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, 2000
-------------------------------------------------
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, 2000
---------------------------------------- ------------------------------------
Common Stock, no par value 325,811,206
<PAGE>
EDISON INTERNATIONAL
INDEX
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Page
No.
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Part I.Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income - Three and Six Months
Ended June 30, 2000, and 1999 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2000, and 1999 1
Consolidated Balance Sheets - June 30, 2000,
and December 31, 1999 2
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2000, and 1999 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 11
Part II. Other Information:
Item 1. Legal Proceedings 26
Item 6. Exhibits and Reports on Form 8-K 28
<PAGE>
EDISON INTERNATIONAL
PART I - FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
In thousands, except per-share amounts
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
<S> <C> <C> <C> <C>
Electric utility $ 1,853,024 $ 1,725,705 $ 3,682,716 $ 3,410,539
Nonutility power generation 755,322 269,426 1,506,075 539,236
Financial services and other 140,818 125,768 283,693 267,021
-------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,749,164 2,120,899 5,472,484 4,216,796
-------------------------------------------------------------------------------------------------------------------
Fuel 258,508 116,670 594,012 222,765
Purchased power - contracts 435,429 422,754 863,603 1,032,660
Purchased power - PX/ISO - net 251,641 99,246 323,686 224,546
Provisions for regulatory adjustment clauses - net (97,291) (80,632) 5,662 (360,268)
Other operation and maintenance 828,265 725,966 1,555,823 1,394,043
Depreciation, decommissioning and amortization 485,846 429,518 980,111 853,497
Property and other taxes 30,035 29,678 70,110 68,833
Net gain on sale of utility plant (308) (724) (6,531) (2,925)
-------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,192,125 1,742,476 4,386,476 3,433,151
-------------------------------------------------------------------------------------------------------------------
Operating income 557,039 378,423 1,086,008 783,645
-------------------------------------------------------------------------------------------------------------------
Interest and dividend income 37,657 22,753 62,898 43,124
Other nonoperating income - net 596 17,801 567 13,625
-------------------------------------------------------------------------------------------------------------------
Total other income - net 38,253 40,554 63,465 56,749
-------------------------------------------------------------------------------------------------------------------
Income before interest and other expenses 595,292 418,977 1,149,473 840,394
-------------------------------------------------------------------------------------------------------------------
Interest and amortization on long-term debt 276,623 169,534 532,330 321,353
Other interest expense - net 58,729 35,569 126,707 58,503
Dividends on preferred securities 25,308 4,145 50,552 7,378
Dividends on utility preferred stock 4,571 5,609 10,219 11,808
-------------------------------------------------------------------------------------------------------------------
Total fixed charges 365,231 214,857 719,808 399,042
-------------------------------------------------------------------------------------------------------------------
Minority interest 561 1,046 1,459 2,008
-------------------------------------------------------------------------------------------------------------------
Income before taxes 229,500 203,074 428,206 439,344
Income taxes 92,333 74,652 181,497 167,711
-------------------------------------------------------------------------------------------------------------------
Net income $ 137,167 $ 128,422 $ 246,709 $ 271,633
-------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock
outstanding 331,695 347,204 338,344 347,846
Basic earnings per share $.41 $.37 $.73 $.78
Diluted earnings per share $.41 $.37 $.73 $.78
Dividends declared per common share $.28 $.27 $.56 $.54
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands
3 Months Ended 6 Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 137,167 $ 128,422 $ 246,709 $ 271,633
Cumulative translation adjustments - net (99,737) (29,076) (146,819) (41,714)
Unrealized gain (loss) on securities - net 1,974 (1,876) (4,853) (11,022)
Reclassification adjustment for gains included
in net income (24,487) (14,874) (24,487) (32,245)
-------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 14,917 $ 82,596 $ 70,550 $ 186,652
-------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
1
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
-------------------------------------------------------------------------------------------------------------------
ASSETS (Unaudited)
<S> <C> <C>
Cash and equivalents $ 864,163 $ 507,581
Receivables, including unbilled revenue, less allowances of
$36,007 and $34,164 for uncollectible accounts at respective dates 1,561,366 1,378,422
Fuel inventory 288,568 241,216
Materials and supplies, at average cost 207,263 199,302
Accumulated deferred income taxes - net 527,275 190,508
Prepayments and other current assets 95,767 152,635
-------------------------------------------------------------------------------------------------------------------
Total current assets 3,544,402 2,669,664
-------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision for
depreciation of $610,812 and $445,945 at respective dates 11,857,476 12,352,095
Nuclear decommissioning trusts 2,546,090 2,508,904
Investments in partnerships and unconsolidated subsidiaries 2,642,306 2,504,691
Investments in leveraged leases 1,980,689 1,884,603
Other investments 190,156 180,594
-------------------------------------------------------------------------------------------------------------------
Total investments and other assets 19,216,717 19,430,887
-------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 12,696,730 12,439,059
Generation 1,743,415 1,717,676
Accumulated provision for depreciation and decommissioning (7,701,822) (7,520,036)
Construction work in progress 684,221 562,651
Nuclear fuel, at amortized cost 110,378 132,197
-------------------------------------------------------------------------------------------------------------------
Total utility plant 7,532,922 7,331,547
-------------------------------------------------------------------------------------------------------------------
Unamortized nuclear investment - net 978,262 1,365,848
Income tax-related deferred charges 1,234,694 1,272,947
Regulatory balancing accounts - net 2,258,452 1,714,973
Unamortized debt issuance and reacquisition expense 327,419 339,806
Other deferred charges 1,835,669 2,103,716
-------------------------------------------------------------------------------------------------------------------
Total deferred charges 6,634,496 6,797,290
-------------------------------------------------------------------------------------------------------------------
Total assets $ 36,928,537 $ 36,229,388
-------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
-------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY (Unaudited)
<S> <C> <C>
Short-term debt $ 3,121,518 $ 2,553,376
Current portion of long-term debt 1,499,152 962,041
Accounts payable 657,996 625,347
Accrued taxes 515,968 406,770
Accrued interest 218,121 188,773
Dividends payable 98,124 100,598
Regulatory balancing accounts - net 472,032 75,693
Deferred unbilled revenue and other current liabilities 2,017,020 1,929,589
-------------------------------------------------------------------------------------------------------------------
Total current liabilities 8,599,931 6,842,187
-------------------------------------------------------------------------------------------------------------------
Long-term debt 12,888,661 13,391,636
-------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 6,016,956 5,756,824
Accumulated deferred investment tax credits 203,596 224,636
Customer advances and other deferred credits 1,717,364 2,094,225
Power purchase contracts 505,604 563,459
Other long-term liabilities 639,596 477,313
-------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 9,083,116 9,116,457
-------------------------------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 1 and 2)
Minority interest 11,594 8,778
-------------------------------------------------------------------------------------------------------------------
Preferred stock of utility:
Not subject to mandatory redemption 128,755 128,755
Subject to mandatory redemption 255,700 255,700
Company-obligated mandatorily redeemable securities
of subsidiaries holding solely parent company debentures 948,542 948,238
Other preferred securities 305,534 326,894
-------------------------------------------------------------------------------------------------------------------
Total preferred securities of subsidiaries 1,638,531 1,659,587
-------------------------------------------------------------------------------------------------------------------
Common stock (325,811,206 and 347,207,106
shares outstanding at respective dates) 1,960,521 2,090,212
Accumulated other comprehensive income:
