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, 1999
-----------------------------------------------
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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No ___
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:
Class Outstanding at August 9, 1999
- ----------------------------------------- --------------------------------
Common Stock, no par value 347,207,106
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, 1999, and 1998 1
Consolidated Statements of Comprehensive Income --
Three and Six Months Ended June 30, 1999, and 1998 1
Consolidated Balance Sheets -- June 30, 1999,
and December 31, 1998 2
Consolidated Statements of Cash Flows -- Six Months
Ended June 30, 1999, and 1998 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 9
Part II. Other Information:
Item 1. Legal Proceedings 24
Item 6. Exhibits and Reports on Form 8-K 27
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,
- -----------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility revenue $1,720,820 $1,618,782 $3,397,476 $3,241,471
Diversified operations 395,194 320,253 806,257 607,124
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,116,014 1,939,035 4,203,733 3,848,595
- -----------------------------------------------------------------------------------------------------------------------
Fuel 118,694 100,259 233,077 267,580
Purchased power -- contracts 422,754 525,355 1,032,660 1,101,862
Purchased power -- power exchange-- net 97,143 40,099 214,100 40,099
Provisions for regulatory adjustment clauses-- net (81,718) 462,176 (360,748) 158,363
Other operating expenses 616,362 562,533 1,193,124 949,702
Maintenance 106,243 98,597 195,188 200,566
Depreciation, decommissioning and amortization 429,171 404,031 852,808 815,354
Income taxes 67,278 99,010 152,807 235,728
Property and other taxes 29,609 33,194 68,701 73,955
Net gain on sale of utility plant (724) (684,838) (2,925) (619,038)
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,804,812 1,640,416 3,578,792 3,224,171
- -----------------------------------------------------------------------------------------------------------------------
Operating income 311,202 298,619 624,941 624,424
- -----------------------------------------------------------------------------------------------------------------------
Allowance for equity funds used during construction 3,056 2,908 5,892 5,690
Interest and dividend income 22,594 25,078 42,964 55,794
Minority interest (1,046) (859) (2,008) (2,367)
Other nonoperating income (deductions)-- net 7,338 (9,107) (1,247) (18,308)
- -----------------------------------------------------------------------------------------------------------------------
Total other income-- net 31,942 18,020 45,601 40,809
- -----------------------------------------------------------------------------------------------------------------------
Income before interest and other expenses 343,144 316,639 670,542 665,233
- -----------------------------------------------------------------------------------------------------------------------
Interest and amortization on long-term debt 169,534 147,505 321,353 326,617
Other interest expense 45,178 20,319 81,293 41,531
Allowance for borrowed funds used during
construction (2,652) (1,979) (5,113) (3,871)
Capitalized interest (7,092) (4,461) (17,810) (8,365)
Dividends on subsidiary preferred securities 9,754 9,952 19,186 20,008
- -----------------------------------------------------------------------------------------------------------------------
Total interest and other expenses-- net 214,722 171,336 398,909 375,920
- -----------------------------------------------------------------------------------------------------------------------
Net income $ 128,422 $ 145,303 $ 271,633 $ 289,313
- -----------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock
outstanding 347,204 360,251 347,846 365,150
Basic earnings per share $.37 $.40 $.78 $.79
Diluted earnings per share $.37 $.40 $.78 $.79
Dividends declared per common share $.27 $.26 $.54 $.52
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
3 Months Ended 6 Months Ended
June 30, June 30,
- -----------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $128,422 $145,303 $271,633 $289,313
Cumulative translation adjustments-- net (29,076) (7,585) (41,714) 733
Unrealized gain (loss) on securities-- net (1,876) 1,384 (11,022) 15,398
Reclassification adjustment for gains included
in net income (14,874) -- (32,245) --
- -----------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 82,596 $139,102 $186,652 $305,444
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
June 30, December 31,
1999 1998
- ------------------------------------------------------------------------------------------------------------------
ASSETS (Unaudited)
Utility plant, at original cost:
Transmission and distribution $11,975,779 $11,771,678
Generation 1,705,009 1,689,469
Accumulated provision for depreciation
and decommissioning (7,175,966) (6,896,479)
Construction work in progress 654,516 516,664
Nuclear fuel, at amortized cost 163,281 172,250
- ------------------------------------------------------------------------------------------------------------------
Total utility plant 7,322,619 7,253,582
- ------------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision for
depreciation of $334,443 and $296,732 at respective dates 4,931,953 3,072,354
Nuclear decommissioning trusts 2,357,155 2,239,929
Investments in partnerships and unconsolidated subsidiaries 2,379,100 1,615,106
Investments in leveraged leases 1,733,086 1,621,133
Other investments 215,315 572,856
- ------------------------------------------------------------------------------------------------------------------
Total other property and investments 11,616,609 9,121,378
- ------------------------------------------------------------------------------------------------------------------
Cash and equivalents 937,929 583,556
Receivables, including unbilled revenue, less allowances of
$27,371 and $24,272 for uncollectible accounts at respective dates 1,353,070 1,315,830
Fuel inventory 74,570 51,299
Materials and supplies, at average cost 165,387 116,259
Accumulated deferred income taxes-- net 92,798 274,851
Regulatory balancing accounts-- net 1,103,765 648,781
Prepayments and other current assets 43,140 137,920
- ------------------------------------------------------------------------------------------------------------------
Total current assets 3,770,659 3,128,496
- ------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net 1,763,390 2,161,998
Income tax-related deferred charges 1,440,617 1,463,256
Unamortized debt issuance and reacquisition expense 343,126 348,816
Other deferred charges 1,703,194 1,220,353
- ------------------------------------------------------------------------------------------------------------------
Total deferred charges 5,250,327 5,194,423
- ------------------------------------------------------------------------------------------------------------------
Total assets $27,960,214 $24,697,879
- ------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
June 30, December 31,
1999 1998
- ------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES (Unaudited)
Common shareholders' equity:
Common stock (347,207,106 and 350,553,197
shares outstanding at respective dates) $2,089,206 $ 2,109,279
Accumulated other comprehensive income:
Cumulative translation adjustments-- net (12,015) 29,699
Unrealized gain in equity securities-- net 10,592 53,859
Retained earnings 2,916,285 2,906,432
- ------------------------------------------------------------------------------------------------------------------
5,004,068 5,099,269
- ------------------------------------------------------------------------------------------------------------------
Preferred securities of subsidiaries:
Not subject to mandatory redemption 246,858 128,755
Subject to mandatory redemption 489,732 405,700
Long-term debt 9,624,194 8,008,154
- ------------------------------------------------------------------------------------------------------------------
Total capitalization 15,364,852 13,641,878
- ------------------------------------------------------------------------------------------------------------------
Other long-term liabilities 742,298 467,109
- ------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt 931,861 920,333
Short-term debt 1,581,919 565,626
Accounts payable 413,474 489,751
Accrued taxes 470,456 629,906
Accrued interest 183,383 146,773
Dividends payable 94,406 91,742
Deferred unbilled revenue and other current liabilities 1,734,469 1,442,149
- ------------------------------------------------------------------------------------------------------------------
Total current liabilities 5,409,968 4,286,280
- ------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 4,651,925 4,591,236
Accumulated deferred investment tax credits 248,601 270,689
Customer advances and other deferred credits 1,523,812 1,424,986
- ------------------------------------------------------------------------------------------------------------------
Total deferred credits 6,424,338 6,286,911
- ------------------------------------------------------------------------------------------------------------------
Minority interest 18,758 15,701
- ------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 1 and 2)
Total capitalization and liabilities $27,960,214 $24,697,879
- ------------------------------------------------------------------------------------------------------------------
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,
- -------------------------------------------------------------------------------------------------------------------
1999 1998
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 271,633 $ 289,313
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 852,808 815,354
Other amortization 43,195 41,294
Deferred income taxes and investment tax credits 231,562 4,802
Equity in income from partnerships and unconsolidated
subsidiaries (105,867) (62,727)
Income from leveraged leases (112,618) (91,579)
Other long-term liabilities 81,311 16,066
Regulatory asset related to the sale of oil and gas plant 241 (107,991)
Net gain on sale of oil and gas plant (1,110) (640,339)
Other-- net (17,287) (19,214)
Changes in working capital:
Receivables 26,321 (123,278)
Regulatory balancing accounts (454,984) 143,077
Fuel inventory, materials and supplies (1,596) 23,396
Prepayments and other current assets 70,791 62,503
Accrued interest and taxes (92,223) 178,041
Accounts payable and other current liabilities 94,058 153,165
Distributions from partnerships and unconsolidated subsidiaries 57,276 70,453
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 943,511 752,336
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 2,167,054 716,441
Long-term debt repaid (406,693) (873,737)
Common stock repurchased (92,023) (586,297)
Preferred securities issued 202,212 --
Preferred securities redeemed -- (73,300)
Rate reduction notes repaid (119,760) (82,465)
Nuclear fuel financing-- net (9,016) (18,871)
Short-term debt financing-- net 1,017,893 (190,052)
Dividends paid (185,258) (189,505)
Other-- net 87 367
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 2,574,496 (1,297,419)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (569,771) (398,277)
Purchase of nonutility power station (1,800,355) --
Proceeds from sale of assets 20,975 1,149,139
Funding of nuclear decommissioning trusts (66,424) (76,881)
Investments in partnerships and unconsolidated subsidiaries (716,243) (53,636)
Unrealized gain (loss) on securities-- net (43,267) 15,398
Investments in leveraged leases 466 (336,637)
Other-- net 10,985 (4,668)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by investing activities (3,163,634) 294,438
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents 354,373 (250,645)
Cash and equivalents, beginning of period 583,556 1,906,505
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 937,929 $ 1,655,860
- -------------------------------------------------------------------------------------------------------------------
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 1998 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 1998 Annual Report and Form 10-K filed with the Securities and
Exchange Commission.
