EXHIBIT 13
EDISON INTERNATIONAL
SELECTED PORTIONS OF
1996 ANNUAL REPORT TO SHAREHOLDERS
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EDISON INTERNATIONAL AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF REPORTS OF OPERATION AND FINANCIAL
CONDITION
In the following Management's Discussion and Analysis of Results of
Operations and Financial Condition and elsewhere in this annual report,
the words "estimates," "expects," "anticipates," "believes," and other
similar expressions, are intended to identify forward-looking information
that involves risks and uncertainties. Actual results or outcomes could
differ materially as a result of such important factors as the outcome of
state and federal regulatory proceedings affecting the restructuring of
the electric utility industry, the impacts of new laws and regulations
relating to restructuring and other matters, the effects of increased
competition in the electric utility business, and changes in prices of
electricity and costs for fuel.
Results of Operations
Earnings
Edison International's 1996 earnings per share were $1.64, compared with
$1.66 in 1995 and $1.52 in 1994. Southern California Edison (SCE)
contributed $1.42 per share, compared with $1.44 in 1995 and $1.34 in
1994. Edison Mission Energy (EME), Edison Capital and Mission Land
Company contributed, on a combined basis, 27 cents in 1996 compared with
23 cents in 1995 and 19 cents in 1994. Edison International's earnings
include special charges of 6 cents in 1996 (a 4 cent net charge at SCE
for workforce management costs and reserves, a 2 cent charge at EME for
operating reserves, and a 3 cent charge for real estate reserves at
Mission Land, partially offset by a 3 cent gain on the sale of four
geothermal projects at EME) and 3 cents in 1995 for SCE's workforce
management charges. The decline in net income in 1996 was offset by a
common stock repurchase program. The reduced number of outstanding shares
resulted in a 3 cent per-share benefit in 1996 compared with 1995.
During 1996, Edison International formed three new businesses, Edison
Source, Edison EV and Edison Select. Expenses associated with the start-
up of these new businesses, together with the parent company's interest
payments on $350 million in borrowings, related to EME's acquisition of
First Hydro and its ongoing share repurchase program, were responsible for
5 cents per share of expenses (after tax) compared to 1 cent in 1995.
1996 vs. 1995
Excluding special charges, SCE's 1996 earnings were $1.46, down 1 cent
from 1995. The decrease is mainly attributable to a reduction in
authorized rates of return and operating expenses, partially offset by
improved operating performance. The combined 1996 earnings of EME, Edison
Capital and Mission Land, excluding special charges, were 29 cents per
share, 6 cents higher than 1995. The increase is primarily attributable
to earnings from EME's First Hydro project in the United Kingdom. First
Hydro was acquired in December 1995.
1995 vs. 1994
SCE's 1995 earnings before nonrecurring charges were $1.44, up 10 cents
over 1994, primarily due to a higher authorized return on common equity
for 1995, partially offset by the effect of the 1995 general rate case
settlement. SCE recorded workforce management costs of 3 cents per share
in 1995 compared with 4 cents in 1994. The nonutilities' 1995 earnings
were 23 cents, up 4 cents from 1994, reflecting improved results from
EME's energy projects and increased investment activity at Edison Capital.
The parent company incurred expenses (after-tax) of 1 cent per share in
both 1995 and 1994.
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Operating Revenue
Electric utility revenue decreased 4% from 1995, as increased sales volume
was offset by lower average rates. The lower rates are attributable to
the California Public Utilities Commission's (CPUC) decision to lower
SCE's 1996 authorized revenue by 4.4%. Additionally, during 1996 SCE
issued a one-time bill credit of $237 million to ratepayers as part of a
CPUC-ordered refund of energy-cost balancing account overcollections.
Electric utility revenue in 1995 increased slightly over 1994, as a 2.6%
authorized rate increase was partially offset by a decrease in sales
volume to resale cities and milder weather in 1995. Over 98% of SCE's
operating revenue is from retail sales. Retail rates are regulated by the
CPUC and wholesale rates are regulated by the Federal Energy Regulatory
Commission (FERC).
Due to warm weather during the summer months, electric utility revenue
during the third quarter of each year is materially higher than the other
quarters.
