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 June 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 800)
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 August 12, 1998
- ----------------------------------- -----------------------------------------
Common Stock, no par value 353,638,586
EDISON INTERNATIONAL
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income -- Three and Six
Months Ended June 30, 1998, and 1997 1
Consolidated Statements of Comprehensive Income --
Three and Six Months Ended June 30, 1998, and 1997 1
Consolidated Balance Sheets -- June 30, 1998,
and December 31, 1997 2
Consolidated Statements of Cash Flows -- Six Months
Ended June 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 32
EDISON INTERNATIONAL
PART I -- FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
3 Months Ended 6 Months Ended
June 30, June 30, June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Sales to ultimate consumers $1,531,452 $1,763,003 $3,077,286 $3,391,417
Sales to power exchange 303,685 -- 303,685 --
Other 87,330 80,960 164,185 147,948
- -------------------------------------------------------------------------------------------------------------------
Total electric utility revenue 1,922,467 1,843,963 3,545,156 3,539,365
Diversified operations 320,253 323,219 607,124 628,543
- -------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,242,720 2,167,182 4,152,280 4,167,908
- -------------------------------------------------------------------------------------------------------------------
Fuel 100,259 194,328 267,580 394,561
Purchased power -- contracts 525,355 587,660 1,101,862 1,216,335
Purchased power -- power exchange 343,784 -- 343,784 --
Provisions for regulatory adjustment clauses-- net 485,492 (3,850) 247,474 (92,023)
Other operating expenses 562,533 457,964 949,702 788,007
Maintenance 98,597 116,848 200,566 213,002
Depreciation, decommissioning and amortization 404,031 342,254 815,354 682,375
Income taxes 99,010 113,541 235,728 209,616
Property and other taxes 33,194 32,682 73,955 72,992
Gains on sale of utility plant (708,154) (3,065) (708,149) (2,836)
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,944,101 1,838,362 3,527,856 3,482,029
- -------------------------------------------------------------------------------------------------------------------
Operating income 298,619 328,820 624,424 685,879
- -------------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan -- (11,381) -- (22,690)
Allowance for equity funds used during construction 2,908 1,897 5,690 3,900
Interest and dividend income 25,078 19,149 55,794 34,991
Minority interest (859) (9,724) (2,367) (37,689)
Other nonoperating income (deductions)-- net (9,107) (6,870) (18,308) (9,732)
- -------------------------------------------------------------------------------------------------------------------
Total other income (deductions)-- net 18,020 (6,929) 40,809 (31,220)
- -------------------------------------------------------------------------------------------------------------------
Income before interest and other expenses 316,639 321,891 665,233 654,659
- -------------------------------------------------------------------------------------------------------------------
Interest on long-term debt 147,505 152,382 326,617 304,806
Other interest expense 20,319 25,001 41,531 56,260
Allowance for borrowed funds used during
construction (1,979) (2,284) (3,871) (4,696)
Capitalized interest (4,461) (2,899) (8,365) (8,076)
Dividends on subsidiary preferred securities 9,952 10,669 20,008 22,531
- -------------------------------------------------------------------------------------------------------------------
Total interest and other expenses-- net 171,336 182,869 375,920 370,825
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 145,303 $ 139,022 $ 289,313 $ 283,834
- -------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock
outstanding 360,251 408,310 365,150 413,888
Basic earnings per share $.40 $.34 $.79 $.69
Diluted earnings per share $.40 $.34 $.78 $.68
Dividends declared per common share $.26 $.25 $.52 $.50
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
3 Months Ended 6 Months Ended
June 30, June 30, June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $145,303 $139,022 $289,313 $283,834
Cumulative translation adjustments-- net (7,585) 7,270 733 (19,631)
Unrealized gains on securities-- net 1,384 7,205 15,398 14,448
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $139,102 $153,497 $305,444 $278,651
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
June 30, December 31,
1998 1997
- -------------------------------------------------------------------------------------------------------------------
ASSETS (Unaudited)
Transmission and distribution:
Utility plant, at original cost, subject to
cost-based rate regulation $11,454,066 $11,213,352
Accumulated provision for depreciation (5,796,847) (5,573,742)
Construction work in progress 481,192 492,614
- -------------------------------------------------------------------------------------------------------------------
6,138,411 6,132,224
- -------------------------------------------------------------------------------------------------------------------
Generation:
Utility plant, at original cost,
not subject to cost-based rate regulation 2,021,636 9,522,127
Accumulated provision for depreciation and
decommissioning (1,065,888) (4,970,137)
Construction work in progress 86,043 100,283
Nuclear fuel, at amortized cost 133,070 154,757
- -------------------------------------------------------------------------------------------------------------------
1,174,861 4,807,030
- -------------------------------------------------------------------------------------------------------------------
Total utility plant 7,313,272 10,939,254
- -------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision for
depreciation of $263,826 and $238,386 at respective dates 3,098,311 3,178,375
Nuclear decommissioning trusts 2,056,275 1,831,460
Investments in partnerships and
unconsolidated subsidiaries 1,306,520 1,340,853
Investments in leveraged leases 1,386,397 959,646
Other investments 323,749 260,427
- -------------------------------------------------------------------------------------------------------------------
Total other property and investments 8,171,252 7,570,761
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents 1,655,860 1,906,505
Receivables, including unbilled revenue,
less allowances of $21,345 and $26,722
for uncollectible accounts at respective dates 1,163,372 1,077,671