Certain prior-period amounts were reclassified to conform to the June 30, 1999,
financial statement presentation.
Since April 1, 1998, when the new market structure began, Southern California
Edison Company (SCE) has been selling all of its generation through the power
exchange (PX), as mandated by the California Public Utilities Commission's
(CPUC) 1995 restructuring decision. Through the PX, SCE satisfies the electric
energy needs of customers who did not choose an alternative energy provider.
These transactions with the PX are reported as Purchased power - power exchange
- - net. Generation sales through the PX were $360 million and $642 million for
the three and six months ended June 30, 1999, respectively and $304 million for
each of the same periods ended June 30, 1998. Purchases from the PX were $457
million and $856 million for the three and six months ended June 30, 1999,
respectively and $344 million for each of the same periods ended June 30, 1998.
Note 1. Regulatory Matters
Federal Energy Regulatory Commission Transmission Rate Case
SCE filed its first Federal Energy Regulatory Commission (FERC) transmission
rate case in March 1997. The filing proposed a transmission revenue requirement
of $211 million. In March 1999, a proposed FERC decision was issued recommending
a return on equity of 9.68% (compared to SCE's current CPUC rate for
distribution of 11.6%) and a lower revenue requirement. SCE filed briefs
opposing the proposed decision in May 1999. A final FERC decision is expected
late 1999. SCE does not expect the final decision to have a material effect on
its results of operations or financial position.
Recovery of Restructuring Implementation Costs
The independent system operator (ISO) assumed operational control of the
transmission system after the ISO and PX began accepting bids and schedules for
electricity purchases on March 31, 1998. The restructuring implementation costs
related to the start-up and development of the PX, which were paid by the
utilities, were to 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. In May 1998, SCE filed an
application with the CPUC to identify the categories of such costs (including
costs related to the implementation of direct access), and to establish the
reasonableness of those costs incurred in 1997.
Two proposed decisions issued in March 1999 rejected SCE's request for a
determination of eligibility for several major categories of such costs. In May
1999, SCE, the CPUC's Office of Ratepayer Advocates and several other parties
entered into a settlement agreement that would allow SCE to recover
substantially all (approximately $319 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
5
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation. The CPUC has withdrawn its earlier proposed decisions
on SCE's application. On July 6, 1999, a proposed decision was issued that would
approve the settlement in its entirety. A final CPUC decision on the settlement
is expected in third quarter 1999.
Note 2. Contingencies
In addition to the matters disclosed in these notes, Edison International is
involved in legal, tax, and regulatory proceedings before various courts and
governmental agencies regarding matters arising in the ordinary course of
business. Edison International believes the outcome of these other proceedings
will not materially affect its results of operations or liquidity.
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 49
identified sites is $167 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 $285
million. The upper limit of this range of costs was estimated using assumptions
least favorable to Edison International among a range of reasonably possible
outcomes. SCE has sold all of its gas- and oil-fueled generation plants and has
retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $86 million of its recorded liability, through an incentive
mechanism (SCE may request to include additional sites). Under this mechanism,
SCE will recover 90% of cleanup costs through customer rates; shareholders fund
the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $134 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
6
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 $5 million to $15 million.
Based on currently available information, Edison International believes it is
unlikely that it will incur amounts in excess of the upper limit of the
estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs ultimately
recorded will not materially affect its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of
new sites, will not require material revisions to such estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.8
billion. SCE and other owners of the San Onofre and Palo Verde nuclear plants
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 $88 million per reactor, but not
more than $10 million per reactor may be charged in any one year for each
incident. Based on its ownership interests, SCE could be required to pay a
maximum of $175 million per nuclear incident. However, it would have to pay no
more than $20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability claims and
are subject to adjustment for inflation. If the public liability limit above is
insufficient, federal regulations may impose further revenue-raising measures to
pay claims, including a possible additional assessment on all licensed reactor
operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million also has 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 $21 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Federal law requires the Department of Energy (DOE) to select and develop
repositories for, and oversee disposal of, spent nuclear fuel and high-level
radioactive waste. The law requires the DOE to provide for the disposal of spent
nuclear fuel and high-level radioactive waste from nuclear generation stations
beginning January 31, 1998. However, the DOE did not meet its obligation. It is
not certain when the DOE will begin accepting spent nuclear fuel from San Onofre
or from other nuclear power plants.
SCE has paid the DOE the required one-time fee applicable to nuclear generation
at San Onofre through April 6, 1983, (approximately $24 million, plus interest).
SCE is also paying the required quarterly fee equal to one mill per
kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.
7
SCE has primary responsibility for the interim storage of its spent nuclear fuel
at San Onofre. Current capability to store spent fuel is estimated to be
adequate through 2005. Meeting spent-fuel storage requirements beyond that
period would require new and separate interim storage facilities, the costs for
which have not been determined. Extended delays by the DOE could lead to
consideration of costly alternatives involving siting and environmental issues.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2002
for Units 1 and 2, and until 2003 for Unit 3. Arizona Public Service Company,
operating agent for Palo Verde, is constructing an interim fuel storage facility
that is expected to be completed in 2002.
SCE and other owners of nuclear power plants may be able to recover interim
storage costs arising from DOE delays in the acceptance of utility spent nuclear
fuel by pursuing relief under the terms of the contracts, as directed by the
courts, or through other court actions.
Note 3. Business Segments
Edison International's reportable business segments include its electric utility
operation segment (SCE), an unregulated power generation segment (EME), and a
capital and financial services provider segment (Edison Capital).
Segment information for the three months ended June 30, 1999, and 1998,
respectively, was:
3 Months Ended
June 30,
- -----------------------------------------------------------------------------------------------------------------
1999 1998
- -----------------------------------------------------------------------------------------------------------------
Operating Revenue:
Electric utility $1,720,831 $1,618,782
Unregulated power generation 269,372 207,314
Capital & financial services 79,674 58,736
Other* 46,137 54,203
-------------------------------------------------------------------------------------------------------
Consolidated Edison International $2,116,014 $1,939,035
-------------------------------------------------------------------------------------------------------
Net Income:
Electric utility $ 111,846 $ 120,448
Unregulated power generation 5,475 18,588
Capital & financial services 33,945 26,548
Other* (22,844) (20,281)
- -----------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 128,422 $ 145,303
- -----------------------------------------------------------------------------------------------------------------
* Includes amounts from nonutility subsidiaries not significant as a reportable
segment.