The changes in electric utility revenue resulted from:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Electric utility revenue -
Rate changes $ (522) $ 168 $ 112
Sales volume changes 206 (129) 308
Other 26 35 (18)
------- ------ ------
Total $ (290) $ 74 $ 402
======= ====== ======
In March 1995, SCE announced its intention to freeze average rates for
residential, small business and agricultural customers through 1996, and
announced a five-year goal to reduce system average rates by 25% on an
inflation-adjusted basis (from 10.7 cents per kilowatt-hour to below
10 cents per kilowatt-hour). In February 1996, the CPUC approved a
system-wide rate reduction which will drop the average price per kilowatt-
hour from 10.7 cents to 10.1 cents. Legislation enacted in September 1996
provides for, among other things, at least a 10% rate reduction for
residential and small commercial customers beginning in 1998 (see
Competitive Environment).
Revenue from diversified operations increased substantially during 1996
due to an increase in EME's electric revenue from its First Hydro, Iberian
Hy-Power and Loy Yang B Unit 2 projects. Revenue from diversified
operations decreased 3% in 1995 from 1994. The 1995 decline was mainly
due to a decrease at Mission Land, as it sold several of its real estate
holdings in 1994. The decline was partially offset by an increase in
electric revenue at EME's First Hydro and Roosecote projects. Roosecote
was out of service for four months in 1994 due to transformer failure and
scheduled maintenance.
Operating Expenses
Fuel expense increased 11% in 1996, compared to the same period in 1995,
primarily due to higher gas prices and changes in the fuel mix. EME's
fuel expense increased due to the inclusion of fuel costs related to First
Hydro (a pumped storage facility), Loy Yang B Unit 2 and Kwinana. Fuel
expense decreased 23% in 1995 from 1994, as hydro generation was up
significantly in 1995 due to greater rainfall, resulting in lower gas
purchases. In addition, the San Onofre Nuclear Generating Station units
were out of service a total of five months in 1995 for refueling and
maintenance, causing a decrease in nuclear fuel expense. The decline at
SCE was partially offset by an increase at EME, as its Roosecote project
operated for a full year in 1995 after experiencing transformer failure
and scheduled maintenance for four months in 1994.
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Purchased-power expense increased slightly in 1996 and 1995, due to an
increase in power purchased under federally mandated contracts. SCE is
required under federal law to purchase power from certain nonutility
generators even though energy prices under these contracts are generally
higher than other sources. In 1996, SCE paid about $1.7 billion
(including energy and capacity payments) more for these power purchases
than the cost of power available from other sources. The CPUC has
mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially in
1996, compared to 1995. The decrease is mainly due to the energy-cost
balancing account-related refund discussed above, lower base rate revenue
and undercollections related to the accelerated recovery of SCE's
remaining investment in San Onofre Units 2 and 3 (see discussion in Note
1 to the Consolidated Financial Statements). The provisions increased in
1995 over 1994, as CPUC-authorized fuel and purchased-power cost estimates
exceeded SCE's actual energy costs. SCE's actual energy costs were lower
than estimated in 1995 due to the increase in hydro generation and lower
gas prices.
Other operating expenses increased 10% in 1996 when compared with 1995,
as increased operating costs at EME's First Hydro, Iberian Hy-Power and
Loy Yang B Unit 2 projects offset cost reductions and improved operating
efficiencies at SCE. Other operating expenses decreased in 1995 when
compared to 1994, primarily due to operating efficiencies at SCE. These
decreases were partially offset by an increase at EME from its acquisition
of First Hydro.
Maintenance expense decreased 8% in 1996, due to lower overall costs at
SCE's generation, transmission and distribution operating facilities.
Maintenance expense increased 8% in 1995, due to higher expenses related
to the scheduled refueling and maintenance outages at San Onofre Units 2
and 3.
Depreciation and decommissioning expense increased 16% in 1996 due to
higher depreciation rates, the accelerated recovery of San Onofre Units
2 and 3, and increases at EME related to its First Hydro, Loy Yang B Unit
2 and Iberian Hy-Power projects.
Income taxes increased 7% during 1996, mainly due to an increase in the
deferred tax provision related to the accelerated recovery of San Onofre
Units 2 and 3 and increased earnings at EME from its First Hydro project.
Earnings from First Hydro are subject to a higher effective tax rate than
the federal statutory rate.