Fuel inventory 50,965 58,059
Materials and supplies, at average cost 116,678 132,980
Accumulated deferred income taxes-- net 313,360 123,146
Regulatory balancing accounts-- net 50,234 193,311
Prepayments and other current assets 54,136 105,811
- -------------------------------------------------------------------------------------------------------------------
Total current assets 3,404,605 3,597,483
- -------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net 2,561,325 --
Unamortized debt issuance and reacquisition expense 362,125 359,304
Rate phase-in plan -- 3,777
Income tax-related deferred charges 1,559,336 1,543,380
Other deferred charges 1,212,663 1,087,108
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 5,695,449 2,993,569
- -------------------------------------------------------------------------------------------------------------------
Total assets $24,584,578 $25,101,067
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
June 30, December 31,
1998 1997
- -------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES (Unaudited)
Common shareholders' equity:
Common stock (355,014,497 and 375,764,429
shares outstanding at respective dates) $2,136,122 $ 2,260,974
Accumulated other comprehensive income:
Cumulative translation adjustments-- net 31,189 30,456
Unrealized gain in equity securities-- net 75,428 60,030
Retained earnings 2,812,621 3,175,883
- -------------------------------------------------------------------------------------------------------------------
5,055,360 5,527,343
- -------------------------------------------------------------------------------------------------------------------
Preferred securities of subsidiaries:
Not subject to mandatory redemption 128,755 183,755
Subject to mandatory redemption 406,700 425,000
Long-term debt 8,677,728 8,870,781
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 14,268,543 15,006,879
- -------------------------------------------------------------------------------------------------------------------
Other long-term liabilities 495,703 479,637
- -------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt 791,407 868,026
Short-term debt 139,498 329,550
Accounts payable 443,642 441,049
Accrued taxes 738,798 576,841
Accrued interest 147,969 131,885
Dividends payable 92,893 95,146
Deferred unbilled revenue and other current liabilities 1,385,007 1,285,679
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,739,214 3,728,176
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 4,319,530 4,085,296
Accumulated deferred investment tax credits 333,919 350,685
Customer advances and other deferred credits 1,413,751 1,441,303
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits 6,067,200 5,877,284
- -------------------------------------------------------------------------------------------------------------------
Minority interest 13,918 9,091
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $24,584,578 $25,101,067
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
3
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
6 Months Ended
June 30,
- -------------------------------------------------------------------------------------------------------------------
1998 1997
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 289,313 $ 283,834
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 815,354 682,375
Other amortization 76,334 35,814
Rate phase-in plan 3,777 21,584
Deferred income taxes and investment tax credits 4,802 (13,317)
Equity in income from partnerships and unconsolidated
subsidiaries (62,727) (84,014)
Other long-term liabilities 16,066 82,141
Regulatory asset related to the sale of utility plant (107,991) --
Net gains on sale of utility plant (640,339) --
Other-- net (149,610) (91,267)
Changes in working capital:
Receivables (123,278) (52,220)
Regulatory balancing accounts 143,077 (94,972)
Fuel inventory, materials and supplies 23,396 11,714
Prepayments and other current assets 62,503 86,223
Accrued interest and taxes 178,041 125,139
Accounts payable and other current liabilities 153,165 (48,768)
Distributions from partnerships and unconsolidated subsidiaries 70,453 69,058
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 752,336 1,013,324
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 716,441 1,475,537
Long-term debt repaid (873,737) (1,142,534)
Common stock issued -- 4,661
Common stock repurchased (586,297) (500,285)
Preferred securities redeemed (73,300) (100,000)
Rate reduction notes repaid (82,465) --
Nuclear fuel financing-- net (18,871) (7,061)
Short-term debt financing-- net (190,052) 235,592
Dividends paid (189,505) (210,944)
Other-- net 367 973
- -------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (1,297,419) (244,061)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (398,277) (345,975)
Proceeds from sale of plant 1,149,139 142,273
Funding of nuclear decommissioning trusts (76,881) (74,573)
Investments in partnerships and unconsolidated subsidiaries (53,636) (162,076)
Unrealized gain on securities-- net 15,398 14,448
Investments in leveraged leases (336,637) (270,626)
Other-- net (4,668) (73,591)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by investing activities 294,438 (770,120)
- -------------------------------------------------------------------------------------------------------------------
Net decrease in cash and equivalents (250,645) (857)
Cash and equivalents, beginning of period 1,906,505 896,594
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $1,655,860 $ 895,737
- -------------------------------------------------------------------------------------------------------------------
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 (EITF), 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 SCE's balance sheets display a separate caption for
its investments in generation. Application of accounting principles for
enterprises in general 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 June 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
5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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. A
voter initiative on the November 1998 ballot 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 -- 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. 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.
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
6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
customer's choice of electricity supplier. The CPUC is continuing to regulate
the prices and service obligations related to distribution services.