Total segment assets at June 30, 1999, were: electric utility, $17 billion;
unregulated power generation, $8 billion; capital and
financial services, $3 billion.
Note 4. Subsequent Event
On July 26, 1999, a trust that is an affiliate of Edison International issued
$500 million of 7.875% cumulative quarterly income preferred securities, which
are guaranteed by Edison International. These securities have a stated maturity
of July 2029, but are redeemable at the option of Edison International, in whole
or in part, beginning July 2004.
8
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 were 37(cent) and 78(cent),
respectively, for the three and six months ended June 30, 1999, compared to
40(cent) and 79(cent) for the same periods in 1998. Southern California Edison's
(SCE) earnings for the three and six months ended June 30, 1999, were 31(cent)
and 53(cent), respectively, unchanged and down 5(cent), respectively, from the
year-earlier periods. The decrease in SCE's year-to-date earnings was mainly due
to the scheduled refueling outages at San Onofre Nuclear Generating Station
Units 2 and 3. Edison Mission Energy (EME) and Edison Capital had combined
earnings of 11(cent) and 35(cent), respectively, compared to 12(cent) and
27(cent) during the same periods in 1998. The quarterly decrease was mostly due
to higher operating costs and interest expense at EME, partially offset by
infrastructure investments and the closing of three affordable housing
syndications at Edison Capital. The year-to-date increase was primarily due to
earnings contributions from infrastructure investments and the closing of
affordable housing syndications at Edison Capital. Edison Capital closed five
affordable housing syndications in the first half of 1999. Edison Enterprises
and the parent company were responsible for a combined negative earnings impact
for the three and six months ended June 30, 1999, of 5(cent) and 10(cent),
respectively, compared with 3(cent) and 6(cent) for the same periods in 1998.
The decreases in earnings were primarily due to continued investment in Edison
Enterprises' subsidiaries.
Operating Revenue
Electric utility revenue increased 6% and 5%, respectively, for the three and
six months ended June 30, 1999, compared to the year-earlier periods. The
increases resulted primarily from maintenance service SCE is providing the new
owners of the divested gas- and oil-fueled plants. Over 93% of electric utility
revenue was 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).
Due to warmer weather during the summer months, electric utility revenue during
the third quarter of each year is significantly higher than other quarters.
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction (financed through the issuance of rate reduction notes) for
residential and small commercial customers beginning in 1998 and other rates to
remain frozen at June 1996 levels (system average of 10.1(cent) per
kilowatt-hour). See discussion in Regulatory Environment below.
Revenue from diversified operations increased 23% and 33%, respectively, for the
three and six months ended June 30, 1999. The increases were mainly due to
revenue from EME's Homer City Generating Station, which was acquired in March
1999. The year-to-date increase also reflects increases at: Edison Capital,
related to the closing of five affordable housing syndications, as well as
additional lease transactions closed in 1998; Edison Enterprises, related to the
Westec acquisition in 1998; and EME, related to a pricing settlement on four
qualifying facility contracts.
Operating Expenses
Fuel expense increased 18% and decreased 13%, respectively, for the three and
six months ended June 30, 1999, compared to the same periods in 1998. The
quarterly increase is primarily related to an increase at EME for expenses at
Homer City Generating Station, partially offset by a decrease at SCE resulting
from the sale of its gas- and oil-fueled generation plants in 1998. The
year-to-date decrease is mostly due to SCE's sale of its gas- and oil-fueled
plants in 1998.
9
Since April 1, 1998, SCE has been required to sell all of its generated power
through the power exchange (PX) and acquire all of its power from the PX to
distribute to its retail customers. These transactions with the PX are reported
net. PX purchased-power expense increased for the quarter ended June 30, 1999,
compared to the year-earlier period, due to higher prices in May and June of
1999. SCE is continuing to purchase power under existing contracts from certain
nonutility generators (known as qualifying facilities) and from other utilities.
This purchased power is sold through the PX. Purchased-power expense - contracts
decreased for the three and six months ended June 30, 1999, compared to the same
periods last year, as a result of SCE entering into settlements to end its
contractual obligations with certain qualifying facilities. SCE was required
under federal law to purchase power from certain qualifying facilities at CPUC
mandated prices even though energy prices under these contracts are generally
higher than other sources. For the twelve months ended June 30, 1999, SCE paid
about $1.6 billion (including energy and capacity payments) more for these power
purchases than the cost of power available from other sources.
Provisions for regulatory adjustment clauses decreased for the three and six
months ended June 30, 1999, compared to the year-earlier periods, mostly due to
undercollections related to the difference between generation-related revenue
and generation-related costs. (See discussion in Revenue and Cost-Recovery
Mechanisms.)
Other operating expenses increased 10% and 26%, respectively, for the three and
six months ended June 30, 1999, compared to the same periods in 1998. The
increases were primarily due to SCE's mandated transmission service (known as
must-run reliability services) payments to the independent system operator (ISO)
and an increase at EME for costs at Homer City Generating Station. In addition,
the year-to-date increase was the result of direct access activities and
increased PX and ISO costs at SCE, additional reserves for five affordable
housing syndications at Edison Capital and increased operating expenses at
Edison Enterprises related to its 1998 Westec acquisition.
Income taxes decreased 32% and 35%, respectively, for the three and six months
ended June 30, 1999, compared to the year-earlier periods, mostly due to lower
pre-tax income at SCE and a lower effective tax rate at EME in 1999. The lower
effective tax rate at EME was the result of lower foreign income taxes which
resulted from the permanent reinvestment of earnings from foreign affiliates
located in different tax jurisdictions.
Net gain on sale of utility plant resulted from the sale of SCE's 12 gas- and
oil-fueled generation plants in 1998. Gains were used to reduce stranded costs.
Losses will be recovered from customers over the transition period.
Other Income and Deductions
Interest and dividend income decreased 23% for the six months ended June 30,
1999, compared to the same period in 1998, reflecting lower investment balances
at SCE during the first quarter of 1999, as well as lower cash balances at EME.
Other nonoperating income (deductions) increased for both the three and six
months ended June 30, 1999, compared to the same periods in 1998, due to the
gains on sales of equity investments at SCE. The year-to-date increase was
partially offset by a first quarter 1999 write-off of start-up costs at EME. EME
was required to write off these previously capitalized start-up costs due to an
accounting rule change effective January 1999.
Interest and Other Expenses
Interest and amortization on long-term debt increased 15% for the quarter ended
June 30, 1999, compared to same period in 1998, primarily due to additional
long-term debt at EME for financing the Homer City Generating Station
acquisition.
10
Other interest expense increased substantially for both the quarter and
six-month period ended June 30, 1999, compared to the year-earlier periods,
mostly due to additional debt for financing EME's Homer City Generating Station
acquisition and higher overall short-term debt balances at SCE necessary to meet
general cash requirements during the periods.
Capitalized interest increased for both the three and six months ended June 30,
1999, compared to the same periods in 1998, due to EME's investment in its
EcoElectrica project in December 1998. The year-to-date increase also reflects
EME's increased investment in its Paiton project, which began commercial
operation in May 1999.
Financial Condition
Edison International's liquidity is primarily affected by debt maturities,
dividend payments, capital expenditures, and investments in partnerships and
unconsolidated subsidiaries. Capital resources include cash from operations and
external financings.
Edison International's board of directors has authorized the repurchase of up to
$2.8 billion (increased from $2.3 billion in July 1998) of its outstanding
shares of common stock. Edison International repurchased approximately 101
million shares ($2.4 billion) between January 1995 and February 28, 1999, funded
by dividends from its subsidiaries and the proceeds of the rate reduction notes
issuance. (See discussion in Cash Flows from Financing Activities below.)
For the first half of 1999, Edison International's cash flow coverage of
dividends was 5.1 times compared to 4.0 times for the same period in 1998.