Cumulative translation adjustments - net (136,371) 10,448
Unrealized gain in equity securities - net 1,852 31,192
Retained earnings 2,880,702 3,078,891
-------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 4,706,704 5,210,743
-------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 36,928,537 $ 36,229,388
-------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
3
<PAGE>
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
<TABLE>
<CAPTION>
6 Months Ended
June 30,
-------------------------------------------------------------------------------------------------------------------
2000 1999
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
<S> <C> <C>
Net income $ 246,709 $ 271,633
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 980,111 853,497
Other amortization 90,551 43,195
Deferred income taxes and investment tax credits 7,839 231,562
Equity in income from partnerships and unconsolidated
subsidiaries (95,068) (105,867)
Income from leveraged leases (97,082) (112,618)
Other long-term liabilities 40,311 81,311
Regulatory balancing account - long-term (543,479) (464,267)
Net gain on sale of utility generating plants (26) (1,110)
Other - net (140,416) (17,046)
Changes in Working Capital:
Receivables (223,551) 26,321
Regulatory balancing accounts 396,339 9,283
Fuel inventory, materials and supplies 6,894 (1,596)
Prepayments and other current assets (1,445) 70,791
Accrued interest and taxes 150,136 (92,223)
Accounts payable and other current liabilities 259,043 94,058
Distributions and dividends from unconsolidated entities 66,742 57,276
-------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,143,608 944,200
-------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 2,557,500 2,167,054
Long-term debt repaid (2,183,519) (406,693)
Common stock issued 158 --
Common stock repurchased (385,799) (92,023)
Preferred securities issued -- 202,212
Rate reduction notes repaid (113,179) (119,760)
Short-term debt issued - net 531,673 1,017,893
Dividends paid (188,403) (185,258)
Other - net (21,923) (8,929)
-------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 196,508 2,574,496
-------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (721,102) (570,460)
Purchase of nonutility generating plants -- (1,800,355)
Proceeds from sale of assets 24,960 20,975
Funding of nuclear decommissioning trusts (59,401) (66,424)
Investments in partnerships and unconsolidated subsidiaries (167,507) (716,243)
Unrealized loss on securities - net (29,340) (43,267)
Investments in leveraged leases 12,763 466
Other - net (43,907) 10,985
-------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (983,534) (3,164,323)
-------------------------------------------------------------------------------------------------------------------
Net increase in cash and equivalents 356,582 354,373
Cash and equivalents, beginning of period 507,581 583,556
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 864,163 $ 937,929
-------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
4
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments have been made that are necessary
to present a fair statement of the financial position and results of operations
for the periods covered by this report.
Edison International's significant accounting policies were described in Note 1
of "Notes to Consolidated Financial Statements" included in its 1999 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 1999 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, 2000,
financial statement presentation.
Note 1. Regulatory Matters
Federal Energy Regulatory Commission (FERC) Transmission Rate Case
Southern California Edison Company (SCE) filed its first 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 California Public Utilities
Commission (CPUC) rate for distribution of 11.6%) and a lower revenue
requirement. On July 26, 2000, the FERC issued its final decision adopting SCE's
requested return on equity (11.6%). The FERC decision rejected SCE's proposed
approach for the recovery of a portion of administrative and general and plant
costs related to transmission and instead suggested that SCE seek recovery of
such costs through distribution rates.
Generating Plant Divestiture
In October 1999, SCE filed an application with the CPUC to approve an auction
process to sell its 56% interest in Mohave Generating Station. On April 6, 2000,
the CPUC approved the auction process. On May 10, 2000, SCE agreed to sell its
interest in Mohave to AES Corporation for approximately $533 million. The
transaction is subject to approval by the CPUC and various federal regulatory
agencies. On June 28, 2000, SCE submitted a compliance filing with the CPUC
seeking approval of the auction results and the sale to AES. The sale is
expected to close within the next 12 months.
On April 27, 2000, SCE agreed to sell its 16% interest in Palo Verde Nuclear
Generating Station and its 48% interest in Four Corners Generating Station to
Pinnacle West Energy for a total price of $550 million, subject to certain
adjustments. The sale of assets at Palo Verde will be accompanied by an
assignment of SCE's interest in the related decommissioning fund. Palo Verde is
located in Arizona and Four Corners is located in New Mexico. The transaction is
subject to the approval of the CPUC, the Nuclear Regulatory Commission, the FERC
and other state and federal entities, and to the receipt of a favorable ruling
from the Internal Revenue Service. The Utility Reform Network has filed a
protest with the CPUC recommending that the CPUC reject the sale and require SCE
to retain these generating assets. There can be no assurance that other protests
will not be filed with the CPUC. The transaction is expected to close by
mid-2001. Until the end of November, competing offers may be solicited by SCE,
subject to certain conditions, and any superior offers obtained are subject to
matching rights by Pinnacle West Energy.
5
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Hydroelectric Market Value Filing
In December 1999, SCE filed an application with the CPUC establishing a market
value for its hydroelectric generation-related assets at approximately $1.0
billion (almost twice the assets' book value) and proposing to retain and
operate the hydroelectric assets under a performance-based, revenue-sharing
mechanism. The application had broad-based support from labor, ratepayer and
environmental groups. If approved by the CPUC, SCE would be allowed to recover
an authorized, inflation-indexed operations and maintenance allowance, as well
as a reasonable return on capital investment. A revenue-sharing arrangement
would be activated if revenue from the sale of hydroelectricity exceeds or falls
short of the authorized revenue requirement. SCE would then refund 90% of the
excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers. A
final CPUC decision is expected in 2001.
Note 2. Contingencies
In addition to the matters disclosed in these notes, Edison International is
involved in other legal, tax and regulatory proceedings before various courts
and governmental agencies regarding matters arising in the ordinary course of
business. Edison International believes the outcome of these 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 45
identified sites is $104 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 $281
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. In 1998, SCE 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 44 of its sites,
representing $34 million of its recorded liability, through an incentive
mechanism (SCE may request to include additional sites).
6
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under this mechanism, SCE will recover 90% of cleanup costs through customer
rates; and 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
incurredat SCE's remaining sites are expected to be recovered through customer
rates. SCE has recorded a regulatory asset of $71 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer
rates.
Edison International's identified sites include several sites for which there is
a lack of currently available information, including the nature and magnitude of
contamination, and the extent, if any, that Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $5 million to $15 million. Recorded costs for the twelve-month
period ended June 30, 2000, were $13 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 $9.5
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 $19 million per year. Insurance premiums are charged to operating expense.
7
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Spent Nuclear Fuel
Under federal law, the Department of Energy (DOE) is responsible for the
selection and development of a facility for disposal of spent nuclear fuel and
high-level radioactive waste. Such a facility was to be in operation by January
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 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 additional on-site storage capability, 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. 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.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003
for Unit 2, and until 2004 for Units 1 and 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), a nonutility power generation segment (EME), and a
capital and financial services provider segment (Edison Capital).