Other Income and Deductions
The provision for rate phase-in plan reflects a CPUC-authorized, 10-year
rate phase-in plan, which deferred the collection of revenue during the
first four years of operation for the Palo Verde Nuclear Generating
Station. The deferred revenue (including interest) is being collected
evenly over the final six years of each unit's plan. The plan ended in
February 1996 and September 1996 for Units 1 and 2, respectively. The
plan ends in January 1998 for Unit 3. The provision is a non-cash offset
to the collection of deferred revenue.
Minority interest expense increased 46% during 1996, primarily from higher
pre-tax income at EME's Loy Yang B project.
Other nonoperating income decreased in 1996, due to additional accruals
for SCE's regulatory matters, partially offset by EME's gain on the sale
of four geothermal facilities. Other nonoperating income decreased in
1995, as CPUC-authorized incentive awards were below 1994 levels.
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Interest and Other Expenses
Interest on long-term debt increased 12% in 1996, reflecting EME's
increased ownership in Iberian Hy-Power and First Hydro.
Other interest expense increased 11% during 1996, due to a $350 million
borrowing by Edison International (holding company) for the acquisition
of First Hydro and for its ongoing share repurchase program.
Capitalized interest decreased during 1996, primarily due to the
completion of construction activity at EME's Loy Yang B Unit 2 project.
Loy Yang B is a 51% owned, 1,000-megawatt coal-fired power plant near
Melbourne, Australia. Unit 2 began commercial operation on October 1,
1996.
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.
In June 1994, Edison International lowered its quarterly common stock
dividend by 30%, due to the uncertainty of future earnings levels arising
from the changing nature of California's electric utility regulation.
Currently, Edison International's board of directors has authorized the
repurchase of up to $800 million of its common stock. Edison
International has repurchased 27.4 million shares ($497 million) through
January 31, 1997, funded by dividends from its subsidiaries and its lines
of credit.
Edison International's cash flow coverage of dividends for 1996 was 5.0
times compared to 4.7 times in 1995 and 3.7 times in 1994. Edison
International's dividend payout ratio for 1996 was 61%.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $2.2 billion in 1996 and
$2.1 billion in both 1995 and 1994. Cash from operations exceeded capital
requirements for all years presented.
Cash Flows from Financing Activities
At December 31, 1996, Edison International and its subsidiaries had $1.8
billion of borrowing capacity available under lines of credit totaling
$2.1 billion. SCE had available lines of credit of $1.1 billion, with
$600 million for short-term debt and $500 million for the long-term
refinancing of its variable-rate pollution-control bonds. The parent
company has lines of credit totaling $350 million, with $185 million of
borrowing capacity available. The nonutility companies had available
lines of credit of $700 million, with $575 million of borrowing capacity
available to finance general cash requirements. Edison International's
unsecured lines of credit are at negotiated or bank index rates with
various expiration dates; the majority have five-year terms.
SCE's short-term debt is used to finance fuel inventories, balancing
account undercollections and general cash requirements. EME uses
available credit lines mainly for construction projects until long-term
construction or project loans are secured. Long-term debt is used mainly
to finance capital expenditures. SCE's external financings are influenced
by market conditions and other factors, including limitations imposed by
its articles of incorporation and trust indenture. As of December 31,
1996, SCE could issue approximately $7.9 billion of additional first and
refunding mortgage bonds and $4.5 billion of preferred stock at current
interest and dividend rates.
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EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard
project, but funded all of the required equity during construction. The
estimated total cost is $485 million, of which $442 million had been spent
through December 31, 1996. In December 1995, a tax-exempt bond financing
for the project in the amount of $254 million was obtained through the New
York City Industrial Development Agency (NYCIDA). EME has guaranteed the
obligations of the project pursuant to the financing, as well as an
indemnity agreement on behalf of NYCIDA in the amount of $40 million. In
the fourth quarter of 1996, EME executed a new energy sales agreement with
Consolidated Edison Company of New York, which has contracted to buy most
of the project's power and steam, and began selling power and steam under
that agreement. The contractor has recently asserted general monetary
claims under the turnkey agreement against Brooklyn Navy Yard and has
served a complaint for damages in the amount of $136.8 million against
Brooklyn Navy Yard. Brooklyn Navy Yard intends to vigorously defend this
action and to assert general monetary claims against the contractor. EME
believes that the outcome of this litigation will not have a material
adverse effect on its consolidated results of operations or financial
position.