Edison International's dividend payout ratio for the twelve-month period ended
June 30, 1999, was 56.5%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $944 million for the six
months ended June 30, 1999, compared to $752 million for the same period in
1998. Cash from operations exceeded capital requirements for both periods
presented.
Cash Flows from Financing Activities
At June 30, 1999, Edison International and its subsidiaries had $1.4 billion of
borrowing capacity available under lines of credit totaling $3.4 billion. SCE
had total lines of credit of $1.3 billion, with $300 million available for
general purpose short-term debt and $500 million available for the long-term
refinancing of its variable-rate pollution-control bonds. The parent company had
total lines of credit of $600 million, with $100 million available. The
nonutility companies had total lines of credit of $1.5 billion, with $500
million available to finance general cash requirements. These unsecured lines of
credit are at negotiated or bank index rates with various expiration dates.
SCE's short-term debt is used to finance fuel inventories and general cash
requirements. Both EME's short-term and long-term debt are mostly used for
general corporate purposes. SCE's 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, 1999, SCE could issue
approximately $11.4 billion of additional first and refunding mortgage bonds and
$3.7 billion of preferred stock at current interest and dividend rates.
EME has firm commitments of $206 million to make equity and other contributions,
primarily for the ISAB project in Italy, the EcoElectrica project in Puerto
Rico, the Tri Energy project in Thailand and the Paiton project in Indonesia.
EME also has contingent obligations to make additional contributions of $194
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
11
operating activities, proceeds from the repayment of loans to energy projects
and funds available from EME's revolving line of credit.
Edison Capital has firm commitments of $247 million to fund affordable housing,
and energy and infrastructure investments.
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, 1999, SCE
had the capacity to pay $694 million in additional dividends and continue to
maintain its authorized capital structure. These restrictions are not expected
to affect Edison International's ability to meet its cash obligations.
In December 1997, SCE Funding LLC, a special purpose entity, 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
SCE Funding LLC 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 rate
charged to residential and small commercial customers. Despite the legal sale of
the transition property by SCE to SCE Funding LLC, the amounts reflected as
assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to SCE Funding LLC, and the liabilities of SCE Funding
LLC for the rate reduction notes are for accounting purposes reflected as
long-term liabilities on the consolidated balance sheets of SCE. SCE used the
proceeds from the sale of the transition property to retire debt and equity
securities.
The remaining series of outstanding rate reduction notes have scheduled
maturities beginning in 2000 and ending in 2007, and bear interest at rates
ranging from 6.14% to 6.42%. The rate reduction notes are secured solely by the
transition property and certain other assets of SCE Funding LLC, and there is no
recourse to SCE or Edison International.
Although SCE Funding LLC is consolidated with SCE in the financial statements,
as required by generally accepted accounting principles, SCE Funding LLC is
legally separate from SCE, the assets of SCE Funding LLC are not available to
creditors of SCE or Edison International, and the transition property is legally
not an asset of SCE or Edison International.
On July 26, 1999, a trust that is an affiliate of Edison International issued
$500 million of 7.875% cumulative quarterly income preferred securities, which
are guaranteed by Edison International. These securities have a stated maturity
of July 2029, but are redeemable at the option of Edison International, in whole
or in part, beginning July 2004.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, the nonutility companies' investments in partnerships and unconsolidated
subsidiaries, proceeds from the sale of assets (see discussion in Regulatory
Environment below), 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. SCE estimates that it will
spend approximately $8.6 billion through 2060 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar decommissioning costs
($1.9 billion), escalated at rates ranging from 0.3% to 10.0% (depending on the
cost element) annually. These costs are expected to be funded from independent
decommissioning trusts which, effective June 3, 1999, receive SCE contributions
of approximately $25 million per year.
12
Cash used for the nonutility subsidiaries' investing activities was $2.7 billion
for the six-month period ended June 30, 1999, compared to $423 million for the
same period in 1998. The increase is primarily due to EME's acquisitions during
the first half of 1999.
Market Risk Exposures
Edison International's primary market risk exposures arise from fluctuations in
energy prices, interest rates and foreign exchange rates. Edison International's
risk management policy allows the use of derivative financial instruments to
manage its financial exposures, but prohibits the use of these instruments for
speculative or trading purposes.
As a result of the rate freeze established in the restructuring legislation,
SCE's transition costs are recovered as the residual component of rates once the
costs for distribution, transmission, public purpose programs, nuclear
decommissioning and the cost of supplying power to its customers through the PX
and ISO have already been recovered. Accordingly, more revenue will be available
to cover transition costs when market prices in the PX and ISO are low than when
PX and ISO prices are high. The PX and ISO market prices to date have generally
been reasonable, although some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap of $250/MW on the market for such
services until certain actions have been completed to improve the functioning of
those markets. Similarly, the ISO currently maintains a cap of $250/MWh on its
market for imbalance energy until adequate measures to improve the efficient
operation of the market have been implemented. The caps in these markets
mitigate the risk of costly price spikes that would reduce the revenue available
to SCE to pay transition costs. The ISO is in the process of replacing the price
caps currently used in its markets with a price volatility limit mechanism to be
implemented after the summer of 1999. This limit mechanism would act to prevent
unduly large day-to-day increases in prices. SCE has entered into hedges against
high natural gas prices, since increases in natural gas prices tend to raise the
price of electricity purchased from the PX. In July 1999, SCE began
participating in forward purchases through a PX block forward market. SCE
requested permission from the CPUC to begin a pilot demand responsiveness
program that would allow customers to be paid to curtail their load during times
of very high prices. This request was denied for 1999, but SCE will continue to
work with the CPUC and others to implement some form of demand responsiveness
programs prior to the summer of 2000.
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 a portion of 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. Interest expense includes $13 million and $12 million, respectively,
for the six month periods ended June 30, 1999, and June 30, 1998, as a result of
interest rate swap and collar agreements. 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 on the difference between the price in the contract and the pool
price for the element of power under contract. These contracts are sold in
various structures. 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. A proposal to replace the current structure of the
forward-contracts market and the pool has been made by the Director General of
Electricity Supply, at the request of the Minister of Science, Energy and
Industry in the United Kingdom. The Minister has recommended that the proposal
be implemented by April 2000. Further
13
definition of the proposal will berequired before the effects of the changes can
be evaluated. Implementation of the proposal may also require legislation.
Loy Yang B sells its electric energy through a centralized electricity pool,
which provides for a system of generator bidding, central dispatch and a
settlements system based on a clearing market for each half-hour of every day.
The Victorian Power Exchange, operator and administrator of the pool, determines
a system marginal price each half-hour. To mitigate the exposure to price
volatility of the electricity traded in the pool, Loy Yang B has entered into a
number of financial hedges. From May 8, 1997, to December 31, 2000,
approximately 53% to 64% of the plant output sold is hedged under vesting
contracts, with the remainder of the plant capacity hedged under the state hedge
described below. Vesting contracts were put into place by the State Government
of Victoria, Australia (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 are sold in various structures. 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.
Electric power generated at Homer City is sold under bilateral arrangements with
domestic utilities and power marketers under short-term contracts (two years or
less) or to the Pennsylvania-New Jersey-Maryland Power Interconnection (PJM) or
the New York Power Pool (NYPP). The PJM pool has a market which establishes an
hourly clearing price. Homer City is located in the PJM pool area and is
physically connected to high-voltage transmission lines serving both the PJM and
NYPP markets. Power can also be transmitted to the mid-western United States.
EME has developed risk management policies and procedures which, among other
matters, address credit risk. It is EME's policy to sell to investment grade
counterparties or counterparties that have an investment grade guarantor. EME
intends on hedging a portion of the electric output of the plant in order to
lock in desirable outcomes. EME plans to manage the margin that is spread
between electric prices and fuel prices when deemed appropriate. EME plans to
use forward contracts, swaps, futures or options contracts to achieve those
objectives.