Segment information for the three and six months ended June 30, 2000, and 1999,
was:
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended
June 30, June 30,
----------------------------------------------------------------------------------------------------------
In millions 2000 1999 2000 1999
----------------------------------------------------------------------------------------------------------
Operating Revenue:
<S> <C> <C> <C> <C>
Electric utility $ 1,853 $ 1,726 $ 3,683 $ 3,411
Unregulated power generation 755 269 1,506 539
Capital and financial services 68 80 134 163
Corporate and other(1) 73 46 149 104
----------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,749 $ 2,121 $ 5,472 $ 4,217
----------------------------------------------------------------------------------------------------------
Net Income:
Electric utility(2) $ 156 $ 106 $ 270 $ 183
Unregulated power generation (19) 5 (31) 50
Capital and financial services 39 34 77 74
Corporate and other(1) (39) (17) (69) (35)
----------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 137 $ 128 $ 247 $ 272
----------------------------------------------------------------------------------------------------------
</TABLE>
(1) Includes amounts from nonutility subsidiaries not significant as a
reportable segment.
(2) Net income available for common stock.
Total segment assets as of June 30, 2000, were: electric utility, $18.2 billion;
unregulated power generation, $15.5 billion; capital and financial services,
$3.2 billion.
8
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Acquisitions
On March 15, 2000, EME completed its acquisition of Edison Mission Wind Power
Italy B.V., formerly known as Italian Vento Power Corp. Energy 5 B.V. Edison
Mission Wind owns a 50% interest in a series of wind-generated power projects in
operation or under development in Italy. Assuming all of the projects under
development are completed, currently scheduled for 2002, the total capacity of
these projects will be 283 MW. The purchase price of the acquisition was $45
million with equity contribution obligations of up to $16 million, depending on
the number of projects that are ultimately developed.
In May 2000, EME entered into a purchase and sale agreement with P&L Coal
Holdings Corporation and Gold Fields Mining Corporation to acquire the trading
operations of Citizens Power LLC and a minority interest in certain structured
transactions. The purchase price is based on the fair market value of the
trading portfolio and investments, plus $25 million. The acquisition, which is
subject to a number of conditions, including consent of third parties, is
expected to be completed during the third quarter of 2000.
Note 5. Accounting Changes
Effective January 1, 2000, EME changed its accounting method for major
maintenance to record such expenses as incurred. Previously, EME recorded major
maintenance costs on an accrue in advance method. EME voluntarily made the
change in accounting due to recent guidance provided by the Securities and
Exchange Commission. The cumulative effect of the change in accounting method
was an $18 million after-tax benefit.
On January 1, 1999, Edison International implemented a new accounting rule that
requires costs related to start-up activities to be expensed as incurred.
Although this new accounting rule did not materially affect Edison
International's results of operations or financial position, EME wrote off $14
million (after tax) of previously capitalized start-up costs in first quarter
1999.
Note 6. Employee Compensation and Benefit Plans
As disclosed in Edison International's 1999 Annual Report on Form 10-K and
Quarterly Report on Form 10-Q for first quarter 2000, Edison International's
Board of Directors and its Compensation and Executive Personnel Committee
considered an exchange offer of cash and stock equivalent units for outstanding
affiliate options issued by EME and Edison Capital. Such an exchange offer was
reviewed and approved by the Board of Directors at its meetings in January and
February 2000, subject to final approval by the Compensation and Executive
Personnel Committee of the offer terms and documentation. The Compensation and
Executive Personnel Committee and the Board of Directors subsequently concluded
that it was not advisable to make an exchange offer to the holders of EME's
affiliate stock options at that time. During June 2000, the Compensation and
Executive Personnel Committee and the Board of Directors considered the
advisability of a revised exchange offer, and on July 3, 2000, a revised offer
was made to holders of EME and Edison Capital affiliate options. Holders of 100%
of the outstanding affiliate options accepted the exchange offer, and on August
8, 2000, all conditions for completion of the exchange offer were satisfied and
the exchange offer was completed. The exchange is principally for cash with a
portion exchanged for stock equivalent units relating to Edison International
common stock. The vested cash payment will occur on March 13, 2001, and will
accrue interest from August 8, 2000. The number of stock equivalent units was
determined on the basis of a price of $20.50 per share, and the stock equivalent
units will receive dividend equivalents. Participants may elect to convert their
stock equivalent units to a cash value on either the first- or third-year
anniversary of August 8, 2000, for an amount equal to the daily average of the
trading prices of Edison International common stock on the New York Stock
Exchange for the 20 trading days preceding the elected payment date. Some of the
affiliate option holders have elected to defer payments of the cash and stock
equivalent units, and the payment schedules for them will be
9
<PAGE>
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
different from that described above. Since all of the outstanding affiliate
options have been terminated through the exchange offer, there will be no future
exercises of the affiliate options. Due to the lower valuation of the revised
exchange offer compared to the values previously considered, Edison
International will reduce the liability for accrued incentive compensation by
$55 million to $60 million in third quarter 2000.
Note 7. Subsequent Events
On July 18, 2000, Edison International issued $250 million of floating rate
notes due in July 2001.
On July 19, 2000, SCE issued $144 million of pollution control bonds at an
interest rate that is reset daily, due in June 2035. The proceeds of the bonds
are held in trust until October 2000, at which time the funds will be used for
the early retirement of $144 million of pollution control bonds.
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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 41(cent) and 73(cent),
respectively, for the three and six months ended June 30, 2000, compared to
37(cent) and 78(cent) for the same periods in 1999. Southern California Edison's
(SCE) earnings for the three and six months ended June 30, 1999, were 47(cent)
and 80(cent), respectively, up 16(cent) and 27(cent), respectively, over the
year-earlier periods. The increases at SCE were primarily due to the planned
refueling outages at the San Onofre Nuclear Generating Station in the first half
of 1999 (no refueling outages during 2000), combined with superior operating
performance at San Onofre and higher kilowatt-hour sales. Edison Mission Energy
(EME) lost 6(cent) and 9(cent), respectively, compared to earnings of 1(cent)
and 14(cent) for same periods in 1999. The decreases were primarily attributable
to higher interest expense related to EME's 1999 acquisitions. The year-to-date
loss was also due to insufficient earnings from the winter-peaking Fiddler's
Ferry and Ferrybridge plants that were expected to offset the anticipated
seasonal net loss from the summer peaking Illinois plants (acquired from
Commonwealth Edison in December 1999). Edison Capital's earnings were 12(cent)
and 23(cent), respectively, for the three and six months ended June 30, 2000, up
2(cent) over each of the year-earlier periods. The increases at Edison Capital
were due to income from new power and infrastructure investments closed within
the past year. Edison Enterprises and the parent company incurred losses of
12(cent) and 21(cent), respectively, for the quarter and year-to-date period
ended June 30, 2000, compared to losses of 5(cent) and 10(cent) for the
comparable periods in 1999. The decreases in earnings were primarily due to
higher interest expense at the parent company, partially offset by improved
operating performance and lower general and administrative expenses at Edison
Enterprises.
Operating Revenue
As a result of industry restructuring, customers have an option to buy power
from SCE or directly from the California Power Exchange (PX), thus becoming
direct access customers. Most direct access customers continue to be billed by
SCE, but are given a credit for the generation portion of their bills. Electric
utility revenue increased for the three and six months ended June 30, 2000,
compared to the year-earlier periods, almost completely due to warmer weather in
the second quarter of 2000 as compared to the same period in 1999. Over 92% 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.
Nonutility power generation revenue increased for both the three and six months
ended June 30, 2000, compared with the year-earlier periods, primarily due to
increases at EME related to its acquisition of the Ferrybridge and Fiddler's
Ferry plants (July 1999), the Illinois plants (December 1999) and the Homer City
plant (March 1999), and the start of commercial operation of the Doga project in
Turkey.