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 determining whether any credit
should be provided by the utility to customers who elect to have ESPs provide
them with revenue cycle services, and the amount of any such credit, the CPUC
has indicated that it is appropriate to provide such customers with the
utility's avoided costs net of costs incurred by the utility to facilitate the
provision of such services by a firm other than the utility.
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. On May 8, 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 all 12 of its gas- and oil-fueled generation plants. Transfer of
ownership of 11 plants was completed by June 30, 1998, and the transfer of
ownership of the 12th plant took place on July 8, 1998. 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
7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 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 a consensus reached by the
Financial Accounting Standards Board's Emerging Issues Task Force (EITF). The
financial reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the EITF consensus did not require SCE to write off any of
its generation-related assets, including related regulatory assets. However, the
EITF 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 consensus reached by the
EITF also permits the recording of new generation-related regulatory assets
during the transition period that are probable of recovery through the CTC
mechanism.
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 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
generation-related regulatory assets no longer probable, SCE would be required
to write off the remaining balance of such assets (approximately $2.4 billion,
after tax, at June 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
8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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 Proposition 9 -- November 1998 Voter Initiative
In November 1997, individuals representing The Utilities Reform Network, Public
Media Center and the Coalition Against Utility Taxes filed a proposed voter
initiative that seeks to overturn major portions of the electric industry
restructuring legislation enacted in California in September 1996 (Statute). The
voter initiative proposes, among other things, to: (i) impose an additional 10%
rate reduction for residential and small commercial customers beyond the 10%
reduction that went into effect on January 1, 1998; (ii) block stranded-cost
recovery of nuclear investments; (iii) restrict stranded-cost recovery of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the opportunity to earn a fair rate of return; and (iv) prohibit the
collection of any charges in connection with a financing order for the purpose
of making payments on rate reduction notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.
On June 24, 1998, the California Secretary of State announced that the proposed
voter initiative qualified for the November 1998 ballot. On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.
On May 22, 1998, Californians for Affordable and Reliable Electric Service
(CARES), a coalition of California business organizations and utilities, filed a
petition for writ of mandate with the Court of Appeal of the State of
California. CARES is sponsored by the California Business Roundtable, the
California Chamber of Commerce, San Diego Gas & Electric Company, the California
Manufacturers Association, Pacific Gas & Electric Company, the California
Retailers Association, and SCE, among other groups. The CARES petition
challenged the initiative as illegal and unconstitutional on its face, and
sought to remove the initiative from the November 1998 ballot. On July 2, 1998,
the Court of Appeal denied the CARES petition. On July 6, 1998, CARES filed its
appeal of the denial with the California Supreme Court. On July 15, 1998, the
California Supreme Court denied the CARES petition. In these rulings, the Court
of Appeal of the State of California and the California Supreme Court both
decided, in effect, not to consider the legality and constitutionality of
Proposition 9 prior to the November 1998 election.
If Proposition 9 is voted into law, further litigation would ensue. 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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property right authorized by the Statute
and the financing order by legislative enactment, voter initiative or
constitutional amendment that would be adverse to holders of the rate reduction
notes. The costs of such actions would be payable out of collections of the
non-bypassable charges established by the financing order and the related
issuance advice letter as an operating expense related to the rate reduction
notes. However, SCE may be required to advance its own funds to satisfy its
obligations as servicer to take such legal and administrative actions.
9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE is unable to predict the outcome of this matter, but if Proposition 9 were
to be 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
operation and financial position. Upon voter approval of Proposition 9, a
write-down of a portion of SCE's generation-related assets might be required
under applicable accounting principles, depending on SCE's assessment of both
the probability that Proposition 9 would be struck down by the courts and the
manner in which it would be interpreted and applied to SCE. The meaning of many
provisions of Proposition 9 is unclear and, if the courts uphold it in whole or
part, will be subject to judicial and regulatory interpretation. Depending on
how Proposition 9 is interpreted and implemented with respect to SCE, the
potential write-down of SCE's generation-related assets could amount to as much
as $1.9 billion after tax.
Additionally, if Proposition 9 passes and survives legal challenges, SCE could
suffer impacts on its annual earnings, including the possibility of being
required to offset customer charges necessary to pay the principal and interest
on the rate reduction notes. Depending on how this provision and other
provisions of Proposition 9 are interpreted and applied, the annual earnings
reductions could be as large as $210 million in 1999, gradually declining to as
much as $10 million in 2007, and immaterial amounts thereafter.
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 51
identified sites (50 at SCE and one at EME) is $178 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 $246
million. The upper limit of this range of costs was estimated using assumptions
least favorable to Edison International among a range of reasonably possible
outcomes. SCE has sold all of its gas- and oil-fueled power 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 $91 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
10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $148 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is
a lack of currently available information, including the nature and magnitude of
contamination and the extent, if any, that Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $4 million to $10 million.
Based on currently available information, Edison International believes it is
unlikely that it will incur amounts in excess of the upper limit of the
estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs ultimately
recorded will not materially affect its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of
new sites, will not require material revisions to such estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from
this secondary level, effective June 1994. The maximum deferred premium for each
nuclear incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its ownership
interests, SCE could be required to pay a maximum of $158 million per nuclear
incident. However, it would have to pay no more than $20 million per incident in
any one year. Such amounts include a 5% surcharge if additional funds are needed
to satisfy public liability claims and are subject to adjustment for inflation.