EME has firm commitments to make equity and other contributions to its
projects of $408 million, primarily for the Paiton project in Indonesia
and the ISAB project in Italy. EME also has contingent obligations to
make additional contributions of $461 million, primarily for a guarantee
as a condition of obtaining a $254 million tax-exempt financing for the
Brooklyn Navy Yard project (further discussed in Note 10 to the
Consolidated Financial Statements), and equity support guarantees related
to Paiton.
EME may incur additional obligations to make equity and other
contributions to projects in the future. EME believes it will have
sufficient liquidity to meet these equity requirements from cash provided
by operating activities, proceeds from the repayment of loans to energy
projects, funds available from EME's revolving line of credit and
additional corporate borrowings.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital
structure, limiting the dividends it may pay Edison International. At
December 31, 1996, SCE had the capacity to pay $112 million in additional
dividends to Edison International and continue to maintain its authorized
capital structure. These restrictions are not expected to affect Edison
International's ability to meet its cash obligations.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant, the nonutilities' investments in partnerships and
unconsolidated subsidiaries, and funding of nuclear decommissioning
trusts. Decommissioning costs are accrued and recovered in rates over the
term of each nuclear generating facility's operating license through
charges to depreciation expense. SCE estimates that it will spend
approximately $12.7 billion between 2013-2070 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar
decommissioning costs ($2.0 billion), escalated using a 6.65% annual rate.
These costs are expected to be funded from independent decommissioning
trusts which receive SCE contributions of approximately $100 million per
year until decommissioning begins.
Cash used for the nonutility subsidiaries' investing activities was $409
million in 1996, $1.2 billion in 1995 and $291 million in 1994. The 1995
increase was due to the acquisition of First Hydro.
Edison International's risk management policy allows the use of derivative
financial instruments to mitigate risk. 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
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attempts to mitigate the risk of interest rate fluctuations by arranging
for fixed rate or variable rate financing with interest rate swaps or
other hedging mechanisms for the majority of its project financings. As
a result of interest rate hedging mechanisms, interest expense increased
$6 million in 1996, $7 million in 1995 and $8 million in 1994. The
maturity dates of several of EME's interest rate swap agreements do not
correspond to the term of the underlying debt. EME does not believe that
interest rate fluctuations will have a material adverse effect on results
of operations or financial position.
Projects in the United Kingdom sell their energy and capacity through a
centralized electricity pool, which establishes a half-hourly clearing
price for electric energy and capacity. The pool price is extremely
volatile, and can vary by a factor of ten or more over the course of a few
hours due to large differentials in demand according to the time of day.
First Hydro mitigates a portion of the market risk of the pool by entering
into contracts for differences (electricity rate swap agreements), related
to either the selling or purchase price of power, whereby a contract
specifies a price at which the electricity will be traded, and the parties
to the agreements make payments, calculated based on the difference
between the price in the contract and the half hourly clearing price for
the element of power under contract. These contracts act as a means of
stabilizing production revenue or purchasing costs by removing an element
of First Hydros net exposure to pool price volatility. First Hydro's
electric revenue decreased by $5 million and $29 million, respectively,
for the year ended December 31, 1996, and 1995, as a result of electricity
rate swap agreements.
As EME continues to expand into foreign markets, fluctuations in foreign
currency exchange rates will continue to affect the amount of its equity
contributions to, distributions from, and results of operations for, its
foreign projects. At times, EME has hedged a portion of its current
exposure to fluctuations in foreign exchange rates where it deems
appropriate through financial derivatives, offsetting obligations
denominated in foreign currencies, and indexing underlying project
agreements to U.S. dollars or other indices reasonably expected to
correlate with foreign exchange movements. Various statistical
forecasting techniques are used to help assess foreign exchange risk and
the probabilities of various outcomes. There can be no assurance,
however, that fluctuations in exchange rates will be fully offset by
hedges or that currency movements and the relationship between certain
macro economic variables will behave in a manner that is consistent with
historical or forecasted relationships.
Projected Capital Requirements
Edison International's projected construction expenditures for the next
five years are: 1997-$855 million; 1998-$636 million; 1999-$664 million;
2000-$647 million; and 2001-$650 million.
Long-term debt maturities and sinking fund requirements for the next five
years are: 1997-$573 million; 1998-$560 million; 1999-$459 million;
2000-$405 million; and 2001-$500 million.