Due to warmer weather during the summer months, nonutility power generation
revenue from Homer City is usually higher during the third quarter of each year.
In addition, EME's third quarter revenue from unconsolidated energy projects is
usually materially higher than other quarters of the year. EME's higher third
quarter revenue is due to a significant number of its domestic energy projects
located on the western coast of the United States and the Illinois plants, which
generally have power sales contracts that provide for higher payments during
summer months when the weather is warmer. First Hydro and Ferrybridge and
Fiddler's Ferry contribute more to nonutility power generation revenue during
the winter months.
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Financial services and other revenue increased for the quarter and year-to-date
period ended June 30, 2000, compared to the same periods last year, mainly due
to increases reflecting customer growth at two of Edison International's
nonutility subsidiaries (providers of energy management and home security
services), partially offset by a decrease at Edison Capital related to the
syndication of affordable housing investments in 1999.
Operating Expenses
Fuel expense increased for the three and six months ended June 30, 2000,
compared to the same periods in 1999. The increases were primarily due to
increased expenses at EME's plants acquired during 1999 and at EME's Doga
project. These increases were partially offset by a net decrease at SCE related
to a refund for a fuel-related settlement with another utility, partially offset
by an increase in San Onofre's fuel expense. During the first half of 1999, both
of the San Onofre units had a planned refueling outage. There have been no
refueling outages at San Onofre in 2000.
Purchased-power expense - contracts decreased for the six months ended June 30,
2000, compared to the year-earlier period, primarily due to SCE entering into
settlements to end its contractual obligations with certain nonutility
generators (known as qualifying facilities, or QFs) and the terms in some of the
QF contracts reverting to lower prices. Prior to April 1998, SCE was required
under federal law and CPUC orders to enter into contracts to purchase power from
QFs at CPUC-mandated prices even though energy and capacity prices under many of
these contracts are generally higher than other sources. For the twelve months
ended June 30, 2000, SCE paid about $1.0 billion (including energy and capacity
payments) more for these power purchases than the cost of power available from
other sources. SCE is continuing to purchase power under existing contracts from
certain QFs and from other utilities. Power purchases from QFs and other
utilities are sold through the PX.
Since April 1, 1998, SCE has been required to sell all of its generated power
through the PX, schedule delivery of the power through the California
Independent System Operator (ISO) and acquire all of its power from the PX to
distribute to its retail customers. These transactions with the PX and ISO are
reported net. PX/ISO purchased-power expense increased for the three and six
months ended June 30, 2000, compared to the same periods in 1999. During second
quarter 2000, an increased volume of higher priced PX purchases was partially
offset by increases in PX sales revenue and ISO net revenue, as well as an
increase in the market value of gas call options. Increases in the options'
market value decrease purchased-power expense. These gas call options mitigate
SCE's exposure to increases in energy prices. The year-to-date increase was
partially offset by the realization of hydroelectric-related ISO revenue in
first quarter 2000 that had been previously deferred awaiting regulatory
approval. For a further discussion of the recent significant increases in PX
prices, see Market Risk Exposures.
Provisions for regulatory adjustment clauses decreased for the three months
ended June 30, 2000, compared to the year-earlier period, primarily due to
undercollections related to the generation-related balancing accounts.
Provisions for regulatory adjustment clauses increased for the six months ended
June 30, 2000, compared to the same period in 1999, mainly due to
overcollections related to the generation-related balancing accounts and to the
administration of public purpose funds.
Other operation and maintenance expenses increased 14% and 12%, respectively,
for the three and six months ended June 30, 2000, primarily reflecting increased
plant operating expenses at EME's plants acquired in 1999, and increases at two
of Edison International's other nonutility subsidiaries (providers of energy
management and home security services). The increases were partially offset by
decreases at SCE related to its lower mandated transmission service (known as
must-run reliability services) expense, which was caused by SCE being
contractually obligated for fewer must-run units in 2000, compared to 1999, and
lower maintenance expense due to the absence of planned refueling outages at San
Onofre in 2000, as well as a decrease at Edison Capital associated with the
syndication of affordable housing investments in 2000.
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Depreciation, decommissioning and amortization expense increased for both the
three and six months ended June 30, 2000, mainly due to EME's 1999 acquisitions
of the Illinois plants (in December) and the Ferrybridge and Fiddler's Ferry
plants (in July).
As further discussed in Note 6 to the Consolidated Financial Statements, in July
2000 a revised exchange offer was made to holders of EME and Edison Capital
affiliate options. The offer was accepted by all participants. The terms of the
revised exchange offer will result in an approximately $55 million to $60
million reduction in Edison International's accrued incentive compensation
liability during third quarter 2000.
Other Income
Interest and dividend income increased for both the three and six months ended
June 30, 2000, primarily due to increases in interest earned on higher balancing
account undercollections at SCE, partially offset by lower interest income
resulting from SCE's investment balances during the period and a decrease at
Edison Capital due to higher cash balances in 1999.
Other nonoperating income decreased for the three and six months ended June 30,
2000, compared to the year-earlier periods. The quarterly decrease was mainly
due to a mark-to-market loss at EME related to a natural gas swap instrument,
partially offset by the gain on sale of EME's 50% interest in a cogeneration
project in Florida. The year-to date decrease reflects the gains on sales of
equity investments at SCE in the first quarter of 1999, as well as the second
quarter natural gas swap mark-to-market loss at EME, partially offset by a first
quarter 2000 gain on sale of an equity investment at Edison International's
insurance subsidiary, EME's second quarter 2000 gain on sale of the cogeneration
project in Florida and EME's write-off of start-up costs in first quarter 1999.
Fixed Charges and Taxes
Interest and amortization on long-term debt increased for both the quarter and
year-to-date period ended June 30, 2000, compared to the same periods in 1999,
reflecting additional long-term debt at EME to finance its 1999 plant
acquisitions. Increased long-term debt at Edison International (parent company)
also contributed to the increased expense.
Other interest expense increased for the three and six months ended June 30,
2000, mostly due to higher overall short-term debt balances at Edison
International (parent company) and SCE which were necessary to meet general cash
requirements during the periods and higher interest expense related to balancing
account overcollections at SCE. The year-to-date increase also reflects
additional debt financing for EME's 1999 plant acquisitions.
Dividends on preferred securities increased for both the second quarter and
year-to-date period ended June 30, 2000, reflecting the additional issuance of
preferred securities at EME during 1999, and the issuance of quarterly income
securities at Edison International, the parent company, in July and October
1999. Proceeds from the issuances were used primarily to finance EME's 1999
acquisitions of a 40% interest in Contact Energy Ltd., the Fiddler's Ferry and
Ferrybridge plants, and the Illinois plants.
Income taxes increased for the three and six months ended June 30, 2000, as
increases at SCE were partially offset by decreases at EME and Edison
International (parent). SCE's increases were primarily due to higher pre-tax
income. EME's decreases reflect lower earnings in 2000 and Edison
International's decreases were the result of significantly lower pre-tax income.
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.
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Edison International's Board of Directors authorized the repurchase of up to
$2.8 billion of its outstanding shares of common stock. Edison International
repurchased more than 21 million shares (approximately $400 million) of its
common stock through the first six months of 2000. These were the first
repurchases since first quarter 1999. Edison International has now repurchased
approximately 122 million shares ($2.8 billion) between January 1, 1995, and
June 30, 2000, funded by dividends from its subsidiaries. Edison International's
dividend payout ratio for the twelve-month period ended June 30, 2000, was 62%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.1 billion for the six
months ended June 30, 2000, compared to $944 million for the same period in
1999. For the first half of 2000, Edison International's cash flow coverage of
dividends was 6.1 times, compared to 5.1 times for the year-earlier period.