If the public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million has also been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued primarily by mutual insurance companies
owned by utilities with nuclear facilities. If losses at any nuclear facility
covered by the arrangement were to exceed the accumulated funds for these
insurance programs, SCE could be assessed retrospective premium adjustments of
up to $28 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 six months
ended June 30, 1998, were 40(cent) and 79(cent), respectively, compared with
34(cent) and 69(cent) for the same periods in 1997. Southern California Edison
Company's (SCE) earnings for the three and six months ended June 30, 1998, were
31(cent) and 58(cent), respectively, 1(cent) more than each of the year-earlier
periods, primarily due to the operating performance at the San Onofre Nuclear
Generating Station and Edison International's share repurchase program more than
offsetting SCE's lower authorized revenue. The lower authorized revenue was
driven by reduced authorized returns on generating assets and a lower earning
asset base resulting from 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 six months
ended June 30, 1998, of 12(cent) and 27(cent), respectively, up 5(cent) and
11(cent) from the year-earlier periods. The increases were primarily due to
earnings generated by Edison Capital's cross-border lease transactions in the
Netherlands, South Australia and South Africa. The year-to-date increase also
reflects earnings contributed by EME's investment in First Hydro, which
benefited from higher energy prices in the United Kingdom. Edison Enterprises
and the parent company were responsible for the following negative income
effects: 3(cent) per share for the second quarter of 1998 and 6(cent) for the
first half of 1998, compared to 3(cent) and 4(cent) for the same periods in
1997, primarily due to continued start-up costs at Edison Enterprises (Edison
International's new retail businesses:
Edison Source, Edison EV, 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 -- PX and
ISO." Excluding the sales to the PX, electric utility revenue decreased 12% and
8%, respectively, for the three and six months ended June 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 also
includes a decrease in sales volume due to milder weather in second 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 decreased slightly for both the three and
six months ended June 30, 1998, compared to the same periods in 1997, primarily
due to a new series of power-sales-related contracts associated with EME's
acquisition of the remaining 49% of Loy Yang B in May 1997. The year-to-date
decrease was partially offset by increased revenue related to higher energy
sales at EME's First Hydro project.
Operating Expenses
Fuel expense decreased 48% and 32%, respectively, for the three and six months
ended June 30, 1998, compared to the same periods in 1997. The quarterly and
year-to-date decreases resulted from the sale of SCE's gas- and oil-fueled
plants. In addition, the year-to-date decrease also reflects significantly lower
gas prices at SCE in the first quarter of 1998, as well as a decrease at EME due
to the new fuel supply agreement entered into by Loy Yang B, partially offset by
an increase at First Hydro as a result of higher prices and increased generation
in 1998.
12
Since April 1, 1998, SCE is required to purchase all of its power from the PX
for distribution to its customers. The new competitive market has caused SCE to
only make federally required purchases or purchases required under long-term
contracts and to discontinue making economy power purchases. Excluding the power
purchased from the PX, purchased-power expense decreased 11% and 9%,
respectively, for the three and six months ended June 30, 1998, compared to the
year-earlier periods. The decreases are the result of SCE discontinuing economy
purchases. SCE is required under federal law to purchase power from certain
nonutility generators even though energy prices under these contracts are
generally higher than other sources. For the twelve months ended June 30, 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 increased substantially for the
quarter and six months ended June 30, 1998, compared to the same periods in
1997, primarily due to overcollections in the transition cost balancing account
reflecting the gain on sales of the gas- and oil-fueled plants in second quarter
1998. The overcollections were partially offset by undercollections related to
direct access activities, the delay in the start-up of the PX and independent
system operator (ISO) and the issuance of the rate reduction notes in December
1997. Beginning in January 1998, the difference between generation-related
revenue and generation-related costs is being accumulated in the transition cost
balancing account, effectively eliminating all other balancing accounts except
those used in the administration of public-purpose funds.
Other operating expenses increased for the three and six months ended June 30,
1998, compared to the same periods in 1997, primarily due to SCE's direct access
activities, must-run reliability services and PX and ISO activities. The
year-to-date increase also reflects storm damage expense at SCE resulting from a
harsher winter in 1998, as well as continued start-up expenses at Edison
Enterprises.
Maintenance expense decreased 16% for the quarter ended June 30, 1998, compared
to the year-earlier period, reflecting the extended refueling outages at San
Onofre during the second quarter of 1997.
Depreciation, decommissioning and amortization expense increased 18% and 19%,
respectively, for the quarter and six months ended June 30, 1998, compared to
the same periods in 1997. The increases are primarily due to the accelerated
recovery of the gas- and oil-fueled generation plants and the further
acceleration of the San Onofre and Palo Verde Nuclear Generating Station units.
The accelerated recoveries implemented in 1998 are part of the competition
transition charge (CTC) mechanism (see further discussion under "California
Electric Utility Industry Restructuring"). The increases were partially offset
by a decrease at EME related to an extension in the useful life of Loy Yang B's
plant and equipment, from approximately 30 years, the term of the previous
power-purchase agreement, to 50 years, the projected economic life of the plant.