EME's electric revenue increased by $20 million for the six months ended June
30, 1999, compared to an increase of $70 million for the same period in 1998, as
a result of electricity rate swap agreements and other hedging activities.
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.
A wholly owned subsidiary of EME owns a 40% interest in the Paiton project, a
1,230-MW coal-fired power plant in Indonesia. 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 Indonesian Rupiah, with the portion of such payments intended to
cover non-Rupiah project costs (including returns to investors) indexed to the
Indonesian Rupiah/U.S. dollar exchange rate established at the time of the power
purchase agreement in February 1994. The state-owned electricity company's
payment obligations are supported by the Indonesian Government. The projected
rate of growth of the Indonesian
14
economy and the exchange rate of Indonesian Rupiah into U.S. dollars have
deteriorated significantly since the Paiton project was contracted, approved and
financed. The project received substantial finance and insurance support from
the Export-Import Bank of the United States, The Export-Import Bank of Japan,
the U.S. Overseas Private Investment Corporation and the Ministry of
International Trade and Industry of Japan. The Paiton project's senior debt
ratings have been reduced from investment grade to speculative grade based on
the rating agencies' perceived increased risk that the state-owned electricity
company might not be able to honor the electricity sales contract with Paiton.
The Indonesian government has arranged to reschedule sovereign debt owed to
foreign governments and has entered into discussions about rescheduling
sovereign debt owed to private lenders.
One of the Paiton units began commercial operation in May 1999 and the other
unit in July 1999. Because of the economic downturn, the state-owned electricity
company is experiencing low electricity demand and has therefore ordered no
power from the Paiton plant; however, under the terms of the power purchase
agreement, the state-owned electricity company is required to continue to pay
for capacity and fixed operating costs once each unit and the plant achieve
commercial operation. An invoice for these charges for May 1999 has been
submitted and a partial payment based on an arbitrary exchange rate that does
not comply with the terms of the power purchase agreement, was received. The
state-owned electricity company has begun initial discussions with independent
power producers to renegotiate the power supply contracts. However, it is not
yet known what form the renegotiation may take. Any material modifications of
the contract could also require a renegotiation of the Paiton project's debt
agreement. The impact of any such renegotiations with the state-owned
electricity company, the Indonesian government or the project's creditors on
EME's expected return on its investment in Paiton is uncertain at this time,
however, EME believes that it will ultimately recover its investment in the
project. EME continues to monitor the situation closely.
Projected Capital Requirements
Edison International's projected construction expenditures for the next five
years are: 1999-- $963 million; 2000-- $816 million; 2001-- $716 million; 2002--
$643 million; and 2003-- $641 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 1999, are: 2000 -- $910 million; 2001 --
$914 million; 2002 -- $438 million; 2003 -- $826 million; and 2004 -- $359
million.
Preferred stock redemption requirements for the five twelve-month periods
following June 30, 1999, are: 2000 through 2002-- zero; 2002-- $105 million;
2003-- $9 million; and 2004-- $9 million.
EME Acquisitions
In March 1999, EME completed the acquisition of the 1,884-MW Homer City
Generating Station for approximately $1.8 billion. Homer City was jointly owned
by subsidiaries of GPU, Inc. and New York State Electric & Gas Corporation. The
coal-fired facility has the rights to direct, high-voltage interconnections to
both the New York Power Pool and the Pennsylvania-New Jersey-Maryland Power
Pool. The plant is located near Pittsburgh, Pennsylvania. EME is operating the
plant, which is one of the lowest-cost generation facilities in the region. EME
financed the acquisition with a combination of debt secured by the project, EME
corporate debt, cash and EME corporate revolving debt.
In March 1999, EME entered into agreements to acquire the fossil-fuel generating
assets of Commonwealth Edison Company (ComEd) for approximately $5 billion. The
coal-, gas- and oil-fired generating facilities have a total capacity of 9,621
MW. In conjunction with the acquisition, EME, who will own and operate the
facilities, will invest additional capital in the plants to upgrade pollution
controls, extend plant life, improve reliability and reduce generation cost. The
transaction is expected to close by year-end 1999 and is expected to have an
immaterial effect on earnings in 1999, 2000 and 2001, as a result of transition
contracts in which ComEd will retain power purchase agreements with EME,
enabling ComEd access to certain amounts of plant output for the next five years
to serve its customers.
15
In May 1999, EME completed its acquisition of a 40% interest in New Zealand
government-owned Contact Energy Ltd. for approximately $648 million. The New
Zealand government sold the remaining 60% of Contact Energy to the public
through an initial public offering. Contact Energy owns and operates
hydroelectric, geothermal and natural gas-fired generating plants in New Zealand
with a total generating capacity of 2,371 MW. Contact Energy also supplies gas
and electricity to customers in New Zealand and has minority interests in two
power projects in Australia. EME financed the acquisition with subsidiary debt,
an equity contribution from Edison International and cash.
In July 1999, EME completed its acquisition of two electric generating plants
located in the United Kingdom (U.K.) from PowerGen, an U.K. utility, for
approximately $2 billion. Each of the plants has a generating capacity of about
2,000 MW. The acquisition was financed primarily through a combination of debt
secured by the project and equity from Edison International.
Regulatory 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
as a result of a 1995 CPUC decision on restructuring and state legislation
enacted in 1996. The Statute substantially adopted the CPUC's restructuring
decision by addressing stranded-cost recovery for utilities and providing a
certain cost-recovery time period for the transition costs associated with
generation-related assets. 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 mandated
other rates to remain frozen at June 1996 levels (system average of 10.1(cent)
per kilowatt-hour), including those for large commercial and industrial
customers, and included 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 competition transition charge (CTC) (see detailed
discussion below) that provides utilities the opportunity to recover costs made
uneconomic by electric utility restructuring.
Revenue and Cost-Recovery Mechanisms
In 1999, revenue is being determined by various mechanisms depending on the
utility operation. Revenue related to distribution operations is being
determined through a performance-based rate-making mechanism (PBR) and the
distribution assets have the opportunity to earn a CPUC-authorized 9.49% return.
The distribution-only PBR will extend through December 2001. Key elements of the
distribution PBR include: distribution rates indexed for inflation based on the
Consumer Price Index less a productivity factor; 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 customer satisfaction; service
reliability and safety; and a net revenue-sharing mechanism that determines how
customers and shareholders will share gains and losses from distribution
operations. Transmission revenue is being determined through FERC-authorized
rates that are subject to refund.
SCE's transition costs 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 1995 restructuring decision date. SCE has
estimated its transition costs to be approximately $10.6 billion (1998 net
present value) from 1998 through 2030. This estimate was based on incurred
costs, forecasts of future costs and assumed market prices. However, changes in
the assumed market prices could materially affect these estimates. 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 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 (including the 1998 sale of SCE's gas-
and oil-fueled generation plants) and regulatory commitments consisting of costs
incurred (whose recovery has been deferred by the CPUC) to provide service to
customers. Such commitments include
16
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 Nuclear Generating Station units, and certain
other costs. During 1998, SCE sold all of its gas- and oil-fueled generation
plants for $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. If events occur during
the restructuring process that result in all or a portion of the transition
costs being improbable of recovery, SCE could have write-offs associated with
these costs if they are not recovered through another regulatory mechanism.
Revenue from generation-related operations is being determined through the
competitive market and the CTC mechanism, which now includes the nuclear
rate-making agreements. Revenue related to fossil and hydroelectric generation
operations are 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. SCE's costs associated
with its hydroelectric plants are being recovered through a performance-based
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. In 1999, fossil and hydroelectric generation assets will earn a 7.22%
return.
The CPUC authorized revised rate-making plans for SCE's nuclear facilities,
which call for the accelerated recovery of the 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 an approximately $20
million negative impact on 1999 earnings.
The CPUC considered unbundling SCE's cost of capital by authorizing separate
rates of return for generation, transmission and distribution operations. In May
1998, SCE filed an application on this issue and hearings were completed in
October 1998. On June 10, 1999, the CPUC issued a decision which retains SCE's
return on equity at 11.6%.