Cash Flows from Financing Activities
At June 30, 2000, Edison International and its subsidiaries had $566 million of
borrowing capacity available under lines of credit totaling $3.0 billion. SCE
had total lines of credit of $1.25 billion, with $1 million available for
short-term debt and $515 million available for the refinancing of its
variable-rate pollution-control bonds. The parent company had total lines of
credit of $618 million, with $0.5 million available. The nonutility subsidiaries
had total lines of credit of $1.1 billion, with $565 million available to
finance general cash requirements. These unsecured lines of credit are at
negotiated or bank index rates with various expiration dates.
EME's short-term and long-term debt are used for general corporate purposes as
well as acquisitions. SCE's short-term debt is used to finance fuel inventories,
balancing account undercollections and general cash requirements. 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 first mortgage trust
indenture. As of June 30, 2000, SCE could issue approximately $11.8 billion of
additional first and refunding mortgage bonds and $2.9 billion of preferred
stock at current interest and dividend rates.
EME has firm commitments of $149 million to make equity and other contributions
for the ISAB project in Italy, the Tri Energy project in Thailand and the
Italian wind projects. EME also has contingent obligations to make additional
contributions of $112 million, primarily for equity support guarantees related
to the Paiton project in Indonesia and the Tri Energy project in Thailand.
EME may incur additional obligations to make equity and other contributions to
projects in the future. EME believes it will have sufficient liquidity to meet
these equity requirements from cash provided by operating activities, proceeds
from the repayment of loans to energy projects and funds available from EME's
revolving line of credit.
Edison Capital has firm commitments of $83 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, 2000, SCE
had the capacity to pay $89 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, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from
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SCE an enforceable right known as transition property. Transition property is a
current property right created by the restructuring legislation and a financing
order of the CPUC and consists generally of the right to be paid a specified
amount from non-bypassable rates charged to residential and small commercial
customers. The rate reduction notes are being repaid over 10 years through these
non-bypassable residential and small commercial customer rates which constitute
the transition property purchased by SCE Funding LLC. The remaining series of
outstanding rate reduction notes have scheduled maturities beginning in 2001 and
ending in 2007, with interest rates ranging from 6.17% to 6.42%. The notes are
secured by the transition property and are not secured by, or payable from,
assets of SCE or Edison International. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities. Although, as
required by generally accepted accounting principles, SCE Funding LLC is
consolidated with SCE and the rate reduction notes are shown as long-term debt
in the consolidated financial statements, 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 18, 2000, Edison International issued $250 million of floating rate
notes due in July 2001.
On July 19, 2000, SCE issued $144 million of pollution-control bonds at an
interest rate that is reset daily, due in July 2035. The proceeds of these bonds
are held in trust until October 2000, at which time the funds will be used for
the early retirement of $144 million of pollution-control bonds.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, purchases and sales of assets, the nonutility companies' investments in
partnerships and unconsolidated subsidiaries, and funding of nuclear
decommissioning trusts. Decommissioning costs are recovered in rates. 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 ($2.1 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 receive SCE
contributions of approximately $25 million per year.
Cash used for the nonutility subsidiaries' investing activities was $417 million
for the six-month period ended June 30, 2000, compared to $2.7 billion for the
same period in 1999. The decrease in 2000 reflects EME's plant acquisitions in
the first half of 1999.
Projected Capital Requirements
Edison International's projected construction expenditures for the next five
years are: 2000 - $1.5 billion; 2001 - $1.4 billion; 2002 - $1.2 billion; 2003 -
$1.0 billion; and 2004 - $980 million.
Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following June 30, 2000, are: 2001 - $1.5 billion; 2002 -
$841 million; 2003 - $797 million; 2004 - $578 million; and 2005 - $724 million.
Preferred stock redemption requirements for the five twelve-month periods
following June 30, 2000, are: 2001- zero; 2002 - $105 million; 2003 - $9
million; 2004 - $9 million; and 2005 - $9 million.
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.
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SCE Issues
As a result of the rate freeze established in the 1996 restructuring
legislation, SCE's transition costs are recovered as the residual component of
rates once the costs for distribution, transmission, public benefit programs,
nuclear decommissioning and the cost of supplying power to its customers through
the PX and ISO have already been recovered. Accordingly, more revenue generally
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 effects of higher prices on
transition cost revenue are mitigated to some extent by increased revenue on
energy sold to the PX from SCE-controlled generation sources. The PX and ISO
market prices to date have generally been consistent, although some irregular
price spikes have occurred, and during second quarter 2000, there were sustained
periods during which market prices diverged from the level of prices that should
have come from properly functioning competitive markets. The ISO has responded
to price spikes in the market for reliability services (referred to as ancillary
services) by imposing a price cap 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 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 price cap instituted by the ISO in the summer of 1998 was $250/MWh. In
October 1999, that cap was raised to $750/MWh. The ISO decided to reduce the cap
on imbalance energy and ancillary services to $500/MWh effective July 1, 2000,
and to $250/MWh effective August 7, 2000. The ISO further reduced the cap on
replacement reserves to $100/MWh, also effective July 1, 2000. These price cap
reductions were a response to sustained significantly higher prices in the
energy and ancillary services markets, beginning in May 2000. Reacting to the
recent price increases, which have continued throughout the summer of 2000,
government and regulatory bodies including the FERC, the CPUC, the California
Electricity Oversight Board, the California Legislature and the California
Attorney General, have launched or announced investigations or other actions
relating to aspects of the electricity markets. SCE cannot predict what actions
any of these bodies may take or the potential effects of their actions.
In 1997, SCE bought gas call options to mitigate its exposure to increases in
energy costs. In July 1999, SCE began participating in forward purchases through
a PX block forward market. In the PX block forward market, SCE can purchase
monthly blocks of energy or ancillary services for six days a week (excluding
Sundays and holidays) for 8 to 16 hours a day. These purchases can be made up to
12 months in advance of the delivery date. The CPUC originally limited SCE's use
of the PX block forward market to a maximum of approximately 2,000 MW in any
month. The PX requested and was granted authority from the FERC to sell other
forward products including a peak product, six days a week, for eight hours a
day. In March 2000, the CPUC approved SCE's request for rate-making treatment
for its use of these additional products and for an expansion of the limits from
all forward PX products up to 5,200 MW in summer months. In April 2000, the CPUC
approved SCE's request to begin a demand responsiveness program that would allow
customers to be paid to curtail their load during times of very high PX energy
prices. On August 3, 2000, the CPUC approved SCE's request to enter into
bilateral contracts for delivery of electricity.
EME Issues
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 a number of its project
financings. Interest expense includes $10 million and $13 million, respectively,
for the six months ended June 30, 2000, and June 30, 1999, as a result of
interest rate swap and collar agreements. Several of EME's interest rate swap
and collar agreements mature prior to their underlying debt.
EME hedges a portion of the electric output of its plants in order to lock in
desirable outcomes. EME also manages the margin between electric prices and fuel
prices when deemed appropriate. EME uses forward contracts, swaps, futures or
option contracts to achieve these objectives.