Income taxes decreased 13% and increased 12%, respectively, for the three and
six months ended June 30, 1998, compared to the same periods in 1997. The
quarterly decrease is primarily due to lower pre-tax income at SCE, partially
offset by higher pre-tax income at Edison Capital. The year-to-date increase is
mostly due to higher pre-tax income for the first quarter of 1998, as well as
additional amortization related to the CTC mechanism. The additional
amortization related to the CTC mechanism will continue to cause an increase in
the effective tax rate. Also, Edison Capital had increased income tax expense
related to revenue generated by its cross-border lease transactions.
Gains on sale of utility plant are from the sale of 11 of SCE's 12 gas- and
oil-fueled generation plants in the first half of 1998.
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.
13
Interest and dividend income increased 31% and 59%, respectively, for the three
and six months ended June 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. The year-to-date increase also reflects interest
earned on higher balancing account undercollections in the first quarter of
1998.
Minority interest decreased due to EME's May 1997 acquisition of the remaining
49% ownership interest in the Loy Yang B project.
Other nonoperating income decreased 33% and 88%, respectively, for the second
quarter and first half of 1998, compared to the same periods in 1997. The
decreases are due to additional accruals at SCE for regulatory matters
associated with the restructuring of California's electric utility industry. The
quarterly decrease also reflects the absence of second quarter 1997 income at
EME related to a gain on sale of their ownership interest in BC Star Partners,
partially offset by the extinguishment of Loy Yang B debt.
Interest and Other Expenses
Interest on long-term debt increased for the six months ended June 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, partially offset by
lower expenses at EME due to lower principal balances on outstanding debt.
Interest on the rate reduction notes was $38 million and $77 million,
respectively, for the second quarter and first half of 1998.
Other interest expense decreased 19% and 26%, respectively, for the three and
six months ended June 30, 1998, compared to the same periods in 1997. The
decreases are primarily due to lower levels of short-term debt at June 30, 1998,
versus June 30, 1997. In addition, the year-to-date decrease reflects a
reduction in SCE's balancing account interest expense as a result of higher
undercollections in the first quarter of 1998.
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 95.3 million shares
($2.3 billion) between January 1995 and August 5, 1998, funded by dividends from
its subsidiaries and the issuance of rate reduction notes.
Edison International's cash flow coverage of dividends for the six months ended
June 30, 1998, was 4.0 times, compared to 4.8 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 11 gas- and oil-fueled generation plants. Edison
International's dividend payout ratio for the twelve-month period ended June 30,
1998, was 55%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $752 million for the six-month
period ended June 30, 1998, compared with $1.0 billion in 1997. Cash from
operations exceeded capital requirements for both periods presented.
Cash Flows from Financing Activities
At June 30, 1998, Edison International and its subsidiaries had $2.2 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
14
variable-rate pollution-control bonds. The parent company had total lines of
credit of $500 million, with $489 million available. The nonutility companies
had total lines of credit of $800 million, with $452 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; the
majority have five-year terms.
SCE's short-term debt is used to finance fuel inventories, balancing account
undercollections 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 June 30, 1998, SCE could issue
approximately $12.0 billion of additional first and refunding mortgage bonds and
$4.4 billion of preferred stock at current interest and dividend rates.
EME has firm commitments of $281 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 $203 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 June 30, 1998, SCE
had the capacity to pay $1.1 billion in additional dividends and continue to
maintain its authorized capital structure. These restrictions are not expected
to affect Edison International's ability to meet its cash obligations.
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
15
certificates and the secondary market for the certificates, including the
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 Proposition 9 -- November 1998 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 Divestiture),
and funding of nuclear decommissioning trusts. Decommissioning costs are accrued
and recovered in rates over the term of each nuclear generating facility's
operating license through charges to depreciation expense. SCE estimates that it
will spend approximately $12.7 billion between 2013 --2070 to decommission its
nuclear facilities. This estimate is based on SCE's current-dollar
decommissioning costs ($2.1 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 until
decommissioning begins. 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 $423 million
for the six-month period ended June 30, 1998, compared to $401 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.
SCE has hedged a portion of its exposure to increases in natural gas prices.
Increases in natural gas prices tend to increase the price of electricity
purchased from the PX. SCE's exposure is also limited by regulatory mechanisms
that protect SCE from much of the risk arising from high electricity prices.
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 $12 million in
the six months ended June 30, 1998, compared to $7 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 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 $29 million for the six months ended
16
June 30, 1998, compared to an increase of $20 million for the same period in
1997, as a result of electricity rate swap agreements. The structure of the
forward-contracts market and the pool is currently under review by the Director
General of Electricity Supply, at the request of the Minister for Science,
Energy and Industry in the United Kingdom, and a report is expected in the third
quarter of 1998.
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 $41 million for the six months ended June 30,
1998, 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 93% 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. 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. A
presidential decree has deemed some power plants, but not including the Paiton
project, subject to review, postponement or cancellation. EME continues to
monitor the situation closely.
Projected Capital Requirements
Edison International's projected construction expenditures for the next five
years are: 1998 -- $867 million; 1999 -- $729 million; 2000 -- $685 million;
2001 -- $684 million; and 2002 -- $656 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 1998, are: 1999 -- $769 million; 2000 --
$991 million; 2001 -- $1.2 billion; 2002 -- $341 million; and 2003 -- $698
million.
