements pursuant to which the
certificates were issued. Therefore, the letter states, the trustee is
requesting authorization from the holders to commence litigation to enjoin
Proposition 9 if it passes, to collect damages on behalf of the holders for the
breach of the State's statutory and contractual pledge, and for other
appropriate relief. The trustee's letter also attached letters from SCE, Pacific
Gas and Electric Company, and San Diego Gas & Electric Company, in their
capacities as servicers, restating their intention to comply with their
obligations under the related agreements to take reasonable and necessary legal
actions to overturn Proposition 9 if it is approved by the voters.
If California voters approve Proposition 9, legal challenges by the California
utilities, including SCE, and others will ensue. SCE intends to vigorously
challenge Proposition 9 as unconstitutional and to seek an immediate stay of its
provisions pending court review of the merits of SCE's challenge. Although SCE
believes the litigation arguments challenging the enforceability of Proposition
9 would be compelling, no assurances can be given whether or when Proposition 9
would be overturned.
SCE is unable to predict the outcome of this matter, but if Proposition 9 is
voted into law, and not immediately stayed and ultimately invalidated by the
courts, it could have a material adverse effect on SCE's results of operations
and financial position as more specifically described in "California Voter
Initiative" in Item 2 of Part 1 of this quarterly Report, which is hereby
incorporated by reference.
32
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Articles of Incorporation (File No. 1-9936, Form 10-Q for the
quarterly period ended March 31, 1996)*
3.2 Bylaws as adopted by the Board of Directors effective
September 17, 1998
11. Computation of Primary and Fully Diluted Earnings Per Share
27. Financial Data Schedule
(b) Reports on Form 8-K:
July 13, 1998 Item 5: Other Events: Proposed Initiative
July 27, 1998 Item 5. Other Events: Stock Repurchase Plan
California Voter Initiative
Agreement for Subsidiary's Purchase
of Home Security Company
- ----------------------
* Incorporated by reference pursuant to Rule 12b-32 .
33
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
October 30, 1998