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Projects in the U.K. 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 10 or more over the course of a few hours due to large
differentials in demand according to the time of day. First Hydro and
Ferrybridge and Fiddler's Ferry mitigate 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 their net exposure to pool price volatility. A proposal to replace
the current structure of the pool and the forward-contracts market to require
firm physical delivery has been made by the Director General of Electricity
supply, at the request of the Minister for Science, Energy and Industry in the
U.K. The Minister has recommended that the proposal be implemented by October
2000. This proposal has placed a significant downward pressure on forward
contract prices. Legislation in the form of a Utilities Bill, published on
January 20, 2000, is being introduced to allow for the implementation of new
trading arrangements and the necessary amendments to generators' licenses. A
warmer than average winter, the entry of new operations into the generation
market, the introduction of the new electricity trading arrangements coupled
with uncertainties surrounding the new Utilities Bill and a proposed "good
behavior" clause, discussed below, have depressed anticipated prices for winter
2000/2001. As a result of these events, EME expects lower than anticipated
revenue from its Ferrybridge and Fiddler's Ferry plants.
The Utilities Bill, which includes several consumer and environmental protection
measures became law in July 2000. While the U.K. government recognizes the need
to strike a balance between consumer and shareholder interests, the proposals
have far-reaching implications for the utilities sector.
In December 1999, the U.K. Director General of Electricity Supply gave notice of
an intention to introduce a new condition into the licenses of a number of
generators to curb the perceived exercise of market power in the determination
of wholesale electricity prices. The majority of the major generators have
accepted the new clauses, including EME, which has sought and received specific
assurances from the Regulator on the definition of market abuse and the way the
clauses will be interpreted in the future.
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 Pool (PJM) or the New
York Independent System Operator (NYISO). The PJM pool has a market that
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 NYISO markets. Power can also be transmitted to the mid-western United
States.
Commonwealth Edison (ComEd) entered into purchase power agreements in which
ComEd will purchase capacity and have the right to purchase energy generated by
the Illinois plants. The agreements, which began in December 1999, and have a
term of up to five years, provide for capacity and energy payments. ComEd will
be obligated to make a capacity payment for the units under contract and an
energy payment for the electricity produced by these units. The capacity payment
will provide the Illinois plants revenue for fixed charges, and the energy
payment will compensate the Illinois plants for variable costs of production. If
ComEd does not fully dispatch the units under contract, the Illinois plants may
sell, subject to certain conditions, the excess energy at market prices to
neighboring utilities, municipalities, third party electric retailers, large
consumers and power marketers on a spot basis.
Loy Yang B sells its electrical energy through a centralized electricity pool,
which provides for a system of generator bidding, central dispatch and a settle-
ments system based on a clearing market for each half-hour of every day. The
National Electricity Market Management Company, operator and administrator of
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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, 53% to 64% of the plant output sold is hedged under vesting contracts,
with the remainder of the plant capacity hedged under the State Government of
Victoria, Australia (State) hedge described below. Vesting contracts were put
into place by the State, between each generator and each distributor, prior to
the privatization of electric power distributors in order to provide more
predictable pricing for those electricity customers that were unable to choose
their electricity retailer. Vesting contracts set base strike prices at which
the electricity will be traded, and the parties to the agreement make payments,
calculated based on the difference between the price in the contract and the
half-hourly pool clearing price for the element of power under contract. These
contracts 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.
EME's electric revenue increased by $39 million for the six months ended June
30, 2000, compared to an increase of $20 million for the same period in 1999, 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 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
macro-economic variables will behave in a manner that is consistent with
historical or forecasted relationships.
Paiton Project
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. 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 project
received substantial finance and insurance support from the Export-Import Bank
of the United States, the Japan Bank of International Cooperation (formerly
known as The Export-Import Bank of Japan), the U.S. Overseas Private Investment
Corporation and the Ministry of International Trade and Industry of Japan. The
projected rate of growth of the Indonesian economy and the exchange rate of
Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The 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. Certain events have occurred (including
those discussed in the subsequent paragraph) which, with the passage of time or
upon notice, may mature into defaults of the project's debt agreement. In
October 1999, the project entered into an interim agreement with its lenders, in
which the lenders waived such defaults until July 31, 2000. The term of the
interim agreement has been extended to December 31, 2000. However, such waiver
may expire on an earlier date if additional defaults (other than those
specifically waived) or certain other specified events occur.
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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 through February 2000; 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. The state-owned electricity company has not
paid invoices amounting to $561 million for capacity charges and fixed operating
costs under the power purchase agreement.
On February 21, 2000, Paiton and the state-owned electricity company executed an
Interim Agreement in which the power purchase agreement will be administered
pending a long-term restructure of the power purchase agreement. Among other
things, the Interim Agreement provides for dispatch of the project, fixed
monthly capacity payments to Paiton by the state-owned electricity company, and
the standstill of any further legal proceedings by either party during the term
of the Interim Agreement which runs through December 31, 2000, and may be
extended by mutual agreement. To date, the state-owned electricity company has
made timely payments of the fixed capacity totaling $45 million. Invoicing under
the power purchase agreement will continue to accrue (minus the fixed monthly
capacity payments under the Interim Agreement) and will be dealt with under the
overall tariff restructuring negotiations. The state-owned electricity company
and Paiton have entered into negotiations on a long-term restructuring of the
tariff but no final agreement has been reached to date. 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 Acquisition
In May 2000, EME entered into a purchase and sale agreement with P&L Coal
Holdings Corporation and Gold Fields Mining Corporation to acquire the trading
operations of Citizens Power LLC and a minority interest in certain structured
transactions. The purchase price is based on the fair market value of the
trading portfolio and investments, plus $25 million. The acquisition, which is
subject to a number of conditions, including consent of third parties, is
expected to be completed during the third quarter of 2000.
SCE's 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 continues to
change as California moves toward a more competitive climate. SCE continues to
recover its stranded costs associated with generation-related assets through an
authorized competition transition charge (CTC). California's electric industry
restructuring statute 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.
Revenue is determined by various mechanisms depending on the utility operation.
Generation
Revenue from generation-related operations is being determined through the
market and the CTC mechanism, which now includes the nuclear rate-making
agreements. The portion of revenue related to fossil generation operations 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.
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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 2000, fossil and hydroelectric generation assets have the opportunity to earn
a 7.22% return. SCE has filed applications with the CPUC regarding the market
valuation of all of its non-nuclear generating facilities. See additional
discussions below regarding hydroelectric valuation, Mohave Generating Station
auction and pending sale, and pending Four Corners Generating Station sale.
SCE is recovering its investment in its nuclear facilities on an accelerated
basis 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, 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. SCE has entered into
an agreement to sell its investment in Palo Verde (see further discussion
below).
In October 1999, SCE filed an application with the CPUC to approve an auction
process to sell its 56% interest in Mohave Generating Station. On April 6, 2000,
the CPUC approved the auction process. On May 10, 2000, SCE agreed to sell its
interest in Mohave to AES Corporation for approximately $533 million. The
transaction is subject to approval by the CPUC and various federal regulatory
agencies. On June 28, 2000, SCE submitted a compliance filing with the CPUC
seeking approval of the auction results and the sale to AES. The sale is
expected to close within the next 12 months.