17
Preferred stock redemption requirements for the five twelve-month periods
following June 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 without access charges. 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 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 enables 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.
18
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 Utilities Reform Network
recommended a combined total disallowance of $37 million. A CPUC decision is
expected in third quarter 1998. In third 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 the date of divestiture.
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 Proposition 9 -- November 1998 Voter Initiative."
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. A
voter initiative on the November 1998 ballot 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. For
further details, see the discussion in "Cash Flows from Financing Activities."
19
Rate-setting -- 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. 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.
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 July 1, 1998, approximately 47,000 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 determining whether any credit
should be provided by the utility to customers who elect to have ESPs provide
them with revenue cycle services, and the amount of any such credit, the CPUC
has indicated that it is appropriate to provide such customers with the
utility's avoided costs net of costs incurred by the utility to facilitate the
provision of such services by a firm other than the utility. The unbundling of
revenue cycle services will expose SCE to the possible loss of revenue and a
reduction in revenue security.
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.
20
The CPUC is considering unbundling SCE's cost of capital based on major utility
function. On May 8, 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 all 12 of its gas- and oil-fueled generation plants. Transfer of
ownership of 11 plants was completed by June 30, 1998, and transfer of ownership
of the 12th plant took place on July 8, 1998. 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.
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 a consensus reached by the
Financial Accounting Standards Board's Emerging Issues Task Force (EITF). The
financial reporting effect of this discontinuance was to segregate these assets
on the balance sheet; the EITF consensus did not require SCE to write off any of
its generation-related assets, including related
21
regulatory assets. However, the EITF 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 consensus reached by the EITF also permits the recording of
new generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.
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 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
generation-related regulatory assets no longer probable, SCE would be required
to write off the remaining balance of such assets (approximately $2.4 billion,
after tax, at June 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 Proposition 9 -- November 1998 Voter Initiative
In November 1997, individuals representing The Utilities Reform Network, Public
Media Center and the Coalition Against Utility Taxes filed a proposed voter
initiative that seeks to overturn major portions of the electric industry
restructuring legislation enacted in California in September 1996 (Statute). The
voter initiative proposes, among other things, to: (i) impose an additional 10%
rate reduction for residential and small commercial customers beyond the 10%
reduction that went into effect on January 1, 1998; (ii) block stranded-cost
recovery of nuclear investments; (iii) restrict stranded-cost recovery of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the opportunity to earn a fair rate of return; and (iv) prohibit the
collection of any charges in connection with a financing order for the purpose
of making payments on rate reduction notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.
On June 24, 1998, the California Secretary of State announced that the proposed
voter initiative qualified for the November 1998 ballot. On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.
On May 22, 1998, Californians for Affordable and Reliable Electric Service
(CARES), a coalition of California business organizations and utilities, filed a
petition for writ of mandate with the Court of Appeal of the State of
California. CARES is sponsored by the California Business Roundtable, the
California Chamber of Commerce, San Diego Gas & Electric Company, the California
Manufacturers Association, Pacific Gas & Electric Company, the California
Retailers Association, and SCE, among other groups. The CARES petition
challenged Proposition 9 as illegal and unconstitutional on its face, and sought
to remove the initiative from the November 1998 ballot. On July 2, 1998, the
Court of Appeal denied the CARES petition. On July 6, 1998, CARES filed its
appeal of the denial with the California Supreme Court. On July 15, 1998, the
California Supreme Court denied the CARES petition. In these rulings, the Court
of Appeal of the State of California and the California Supreme Court both
decided, in effect, not to consider the legality and constitutionality of
Proposition 9 prior to the November 1998 election.
22
If Proposition 9 is voted into law, further litigation would ensue. 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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property right authorized by the Statute
and the financing order by legislative enactment, voter initiative or
constitutional amendment that would be adverse to holders of the rate reduction
notes. The costs of such actions would be payable out of collections of the
non-bypassable charges established by the financing order and the related
issuance advice letter as an operating expense related to the rate reduction
notes. However, SCE may be required to advance its own funds to satisfy its
obligations as servicer to take such legal and administrative actions.
SCE is unable to predict the outcome of this matter, but if Proposition 9 were
to be 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
operation and financial position. Upon voter approval of Proposition 9, a
write-down of a portion of SCE's generation-related assets might be required
under applicable accounting principles, depending on SCE's assessment of both
the probability that Proposition 9 would be struck down by the courts and the
manner in which it would be interpreted and applied to SCE. The meaning of many
provisions of Proposition 9 is unclear and, if the courts uphold it in whole or
part, will be subject to judicial and regulatory interpretation. Depending on
how Proposition 9 is interpreted and implemented with respect to SCE, the
potential write-down of SCE's generation-related assets could amount to as much
as $1.9 billion after tax.
Additionally, if Proposition 9 passes and survives legal challenges, SCE could
suffer impacts on its annual earnings, including the possibility of being
required to offset customer charges necessary to pay the principal and interest
on the rate reduction notes. Depending on how this provision and other
provisions of Proposition 9 are interpreted and applied, the annual earnings
reductions could be as large as $210 million in 1999, gradually declining to as
much as $10 million in 2007, and immaterial amounts thereafter.