In March 1997, SCE filed its first FERC transmission rate case. In March 1999, a
proposed FERC decision was issued which recommended a reduced rate of return on
equity of 9.68% (compared to SCE's current CPUC rate for distribution of 11.6%)
and a reduced return on transmission assets of 8.41% (compared to the current
rate of 9.43% being earned on transmission assets). SCE has filed comments
opposing the proposed decision. A final FERC decision is expected in late 1999.
SCE does not expect the final decision to have a material effect on its results
of operations or financial position.
Restructuring Implementation Costs
The ISO assumed operational control of the transmission system after the ISO and
PX had begun accepting bids and schedules for electricity purchases on March 31,
1998. 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. In May 1998, SCE filed an
17
application with the CPUC to identify the categories of such costs (including
costs related to the implementation of direct access) and to establish the
reasonableness of those costs incurred in 1997.
Two proposed decisions issued in March 1999 rejected SCE's request for a
determination of eligibility for several major categories of such costs. In May
1999, SCE, the CPUC's Office of Ratepayer Advocates and several other parties
entered into a settlement agreement that would allow SCE to recover
substantially all (approximately $319 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation. The CPUC has withdrawn its earlier proposed decisions
on SCE's application. On July 6, 1999, a proposed decision was issued that would
approve the settlement in its entirety. A final CPUC decision on the settlement
is expected in third quarter 1999.
Accounting for Generation-Related Assets
If the CPUC's electric industry restructuring plan continues as described above,
SCE will be allowed to recover its transition costs 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). In
1997, SCE discontinued application of accounting principles for rate-regulated
enterprises for its investment in generation facilities based on new accounting
guidance. The new guidance did not require SCE to write off any of its
generation-related assets, including related regulatory assets. SCE has retained
these assets on its balance sheet because the Statute and restructuring plan
referred to above make probable their recovery through a non-bypassable CTC to
distribution customers. The regulatory assets relate primarily to the recovery
of accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments and unamortized losses on
reacquired debt. The new accounting guidance also permits the recording of new
generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording a regulatory asset on its balance
sheet for the same amount. For this impairment assessment, the fair value of the
investment was calculated by discounting future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $1.8
billion, after tax, at June 30, 1999) as a one-time, non-cash charge against
earnings. At this time, SCE cannot predict what other revisions will ultimately
be made during the restructuring process in subsequent proceedings or the
effect, after the transition period, that competition will have on its results
of operations or financial position.
Environmental Protection
Edison International is subject to numerous environmental laws and regulations,
which require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.
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.
18
Edison International's recorded estimated minimum liability to remediate its 49
identified sites is $167 million. One of SCE's sites, a former pole-treating
facility, is considered a federal Superfund site and represents 40% of its
recorded liability. The ultimate costs to clean up Edison International's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process. Edison International believes
that, due to these uncertainties, it is reasonably possible that cleanup costs
could exceed its recorded liability by up to $285 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 $86 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 $134 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer
rates.
Edison International's identified sites include several sites for which there is
a lack of currently available information, including the nature and magnitude of
contamination, and the extent, if any, that Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can be made for these sites.
Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $5 million to $15 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 was
undertaken to determine the specific impact of air contaminant emissions from
the Mohave Generating Station on visibility in Grand Canyon National Park. The
final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. On June 17,
1999, the Environmental Protection Agency issued an advanced notice of proposed
rulemaking regarding assessment of visibility impairment at the Grand Canyon.
SCE intends to file comments on the proposed rulemaking. At this time, SCE is
unable to predict the potential effect of these studies on sulfur dioxide
regulations for Mohave, or what effect the final reports may have on SCE's
results of operations or financial position.
Edison International's projected environmental capital expenditures are $900
million for the 1999-2003 period, mainly for undergrounding certain transmission
and distribution lines.
19
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 in 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. A favorable
or decreasing trend in degradation was observed during inspection in the
scheduled refueling outage in January 1999. Analysis of results of the January
1999 inspection has determined that a mid-cycle inspection outage in early 2000
will be unnecessary. With the results from the January 1999 outage, 7.5% of the
tubes have now been removed from service.
During Unit 3's refueling outage, which was completed in May 1999, a complete
inspection of the steam generator tubes was performed. Results obtained were
within expectations. To date, 5.4% of Unit 3's tubes have been removed from
service. During the refueling, follow-up inspections of the tube support
thinning problem first detected in 1997 were performed. These inspections
confirmed that corrective actions taken in 1997 were effective and the thinning
has been stabilized.
New Accounting Rules
An accounting rule which requires that costs related to start-up activities be
expensed as incurred became effective January 1, 1999. Although this new
accounting rule did not materially affect Edison International's results of
operations or financial position, EME wrote off approximately $14 million in
previously capitalized start-up costs in first quarter 1999.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, 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 the existing computer systems at Edison International were originally
programmed to represent any date by using six digits (e.g., 12/31/99) rather
than eight digits (e.g., 12/31/1999). Accordingly, such programs, if not
appropriately addressed, could fail or create erroneous results when attempting
to process information containing dates after December 31, 1999. This situation
has been referred to generally as the Year 2000 Issue.
Edison International has a comprehensive program in place to address potential
Year 2000 impacts. Edison International provides overall coordination of this
effort, working with its affiliates and their departments. Edison International
divides Year 2000 activities into five phases: inventory, impact assessment,
remediation, testing and implementation. Edison International met its goal to
have 100% of its critical systems Year 2000-ready by July 1, 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 health and safety of the public and/or
personnel, the revenue stream, or regulatory compliance. A system, application
or physical asset is deemed to be Year 2000-ready if it is determined by Edison
International to be suitable for continued use through 2028 (or through
20
the last year of the anticipated life of the asset, whichever occurs first),
even though it may not be fully Year 2000-compliant. A system, application, or
physical asset is deemed to be Year 2000-compliant if it accurately processes
date/time data.
Edison International has structured the scope of the program to focus on three
principal categories: mainframe computing, distributed computing and physical
assets (also known as embedded processors). The mainframe and distributed
computing assets consist of computer application systems (software). Physical
assets include information technology infrastructure (hardware, operating system
software) and embedded processor technology in generation, transmission,
distribution, and facilities components.
Included among SCE's critical applications that are Year 2000-ready are the
financial, customer information and billing, material management, and human
resource systems. Work has also been completed on critical physical assets in
the areas of information technology infrastructure, as well as embedded
processor technology in generation, transmission, distribution and facilities
assets. SCE filed a statement with the Nuclear Regulatory Commission (NRC) on
June 28, 1999, stating that its Year 2000 readiness program has been completed
for those systems within the scope of its license, NRC regulations and other
critical systems required for continued operation of San Onofre Units 2 and 3.
EME achieved Year 2000-readiness of its critical systems as of July 1, 1999.
Assurances from third party operated plants have been received indicating
comprehensive Year 2000 remediation programs. Monitoring of these efforts is
ongoing. Plants under construction have obtained assurances from new
construction and development contractors, who have been requested to make
certain that this is part of their goals. General warranty of plants would
likely include any equipment issues that may arise regarding Year 2000 in the
current year.
Edison Enterprises achieved Year 2000-readiness of critical systems on June 30,
1999. Included among Edison Enterprises' critical systems are those related to
Edison Select's residential security services, Edison Source's energy-related
products and services, and Edison Utility Services' transmission and
distribution outsourcing, outage management, billing and new utility
construction services.
Edison Capital achieved Year 2000-readiness of its critical systems as of July
1, 1999. Included among Edison Capital's critical systems are those related to
the provision of capital and financial services in the areas of
energy/infrastructure and affordable housing.
Ongoing efforts in 1999 will continue to focus on guarding against
reintroduction of components that are not Year 2000-ready into Year 2000-ready
systems. Also, business acquisitions routinely involve an analysis of Year 2000
readiness and are incorporated into the overall program as necessary.