In December 1999, SCE filed an application with the CPUC establishing a market
value for its hydroelectric generation-related assets at approximately $1.0
billion (almost twice the assets' book value) and proposing to retain and
operate the hydroelectric assets under a performance-based, revenue-sharing
mechanism. The application has broad-based support from labor, ratepayer and
environmental groups. If approved by the CPUC, SCE would be allowed to recover
an authorized, inflation-indexed operations and maintenance allowance, as well
as a reasonable return on capital investment. A revenue-sharing arrangement
would be activated if revenue from the sale of hydroelectricity exceeds or falls
short of the authorized revenue requirement. SCE would then refund 90% of the
excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers. A
final CPUC decision is expected in 2001.
On April 27, 2000, SCE agreed to sell its 16% interest in Palo Verde and its 48%
interest in Four Corners Generating Station to Pinnacle West Energy for a total
price of $550 million, subject to certain adjustments. The sale of assets at
Palo Verde will be accompanied by an assignment of SCE's interest in the related
decommissioning fund. Palo Verde is located in Arizona and Four Corners is
located in New Mexico. The transaction is subject to the approval of the CPUC,
the Nuclear Regulatory Commission, the FERC and other state and federal
entities, and to the receipt of a favorable ruling from the Internal Revenue
Service. The Utility Reform Network has filed a protest with the CPUC
recommending that the CPUC reject the sale and require SCE to retain these
generating assets. There can be no assurance that other protests will not be
filed with the CPUC. The transaction is expected to close by mid-2001. Until the
end of November, competing offers may be solicited by SCE, subject to certain
conditions, and any superior offers received are subject to matching rights by
Pinnacle West Energy.
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Accounting for Generation-Related Assets
As the CPUC's electric industry restructuring plan continues as described above,
SCE is allowed to recover its transition costs through non-bypassable charges to
its distribution customers (although its investment in certain generation assets
is subject to a lower authorized rate of return). In 1997, SCE discontinued
application of accounting principles for rate-regulated enterprises for its
generation assets 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 because the restructuring plan referred to above made probable
their recovery through a non-bypassable charge to distribution customers. The
regulatory assets are comprised 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, SCE reduced its remaining nuclear plant investment by $2.6 billion (as
of June 30, 1998) and recorded 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 expected future net cash flows. This
reclassification had no effect on SCE's results of operations.
Status of Stranded-Asset Recovery
SCE's transition costs arise from QF contracts (which are the direct result of
prior legislative and regulatory mandates) costs pertaining to certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the recovery
of income tax benefits previously flowed through to customers, postretirement
benefit transition costs, accelerated recovery of investments in San Onofre
Units 2 and 3 and the Palo Verde units, and certain other costs. Transition
costs related to power-purchase contracts are being recovered through the terms
of each contract. Most of the remaining transition costs may be recovered
through the end of the transition period, March 31, 2002.
SCE's transition costs are being recovered principally through a non-bypassable
CTC. This charge applies to customers who were using or began using utility
services on or after the CPUC's 1995 restructuring decision date. Revenue from
the sale or valuation of generation assets in excess of book value is also
applied to recovery of transition 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 reduced stranded
costs, which otherwise were expected to be collected through the CTC mechanism.
Sales or valuations of other generating assets are discussed above. In addition,
net market revenue from sales of power and capacity from SCE-controlled
generation sources is applied to transition cost recovery.
CTC revenue is determined residually (i.e., CTC revenue is the residual amount
remaining from monthly gross customer revenue under the rate freeze after
subtracting the revenue requirements for transmission, distribution, nuclear
decommissioning and public benefit programs, and ISO payments and power
purchases from the PX). Increases in market prices for electricity affect SCE in
two fundamental ways. First, CTC revenue decreases because there is less or no
residual revenue from frozen rates due to higher cost PX power purchases.
Second, transition costs decrease because there is increased net market revenue
due to sales from SCE-controlled generation sources to the PX at higher prices.
Although the second effect mitigates the first to some extent, the overall
impact on transition cost recovery is negative because SCE purchases more power
than it sells to the PX. In addition, higher market prices for electricity may
adversely affect SCE's ability to recover non-transition costs during the rate
freeze period. For example, if market prices for electricity are extremely high
in a given month, residual CTC revenue may be negative, which means there was
insufficient revenue from customers under the frozen rates to
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cover all costs of providing service during that month. Under existing CPUC
decisions, this undercollection in the transition revenue account is carried
forward and recovered from future positive CTC revenue.
Since the beginning of the rate freeze (January 1, 1998), SCE has had positive
CTC revenue of $4.1 billion to recover its transition costs. As the result of
sustained higher market prices which began in May 2000 (further discussed in
Market Risk Exposures), SCE experienced the first month in which there was
negative CTC revenue. SCE continued to have negative CTC revenue in June and
July 2000. To date, the CPUC has denied SCE requests to allow recovery of the
transition revenue account undercollections after the end of the rate freeze.
SCE is currently reassessing the significance of the current undercollections
and may renew requests to the CPUC to modify certain rate-making practices.
As of June 30, 2000, the book value of stranded assets to be recovered by the
end of the rate freeze, less estimated credits from the market valuation or
pending sale of remaining generation assets, is as follows:
In millions
-------------------------------------------------------------------------
Unamortized nuclear investment - net $ 978
Unamortized loss on sale of plant 91
Transition-related balancing accounts 424
Transition revenue account 644
Flow-through taxes 170
Other regulatory assets 40
-------------------------------------------------------------------------
Total regulatory assets 2,347
Book value of remaining generation plant 392
-------------------------------------------------------------------------
Total stranded assets 2,739
Less estimated credits:
Excess of market value over book for hydro assets (500)
Proceeds from pending sale of generating plants (1,083)
-------------------------------------------------------------------------
Net amount of stranded assets $ 1,156
-------------------------------------------------------------------------
As of July 31, 2000, SCE's transition revenue account undercollection was $1.1
billion and its transition-related balancing accounts undercollections were $261
million.
Despite the rate freeze, SCE expects to recover its revenue requirement during
the transition period. The following factors may affect the amount of revenue
available to recover both transition and non-transition costs: the market prices
of gas and electricity; the ultimate selling price for the Palo Verde and Four
Corners generating assets; the outcome of SCE's hydroelectric filing; ISO rate
caps; economic conditions; weather conditions; and actions of governmental and
regulatory bodies. If during the transition period events were to occur that
make the recovery of any of SCE's costs no longer probable, SCE would be
required to write off the unrecoverable portion as a one-time charge against
earnings.
Distribution
Revenue related to distribution operations is determined through a
performance-based rate-making (PBR) mechanism and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution 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.
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In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of CTC recovery. On July 7, 2000, SCE updated
this filing with more recent information. The proposal seeks CPUC approval of a
rate redesign that will result in reduced rates for most customers when SCE
completes the first phase of recovery of its transition costs. The proposed new
rates are expected to reduce SCE's system average rates by about 12% from
current frozen rate levels, based on certain assumptions about competitive
energy prices and unbundled revenue requirements for 2002. In addition, SCE's
filing proposes to redesign and establish separate transmission and distribution
rates to better reflect the actual costs to deliver electricity and serve
customers by recovering the fixed costs of delivering electricity in fixed
charges. This pricing approach is consistent with CPUC policies requiring
California's major utilities to move toward cost-based transmission and
distribution rates.