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 51
identified sites is $178 million. One of SCE's sites, a former pole-treating
facility, is considered a federal Superfund site and represents 41% 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 $246 million. The upper limit of
this range of costs was estimated using assumptions least favorable to Edison
International among a range of reasonably possible outcomes. SCE has sold all of
its gas- and oil-fueled power 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 $91 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 $148 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer
rates.
23
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.
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
24
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.
Accounting Rules
During 1996, the Financial Accounting Standards Board issued an exposure draft
that would establish accounting standards for the recognition and measurement of
closure and removal obligations. The exposure draft would require the estimated
present value of an obligation to be recorded as a liability, along with a
corresponding increase in the plant or regulatory asset accounts when the
obligation is incurred. If the exposure draft is approved in its present form,
it would affect SCE's accounting practices for the decommissioning of its
nuclear power plants, obligations for coal mine reclamation costs and any other
activities related to the closure or removal of long-lived assets. SCE does not
expect that the accounting changes proposed in the exposure draft would have an
adverse effect on its results of operations even after deregulation due to its
current and expected future ability to recover these costs through customer
rates. The nonutility subsidiaries are currently reviewing what impact the
exposure draft may have on their results of operations and financial position.
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 identify a year by
using only two digits instead of four. If not corrected, these programs could
fail or create erroneous results beginning in 2000. This situation has been
referred to generally as the Year 2000 Issue.
SCE has a comprehensive program in place to remediate potential Year 2000
impacts. SCE divides its Year 2000 Issue activities into five phases: inventory,
impact assessment, remediation, testing and implementation. SCE's plan for
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. SCE is on
25
schedule to have its mainframe and distributed computing assets Year 2000-ready
within the timeframe discussed above. The physical asset portfolio includes
systems in the generation, transmission, distribution, telecommunications and
facilities areas. SCE has completed its inventory of these systems and impact
assessment for critical physical assets is nearly complete.
The other essential component of the SCE Year 2000 readiness program is to
identify and assess vendor products and business partners for 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.
Preliminary estimates of the costs to complete these modifications, including
the cost of new hardware and software application modification, range from $55
million to $80 million, about half of which are expected to be capital costs.
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 remediated
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 Year 2000-related processing failures or
malfunctions due to SCE's internal systems or from external parties. 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 the beginning of 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 Report
on Form 10-Q for the quarter ended March 31, 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.
Edison Mission Energy
PMNC Litigation
As previously reported in Part II, Item 1 of the Registrant's Quarterly Report
on Form 10-Q for the quarter ended March 31, 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 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 Report
on Form 10-Q for the quarter ended March 31, 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 ("Los Angeles County") and one was
filed in Kern County Superior Court ("Kern County"). 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 the proper interpretation of the
contracts. Plaintiffs alleged a combined total of approximately $189 million in
damages, 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.
27
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.
Geothermal Generators' Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Report
on Form 10-Q for the quarter ended March 31, 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
(collectively the "Coso Defendants"). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso Defendants routinely vented highly toxic
hydrogen sulfide gas from unmonitored release points beginning in 1990 and
continuing through at least 1994, in violation of applicable federal, state and
local environmental law. According to SCE, these violations constituted material
breaches by the Coso Defendants of their obligations under their contracts and
applicable law. The complaint sought termination of the contracts and damages
for excess power purchase payments made to the Coso Defendants. The Coso
Defendants' motion to transfer venue to Inyo County Superior Court was granted
on August 31, 1997.
On December 19, 1997, SCE filed a first amended complaint in response to which
the Coso Defendants filed a motion to strike the termination remedy sought by
SCE. This motion was granted on June 1, 1998. The Coso Defendants also filed a
motion for summary judgment, asserting that SCE's claims are time-barred or were
released in connection with the settlement of prior litigation among some of the
Coso Defendants and two of SCE's affiliates, Mission Power Engineering, and The
Mission Group (the Mission Parties). The court denied the Coso Defendants'
motion for summary judgment by order dated July 8, 1998. In addition, the Coso
Defendants filed a motion to stay SCE's case pending resolution of certain
technical issues by the Great Basin Air Quality Management District under the
doctrine of primary adjudication. On April 30, 1998, the court denied the motion
for stay without prejudice.
The Coso Defendants have also asserted various claims against SCE and the
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 Defendants
in Inyo County Superior Court. Following a hearing on November 20, 1997, the
court consolidated these actions for all purposes and ordered the Coso
Defendants to file a second amended cross-complaint, incorporating all but two
of the claims in the separate complaint.
The second amended cross-complaint asserts nineteen causes of action against
SCE, three of which are also asserted against the Mission Parties, and alleges
in excess of $115 million in compensatory damages and also punitive damages.
Several of these claims are premised on the theory that SCE has incorrectly
interpreted the cross-complainants' contracts as providing for only a single
"fixed price" period in view of the fact that the cross-complainants developed
their projects in phases. This theory has also been asserted by other
independent power producers in litigation pending in Los Angeles Superior Court.