Regulatory Matters
SCE's 1997 CPUC-authorized rates remain unchanged from 1996 levels due to
recently enacted legislation which requires that system average rates
remain frozen at the June 10, 1996, level of 10.1 cent per kilowatt-hour
(see discussion in Competitive Environment).
The CPUC's 1997 cost-of-capital decision authorized SCE's equity ratio to
remain at 48%. SCE's return on common equity also remains at 11.6%.
SCE's return on rate base was lowered from 9.55% to 9.49%. This decision,
excluding the effects of other rate actions, would reduce 1997 earnings
by approximately 1 cent per share.
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A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the Office of
Ratepayer Advocates (ORA) which resulted in a $39 million (including
interest) refund to SCE's customers. The refund, which had been
previously reserved, was completed by year-end 1996.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA filed its report on the reasonableness of SCE's gas supply costs
for both the 1993 and 1994 record periods. The report recommends a
disallowance of $13.3 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding SCE's
Canadian supply and transportation agreements reasonable for the duration
of their terms and that the costs under these contracts be reviewed on a
yearly basis. In October 1996, the ORA issued its report for the 1995
record period recommending a $37.6 million disallowance for excessive
costs incurred from April 1994 through March 1995. Both proposed
disallowances have been consolidated into one proceeding. SCE and the ORA
have filed several rounds of testimony on this issue. Hearings began in
January 1997 and are expected to conclude in February 1997. A decision
is expected in late 1997.
On December 23, 1996, the CPUC issued a final decision on SCE's proposal
for a new rate mechanism for its 15.8% share of the three units at Palo
Verde. The decision adopts the Palo Verde All-Party Settlement filed with
the CPUC on November 15, 1996. The settlement was based on a Memorandum
of Understanding signed by all of the active parties to the Palo Verde
proceeding. Under the settlement, SCE has the opportunity to recover its
remaining investment (approximately $1.2 billion) in Palo Verde beginning
January 1, 1997, and ending December 31, 2001, earning a reduced rate of
return on rate base of 7.35% instead of the current 9.49%. Also, SCE will
utilize a balancing account to pass through Palo Verde's incremental
operating costs (considered reasonable as long as they do not exceed 30%
of a baseline forecast and the site's gross annual capacity factor does
not go below 55%) to ratepayers. Beginning January 1, 1998, this
balancing account will become part of the competition transition charge
(CTC) mechanism. If SCE's actual costs are less than the forecast, the
difference will benefit ratepayers as a credit to the CTC mechanism. The
existing nuclear unit incentive procedure will continue only for purposes
of calculating a reward for performance of any unit above an 80% capacity
factor for a fuel cycle. After 2001, SCE's ratepayers will receive 50%
of the benefits derived from the operation of Palo Verde. The decision is
projected to reduce SCE's 1997 earnings by approximately 5 cents per
share.
Competitive Environment
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing. The generation sector has experienced
competition from nonutility power producers and regulators are
restructuring California's electric utility industry.
On September 23, 1996, the State of California enacted legislation to
provide a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision
(discussed below) by addressing stranded-cost recovery for utilities,
providing a certain cost recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, thereby
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allowing SCE to give a rate reduction of at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of a
non-bypassable CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Finally, the
legislation contains provisions for the recovery (through 2006) of
reasonable employee-related transition costs incurred and projected for
retraining, severance, early retirement, outplacement and related expenses
for utility workers. In light of the legislation, the CPUC is reassessing
the need to prepare an environmental impact report.
In December 1995, the CPUC issued its decision on restructuring
California's electric utility industry. The transition to a new market
structure, which is expected to provide competition and customer choice,
would begin January 1, 1998, with all consumers participating by 2003
(changed to 2002 by the recently enacted legislation). Key elements of the
CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from and sell to the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore, control
the scheduling and dispatch of all electricity on the state's power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the existing
framework and reasonable employee-related costs) through a non-bypassable
charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture (through
spin-off or sale to an unaffiliated entity) of at least 50% of utilities'
gas-fueled generation to address market power issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the FERC regarding the creation of
the PX and the ISO. On November 26, 1996, the FERC conditionally accepted
the proposal and directed the three utilities to file more specific
information by March 31, 1997. In July 1996, the three utilities jointly
filed an application with the CPUC requesting approval to establish a
restructuring trust which would obtain loans up to $250 million for the
development of the ISO and PX through January 1, 1998. The loans would
be backed by utility guarantees; SCE's share would be 45%. Once the ISO
and PX are formed, they will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million which will be used to build the hardware and software
systems for the ISO and PX.