The other essential component of Edison International's Year 2000 program is to
identify and assess vendor products and business partners for Year 2000
readiness, as these external parties may have the potential to impact Edison
International's Year 2000 readiness. Edison International has implemented,
through its affiliates and their departments, a process to identify and contact
vendors and business partners to determine their Year 2000 status. Evaluation of
responses and other follow-up activities are continuing. Edison International's
general policy requires that all newly purchased products and services be Year
2000-ready or otherwise designed to allow Edison International to determine
whether such products and services present Year 2000 issues. SCE is also working
to address Year 2000 issues related to all ISO and PX interfaces, as well as
joint ownership facilities. SCE and other Edison International affiliates
exchange Year 2000-readiness information (including, but not limited to, test
results and related data) with one another and certain external parties as part
of their Year 2000-readiness efforts.
Edison International's current estimate of its Year 2000 costs, including the
costs of new hardware and software application modification, work on contingency
planning efforts discussed below and continuing work on non-critical assets, is
$75 million, about 35% of which is expected to be capital costs. Edison
International's Year 2000 costs expended through June 30, 1999, were
approximately $56 million. SCE expects current rate levels for providing
electric service to be sufficient to provide funding for utility-related
modifications.
21
Although Edison International expects that its critical facilities, systems,
information technology infrastructure and physical assets will remain fully Year
2000-ready, there can be no assurance that the facilities, systems,
infrastructure and physical assets of other companies on which the systems and
operations of Edison International rely will be converted on a timely basis
and/or remain ready for the Year 2000. Edison International believes that
prudent business practices call for development of contingency plans. These
plans include provisions for monitoring, validating and managing the continued
performance of Edison International Year 2000-sensitive systems and assets
during critical transition periods, development of work-arounds and expedited
fix-on-failure strategies. Where appropriate, contingency plans include
scheduling of key personnel, identification of alternate suppliers and securing
adequate on-site supplies of critical materials.
Edison International has implemented a Year 2000 contingency planning process as
a part of its Year 2000 remediation program. As part of this process, SCE, EME,
Edison Enterprises, and Edison Capital are required to assess the Year 2000
risks, including both internal and external risks and dependencies, associated
with critical systems and assets, that are date aware or date sensitive. This
includes assessment of Year 2000 risks for all indispensable or critical
business processes and key facilities.
Where appropriate, the SCE plans utilize or supplement the existing Corporate
Emergency Response and Recovery Plan, and Information Technology disaster
recovery plan, for identified Year 2000-related events. SCE's Year 2000
contingency plans are designed to coordinate and interface with the ISO and PX
and to satisfy Western System Coordinating Council (WSCC) and North America
Electric Reliability Council (NERC) recommendations and Nuclear Energy Institute
guidelines. SCE has worked with, and will continue to work with, these industry
groups, as well as the Electric Power Research Institute, in the development of
its contingency plans. Initial development of these plans was completed in June
1999. SCE filed a report on its contingency plans with the CPUC on July 1, 1999.
Contingency plans will be used in conducting SCE and electric industry drills
throughout the rest of 1999. SCE expects that its contingency plans will
continue to be revised and enhanced as 2000 approaches.
Although SCE's Year 2000 contingency plans use risk-based methods, the plans are
being evaluated against the NERC/WSCC suggested "more probable" and "credible
worst case scenarios." SCE believes that the most reasonably likely worst case
Year 2000 scenario would be small, localized interruptions of service which
would be restored in a timeframe that is within normal service levels.
EME's Year 2000 contingency plans are being developed using risk-based methods
and following Edison International's Year 2000 guidelines and procedures.
Generating plant contingency plans have been developed and reviewed for any
significant issues and to schedule appropriate testing and/or training. Such
contingency plans include developing strategies for dealing with Year
2000-related processing failures or malfunctions due to EME's internal systems
or from external parties. EME's Year 2000 contingency planning program, which
includes development of contingency plans, allocations of resources and plan
testing, is expected to be completed by October 1, 1999.
Edison Enterprises' Year 2000 contingency plans for Edison Enterprises
companies, including Edison Select, Edison Source and Edison Utility Services,
are being developed using risk-based methods and following Edison
International's Year 2000 guidelines and procedures. Draft Year 2000 contingency
plans have been developed and Edison Enterprises' Year 2000 contingency planning
program is expected to be completed by October 1, 1999.
Edison Capital's Year 2000 contingency plan is being developed using risk-based
methods and following Edison International's Year 2000 guidelines and
procedures. Edison Capital's Year 2000 contingency planning program is expected
to be completed by October 1, 1999.
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, and despite the adoption of contingency plans,
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.
22
Forward-looking Information
In the preceding Management's Discussion and Analysis of Results of Operations
and Financial Condition and elsewhere in this quarterly report, the words
estimates, expects, anticipates, believes, and other similar expressions are
intended to identify forward-looking information that involves risks and
uncertainties. Actual results or outcomes could differ materially as a result of
such important factors as further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business, including direct customer access to retail energy suppliers and the
unbundling of revenue cycle services such as metering and billing; changes in
prices of electricity and fuel costs; changes in market interest or currency
exchange rates; foreign currency devaluation; new or increased environmental
liabilities; the effects of the Year 2000 Issue; municipalization and other
unforeseen events.
23
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings
Edison International
Geothermal Generators' Litigation
Edison International, The Mission Group, and Mission Power Engineering Company,
have been named as defendants in a lawsuit more fully described under "Southern
California Edison Company - Geothermal Generators' Litigation below."
Edison Mission Energy
PMNC Litigation
In February 1997, a civil action was commenced in the Superior Court of the
State of California, Orange County, entitled The Parsons Corporation and PMNC v.
Brooklyn Navy Yard Cogeneration Partners, L.P. (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 in the Supreme Court of the State of New York, Kings County
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, 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 and PMNC subsequently attached three
Brooklyn Navy Yard bank accounts, located in California, in the amount of $0.5
million. Brooklyn Navy Yard is appealing the attachment order. On the same day,
the Court stayed all proceedings in the California action pending an order by
the New York Appellate Court of the appeal by PMNC of a denial of its motion to
dismiss the New York action. That appeal was denied following a hearing on
September 29, 1998. On March 9, 1999, Brooklyn Navy Yard filed a partial Motion
for Summary Judgment in the New York action.
Southern California Edison Company
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties routinely vented highly toxic hydrogen
sulfide gas from unmonitored release points beginning in 1990 and continuing
through at least 1994, in violation of applicable federal, state, and local
environmental law. According to SCE, these violations constituted material
breaches by the Coso parties of their obligations under their contracts with SCE
and applicable law. The complaint sought termination of the contracts and
damages for excess power purchase payments made to the Coso parties. The Coso
parties' motion to transfer venue to Inyo County Superior Court was granted on
August 31, 1997. On June 1, 1998, the Court struck SCE's request for termination
of the contracts, leaving SCE with its claim for damages and other relief. On
February 16, 1999, the Court denied the Coso parties' motion for judgment on the
pleadings directed to SCE's first amended complaint.
The Coso parties have also asserted various claims against SCE, The Mission
Group, and Mission Power Engineering Company (Mission parties) in a cross
complaint filed in the action commenced by SCE as well as in a separate action
filed against SCE by three of the Coso parties in Inyo County
24
Superior Court. In November 1997, the Court struck all but two causes of action
asserted in the separate action on the grounds that they should have been raised
as part of the Coso parties' cross-complaint, and ordered the remaining two
causes of action consolidated for all purposes with the action filed by SCE.
The Coso parties subsequently filed second and third amended cross-complaints.
The third amended cross-complaint names SCE, the Mission parties and Edison
International. As against SCE, the third amended cross-complaint purports to
state causes of action for declaratory relief, breach of the covenant of good
faith and fair dealing; inducing breach of agreements between the Coso parties
and their former employees; breach of an earlier settlement agreement between
the Mission parties and the Coso parties; slander and disparagement, injunctive
relief and restitution for unfair business practices; anticipatory breach of the
contracts; and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As
against the Mission parties, the third amended cross-complaint seeks damages for
breach of warranty of authority with respect to the settlement agreement, and
for equitable indemnity. The Coso parties voluntarily dismissed Edison
International from the third amended cross-complaint on December 4, 1998. As
against SCE, the third amended cross-complaint seeks restitution, compensatory
damages in excess of $115 million, punitive damages in an amount not less than
$400 million, interest, attorney's fees, declaratory relief, and injunctive
relief.