(See "Wind Generators Litigation" above.) SCE filed a demurrer to, as well as a
motion to strike, certain portions of the second amended cross-complaint which
was argued on March 13, 1998. On May 22, 1998, the court granted SCE's motion to
strike and sustained the demurrer with leave to amend. The Coso Defendants
subsequently filed a motion for leave to file a third amended cross-complaint
which was argued and taken under submission on July 9, 1998.
28
Electric and Magnetic Fields (EMF) Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Report
on Form 10-Q for the quarter ended March 31, 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.
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 and has been served on SCE.
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 &
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 cases 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 Report
on Form 10-Q for the quarter ended March 31, 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 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. The
impact on SCE, if any, from further proceedings in this case against the
remaining defendants cannot be determined at this time.
On July 5, 1995, a former SCE reactor operator and his wife sued SCE and SDG&E
in the U.S. District Court for the Southern District of California 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. The impact on SCE, if any, from further proceedings in
this case against the remaining defendants cannot be determined at this time.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District Court for the Southern
District of California 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, recently 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
29
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 late 1998 or early 1999.
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.
False Claims Act Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Report
on Form 10-Q for the quarter ended March 31, 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.
Mohave Generating Station Environmental Litigation
As previously reported in Part II, Item 1 of the Registrant's quarterly Report
on Form 10-Q for the quarter ended March 31, 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 fall.
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 that may be added to the ongoing litigation after
August 3, 1998. The new causes of action are expected to be a variation of the
existing allegations, and are not expected to raise new substantive issues. The
supplemental notice also stated the intent to add the National Parks and
Conservation Association as an additional plaintiff to these proceedings.
However, it is not expected that this will substantially change the timetable
for the court's initial ruling on all the pending motions.
30
California Proposition 9 Litigation
In November 1997, individuals representing The Utilities Reform Network, Public
Media Center and the Coalition Against Utility Taxes filed a proposed voter
initiative that seeks to overturn major portions of the electric industry
restructuring legislation enacted in California in September 1996 ("Statute").
The voter initiative proposes, among other things, to: (i) impose an additional
10% rate reduction for residential and small commercial customers beyond the 10%
reduction that went into effect on January 1, 1998; (ii) block stranded-cost
recovery of nuclear investments; (iii) restrict stranded-cost recovery of
non-nuclear investments unless the CPUC finds that the utility would be deprived
of the opportunity to earn a fair rate of return; and (iv) prohibit the
collection of any charges in connection with a financing order for the purpose
of making payments on rate reduction notes, or if the financing order is found
enforceable by a court, require the utility to offset such charges with an equal
credit to customers.
On June 24, 1998, the California Secretary of State announced that the proposed
voter initiative qualified for the November 1998 ballot. On July 17, 1998, the
Secretary of State designated the initiative as Proposition 9 on the ballot.
On May 22, 1998, Californians for Affordable and Reliable Electric Service
(CARES), a coalition of California business organizations and utilities
(sponsored by the California Business Roundtable, the California Chamber of
Commerce, San Diego Gas & Electric Company, the California Manufacturers
Association, Pacific Gas & Electric Company, the California Retailers
Association, and SCE, among other groups) filed a petition for writ of mandate
with the Court of Appeal of the State of California. The CARES petition
challenged the voter initiative (later designated as Proposition 9) as illegal
and unconstitutional on its face, and sought to remove the initiative from the
November 1998 ballot. On July 2, 1998, the Court of Appeal denied the CARES
petition. On July 6, 1998, CARES filed its appeal of the denial with the
California Supreme Court. On July 15, 1998, the California Supreme Court denied
the CARES petition for pre-election review. In these rulings, the Court of
Appeal of the State of California and the California Supreme Court both decided,
in effect, not to consider the legality and constitutionality of Proposition 9
prior to the November 1998 election.
If Proposition 9 is voted into law, further litigation would ensue. 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 Statute, the financing order issued by the
CPUC, or the rights of holders of the property right authorized by the Statute
and the financing order by legislative enactment, voter initiative or
constitutional amendment that would be adverse to holders of the rate reduction
notes. The costs of such actions would be payable out of collections of the
non-bypassable charges established by the financing order and the related
issuance advice letter as an operating expense related to the rate reduction
notes. However, SCE may be required to advance its own funds to satisfy its
obligations as servicer to take such legal and administrative actions.
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 operation
and financial position as more specifically described in California Proposition
9 -- November 1998 Voter Initiative in Item 2 of Part 1 of this Form, which is
hereby incorporated by reference.
31
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
January 1, 1998 (File No. 1-9936, Form 10-K for the year
ended December 31, 1997)*
10. Material Contracts
10.1. Equity Compensation Plan
10.2. Retirement Plan for Directors
10.3. Director Deferred Compensation Plan
10.4. Form of Agreement for 1998 Employee Awards under
the Equity Compensation Plan
10.5. Form of 1998 Director Award under the Equity
Compensation Plan
11. Computation of Primary and Fully Diluted Earnings Per Share
27. Financial Data Schedule
32
(b) Reports on Form 8-K:
None
- ----------------------
* Incorporated by reference pursuant to Rule 12b-32 .
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 RICHARD K. BUSHEY
-------------------------------------------
RICHARD K. BUSHEY
Vice President and Controller
By K. S. STEWART
-------------------------------------------
K. S. STEWART
Assistant General Counsel and
Assistant Secretary
August 13, 1998