Transmission
Transmission revenue is determined through FERC-authorized rates and is subject
to refund. In March 1997, SCE filed its first FERC transmission rate case. In
response to a FERC ruling, in November 1999, SCE filed additional evidence
regarding return on equity. On July 26, 2000, the FERC issued its final decision
adopting SCE's requested return on equity of 11.6% and a 9.29% return on
transmission assets. The FERC decision rejected SCE's proposed approach for the
recovery of a portion of administrative and general costs and plant costs
related to transmission, and instead suggested that SCE seek recovery of such
costs through distribution rates.
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's recorded estimated minimum liability to
remediate its 45 identified sites is $104 million. Edison International believes
that, due to uncertainties inherent in the estimation process, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to $281
million. In 1998, SCE sold all of its gas- and oil-fueled power plants but has
retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 44 of its sites,
representing $34 million of its recorded liability, through an incentive
mechanism, which is discussed in Note 2. SCE has recorded a regulatory asset of
$71 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. As a result, 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. Recorded costs for the twelve months ended June 30, 2000, were $13
million.
Based on currently available information, Edison International believes it is
unlikely that it will incur amounts in excess of the upper limit of the
estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs ultimately
recorded will not materially affect its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of
new sites, will not require material revisions to such estimates.
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The 1990 Federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions allowances
from the federal government and may bank or sell excess allowances. SCE expects
to have excess allowances under Phase II of the Clean Air Act (2000 and later).
A 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. In June 1999, the Environmental Protection Agency
(EPA) issued an advanced notice of proposed rulemaking regarding assessment of
visibility impairment at the Grand Canyon. SCE filed comments on the proposed
rulemaking in November 1999. In 1998, several environmental groups filed suit
against the co-owners of the Mohave station regarding alleged violations of
emissions limits. In order to accelerate resolution of key environmental issues
regarding the plant, the parties filed, in concurrence with SCE and the other
station owners, a consent decree, which was approved by the court in December
1999. In a letter to SCE, the EPA has expressed its belief that the controls
provided in the consent decree will likely resolve the potential Clean Air Act
visibility concerns. The EPA is considering incorporating the decree into the
visibility provisions of its Federal Implementation Plan for Nevada.
Edison International's projected environmental capital expenditures are $1.6
billion for the 2000-2004 period, mainly for undergrounding certain transmission
and distribution lines at SCE and upgrading environmental controls at EME.
San Onofre Steam Generator Tubes
The San Onofre Units 2 and 3 steam generators have performed relatively well
through the first 16 years of operation. 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. Increased tube degradation was found during routine inspections in
1997. To date, 7.5% of Unit 2's tubes and 5.4% of Unit 3's tubes have been
removed from service. A decreasing (favorable) trend in degradation has been
observed in more recent inspections.
Accounting Changes
Effective January 1, 2000, EME changed its accounting method for major
maintenance to record such expenses as incurred. Previously, EME recorded major
maintenance costs on an accrue in advance method. EME voluntarily made the
change in accounting due to recent guidance provided by the Securities and
Exchange Commission. The cumulative effect of the change in accounting method
was an $18 million after-tax benefit.
On January 1, 1999, Edison International implemented a new accounting rule that
requires costs related to start-up activities to be expensed as incurred.
Although this new accounting rule did not materially affect Edison
International's results of operations or financial position, EME wrote off $14
million (after tax) of 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 Edison International
will be required to implement on 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.
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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 including the sale or retention and ongoing operation of remaining
generation assets; the effects, unfavorable interpretations and applications of
new or existing laws and regulations relating to restructuring, taxes and other
matters; the effects of increased competition in the electric utility business
and other energy-related businesses, 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
financial market conditions; risks of doing business in foreign countries, such
as political changes and currency devaluations; power plant construction and
operation risks; the ability to sell or retain electric generation assets; the
ultimate selling price of those plants that are sold; new or increased
environmental liabilities; the amount of revenue available to recover both
transition and non-transition costs; the ability to create and expand new
businesses, such as telecommunications; weather conditions; and other unforeseen
events.
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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."
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. SCE seeks damages for excess power purchase payments made to
the Coso parties and other relief. The Coso parties' motion to transfer venue to
Inyo County Superior Court was granted on August 31, 1997.
The Coso parties filed a cross-complaint against SCE, The Mission Group, and
Mission Power Engineering Company (Mission parties), which contains claims for
breach of contract, unfair competition, interference with contract, defamation,
breach of an earlier settlement agreement between the Mission parties and the
Coso parties, and other claims. As against SCE, the 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. As against the Mission parties, the
cross-complaint seeks damages for breach of warranty of authority with respect
to the settlement agreement, and for equitable indemnity. Edison International
was named as a cross-defendant, allegedly as an alter ego of SCE and the Mission
parties. The Coso parties voluntarily dismissed the claims against Edison
International.
Three of the Coso parties also filed a separate action in the Inyo County
Superior Court against SCE and Edison International, alleging claims for unfair
competition, false advertising and for violations of Public Utilities Code ss.
2106, and seeking injunctive relief, restitution, and punitive damages. The
Court ordered this action consolidated with the SCE action.
Effective February 8, 2000, the parties entered into confidential agreements
resolving all claims in the consolidated action and calling for dismissals with
prejudice and releases. The settlement is subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings
during the period required to obtain CPUC approval. On April 26, 2000, SCE filed
an application to obtain such approval. The period for protesting the
application has passed and no person has filed a protest. SCE expects a decision
on the application later this year. The settlement is not expected to have a
material financial effect on SCE.
San Onofre Personal Injury Litigation
As previously reported in Part I, Item 3, of the Registrant's Annual Report on
Form 10-K for the year ending December 31, 1999, SCE is actively involved in
three lawsuits claiming personal injuries allegedly resulting from exposure to
radiation at San Onofre.
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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 Appeal, 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.
On July 20, 2000, the Ninth Circuit issued an opinion reversing the trial
court's judgment and ordering a retrial as to both defendants. The Court of
Appeals concluded that the jury instructions were flawed and unfairly prejudiced
plaintiffs and that the trial court erroneously dismissed the products liability
claims against Combustion Engineering. The Ninth Circuit did not decide the
merits of plaintiffs' claims. This decision, if not vacated or altered on
rehearing or other further proceedings, would constitute a "favorable
determination" for plaintiffs in both of the other cases at the U.S. District
Court level (respectively mentioned in the immediately preceding and immediately
following paragraphs), for purposes of the stay agreement described below. SCE
and Combustion Engineering intend to seek rehearing before the Ninth Circuit.
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 the matter have been stayed.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the
cases 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
Appeal. 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 District Court cases will be set for
trial. On March 23, 1999, the District Court approved the parties' stay
agreement in both cases. The stay will remain in effect until the conclusion of
the appellate process, including filing and disposition of any petitions for
rehearing in the Ninth Circuit or petitions for certiorari in the United States
Supreme Court.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot be determined
at this time.
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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,
1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of
Directors on February 17, 2000 (File No. 1-9936, filed as Exhibit 3.3
to Form 10-K for the year ended December 31, 1999)*
10.1 Edison International 2000 Equity Plan
10.2 Form of Agreement for 2000 Employee Awards under the 2000 Equity Plan
10.3 Form of Agreement for 2000 Director Awards under the Equity
Compensation Plan
10.4 Amendment No. 1 to the Edison International Equity Compensation Plan
(as restated January 1, 1998)
11 Computation of Basic and Fully Diluted Earnings per Share
27 Financial Data Schedule
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended June 30, 2000.
---------------------
* Incorporated by reference pursuant to Rule 12b-32.
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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 11, 2000