On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting affirmative
defenses. In addition, SCE filed a cross-complaint for reformation of the
contracts alleging that if they are not susceptible to SCE's interpretation,
they should be reformed to reflect the parties' true intention. SCE subsequently
voluntarily filed a first amended cross-complaint. On February 26, 1999, after
the Court had sustained a demurrer to its first amended cross-complaint, SCE
filed a second amended cross-complaint for reformation.
Following various pre-trial motions filed by the Mission parties and Edison
International, the Coso parties purported to file a fourth amended
cross-complaint on December 23, 1998, against the Mission parties only. The
Mission parties' demurrer to and motion to strike directed to the fourth amended
cross-complaint was heard and taken under submission on March 10, 1999.
On December 15, 1998, the Court granted the Coso parties leave to file a second
amended complaint in the separately filed (now consolidated) action. The second
amended complaint, which names SCE and Edison International, alleges that SCE
engaged in anti-competitive conduct, false advertising, and conduct proscribed
by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and
punitive damages. On January 20, 1999, SCE filed three motions to strike several
portions of the second amended complaint on the grounds, among others, that the
CPUC or FERC have either exclusive or primary jurisdiction over the matters
asserted therein, and that SCE's alleged conduct was in furtherance of
constitutionally protected rights of free speech and petition and therefore not
actionable. These matters were heard on February 22, 1999, and taken under
submission at that time. Edison International also filed a demurrer and motion
to strike the second amended complaint. The Court denied the motion to strike
and overruled the demurrer on March 22, 1999.
On April 1, 1999, the Court signed a stipulation and order submitted by the
parties staying all proceedings to allow the parties to engage in settlement
discussions. The stay is in effect through and including September 30, 1999. As
a result of the stay, all discovery has been suspended. Furthermore, during the
period of the stay, the Court will not issue orders or rulings on matters taken
under submission.
The Court has set a trial date of March 1, 2000, but, in light of the stay
currently in effect, has reserved jurisdiction to advance or to continue the
trial date. The materiality of net final judgments against SCE in these actions
would be largely dependent on the extent to which any damages or additional
payments which might result therefrom are recoverable through rates.
25
San Onofre Personal Injury Litigation
SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. On August 31, 1995, the wife
and daughter of a former San Onofre security supervisor sued SCE and SDG&E in
the U.S. District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering and the Institute of Nuclear Power Operations as
defendants. All trial court proceedings were stayed pending ruling of the Ninth
Circuit Court of Appeals, on an appeal of a lower court's judgment in favor of
SCE in two earlier cases raising similar allegations. On May 28, 1998, the Court
of Appeal affirmed these judgments. Pursuant to an agreement of the parties as
described below, all proceedings in this matter have been stayed.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California. Plaintiffs also named Combustion
Engineering. The trial in this case resulted in a jury verdict for both
defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed
an appeal of the trial court's judgment to the Ninth Circuit Court of Appeals.
Briefing on the appeal was completed in January 1999 and the parties are
awaiting a date for oral argument to be set by the Court. A decision is not
expected until at least early 2000.
On November 28, 1995, a former contract worker at San Onofre, her husband, and
her son, sued SCE in the U.S. District Court for the Southern District of
California. Plaintiffs also named Combustion Engineering. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in this matter have been stayed.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the
above cases currently pending at the U.S. District Court level to stay all
proceedings including trial, pending the results of the case currently before
the Ninth Circuit Court of Appeals. The parties agreed that if the plaintiffs in
that case do not receive a favorable determination on appeal, then the two cases
at the District Court level will be dismissed. If, however, those plaintiffs
receive a favorable determination on their appeal, then the two cases will be
set for trial. On March 23, 1999, the District Court approved the parties' stay
agreement in both cases.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE was
successful in removing itself from those actions and is no longer actively
involved in them, the impact on SCE, if any, from further proceedings in those
cases against the remaining defendants can not be determined at this time.
Mohave Generating Station Environmental Litigation
On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in
the U.S. District Court of Nevada against SCE and the other three co-owners of
Mohave Generating Station (Mohave). The lawsuit alleges that Mohave has been
violating various provisions of the Clean Air Act (CAA), 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 CAA, 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 pending the court's ruling on a motion to
dismiss filed by the defendants. The plaintiffs filed an opposition to the
defendants' motion to dismiss as well as a separate motion for partial summary
judgment on May 8, 1998.
On June 4, 1998, the plaintiffs served SCE and the other Mohave co-owners with a
60-day supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On November 12,
1998, the court bifurcated the liability and damage phases of the case and
granted plaintiffs' motion to amend the complaint to add the National Parks and
Conservation Association as a plaintiff.
26
On December 8, 1998, defendants filed a supplemental memorandum in support of
defendants' opposition to plaintiffs' motion for partial summary judgment. On
February 4, 1999, plaintiffs filed their first amended complaint to add the
National Parks and Conservation Association as a plaintiff in the action. On
March 10, 1999, defendants filed a motion for partial summary judgment. On March
11, 1999, plaintiffs filed a motion for partial summary judgment to establish
emission limit violations as alleged in certain of the causes of action in their
first amended complaint.
On March 8, 1999, the parties filed a stipulated request for a 60-day stay which
was granted and ordered by the Court on March 9, 1999. A subsequent stay was
granted, which was to expire on July 6, 1999, before being extended to July 20,
1999. No further stay has been sought or is in effect at this time. On July 6,
1999, each party filed an opposition to the other parties' motion for summary
judgment. On August 2, 1999, defendants filed a reply to plaintiff's opposition.
On August 5, 1999, plaintiffs filed a reply to defendant's opposition.
Settlement discussions are ongoing.
Navajo Nation Litigation
On June 18, 1999, SCE was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to Mohave. The
complaint claims that the defendants' actions prevented the Navajo Nation from
obtaining the full value in royalty rates for the coal. The complaint seeks
damages of not less than $600 million, trebling of that amount, and punitive
damages of not less than $1 billion, as well as a declaration that Peabody's
lease and contract rights to mine coal on Navajo Nation lands should be
terminated. SCE's response to the complaint is due on September 9, 1999.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 7,
1998 (File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior participating Cumulative
Preferred Stock of Edison International dated November 21, 1998 (Form 8-A
dated November 21, 1998)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors
on April 15, 1999 (File No. 1-9936, Form 10-Q for the quarter ended March
31, 1999
10.1 Form of Agreement for 1999 Director Awards under the Equity Compensation
Plan
10.2 Estate and Financial Planning Program as amended April 1, 1999
10.3 Sale, Purchase and Leasing Agreement between PowerGen UK plc and Edison
First Power Limited for the purchase of the Ferrybridge "C" Power Station
(incorporated herein by reference to Exhibit 2.7 to Edison Mission Energy's
Form 8-K dated July 19, 1999, File No. 1-13434)*
10.4 Sale, Purchase and Leasing Agreement between PowerGen UK plc and Edison
First Power Limited for the purchase of the Fiddler's Ferry Power Station
(incorporated herein by reference to Exhibit 2.8 to Edison Mission Energy's
Form 8-K dated July 19, 1999, File No. 1-13434)*
11. Computation of Primary and Fully Diluted Earnings Per Share
27
27. Financial Data Schedule
(b) Reports on Form 8-K:
March 18, 1999 Item 5. Other Events - Homer City Station Acquisition and
Commonwealth Edison Company Acquisition and Investment in
Contact Energy Ltd.*
June 18, 1999 Item 5: Other Events Navajo Nation Lawsuit*
- ---------------------
* Incorporated by reference pursuant to Rule 12b-32.
28
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 THOMAS M. NOONAN
-----------------------------------------
THOMAS M. NOONAN
Vice President and Controller
By KENNETH S. STEWART
-----------------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
August 12, 1999