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Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, transmission and distribution (T&D), nuclear decommissioning and
public benefit programs). Nevertheless, the CPUC directed that the
amended application provide estimates of SCE's potential transition costs
from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value), assuming the fossil plants have
a market value equal to the net book value, and $13.8 billion (1998 net
present value), assuming the fossil plants have no market value. These
estimates are based on incurred costs, and forecasts of future costs and
assumed market prices. However, changes in the assumed market prices
could materially affect these estimates. The potential transition costs
are comprised of: $7.5 billion from SCE's qualifying facility contracts,
which are the direct result of legislative and regulatory mandates; and
$5.6 billion to $6.3 billion from costs pertaining to certain generating
plants and regulatory commitments consisting of costs incurred (whose
recovery has been deferred by the CPUC) to provide service to
customers. Such commitments include the recovery of income tax benefits
previously flowed-through to customers, postretirement benefit transition
costs, accelerated recovery of San Onofre (as discussed in Note 1 to the
Consolidated Financial Statements) and Palo Verde, nuclear decommissioning
and certain other costs.
On November 27, 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil- and gas-fueled generation
divestiture was requested for late 1997.
In September 1996, the CPUC adopted a non-generation T&D PBR mechanism for
SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations. In July 1996, SCE filed
a PBR proposal for its hydroelectric plants and a proposed structure for
performance-based local reliability contracts for certain fossil-fueled
plants. If approved, the hydro PBR would be in effect for three years
and the initial terms of the local reliability contracts, which are
subject to FERC approval, would be in effect for up to three years, both
beginning January 1, 1998. A final CPUC decision on hydro PBR is expected
by year-end 1997.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public benefit programs and the CTC. The filing was in
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response to CPUC and FERC directives which require electric services, such
as T&D, to be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers. On
December 6, 1996, SCE filed a more comprehensive plan for the functional
unbundling of SCE's rates for electric service, beginning on January 1,
1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates in separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The filing also included proposals for
establishing new regulatory proceedings to replace current proceedings
that will no longer be necessary during the rate freeze period.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have write-offs
associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
Subsequent Event
If the CPUC's restructuring is implemented as outlined, SCE would be
allowed to recover its CTC (subject to a lower return on equity) and
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996 SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and its
independent accountants continue to believe that SCE meets such criteria
and plan to meet with the SEC staff to present additional and clarifying
information seeking to convince the SEC staff of the merits of SCE's
position. The authority to require SCE to discontinue applying regulatory
accounting standards rests with the SEC. If SCE is required to
discontinue the application of these accounting standards for its
generation-related assets, it would have to write off generation-related
regulatory assets, which at December 31, 1996 totaled approximately $600
million on an after-tax basis, primarily for the recovery of income tax
benefits previously flowed-through to customers, the Palo Verde phase-in
plan and unamortized loss on reacquired debt.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
page 11
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
FERC Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision requires all
electric utilities subject to the FERC's jurisdiction to file transmission
tariffs which provide competitors with increased access to transmission
facilities for wholesale transactions and also establishes information
requirements for the transmission utility. The decision also provides
utilities with the recovery of stranded costs, which are prior-service
costs incurred under the current regulatory framework. In addition to
providing recovery of stranded costs associated with existing wholesale
customers, the FERC directed that it would have primary jurisdiction over
the recovery of stranded costs associated with retail-turned-wholesale
customers, such as the formation of a new municipal electric system.
Retail stranded costs resulting from a state-authorized retail direct-
access program are the responsibility of the states and the FERC would
only address recovery of these costs if the state has no authority to do
so. In compliance with the April 1996 FERC decision, SCE filed a revised
open access tariff with the FERC in July 1996. The tariff became
effective on an interim basis, subject to refund, as of its filing date.
Several wholesale customers have filed protests with the FERC on the
transmission rate levels, and a ruling from the FERC setting the rates to
be decided at formal hearings is anticipated in early 1997.
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 10 to the Consolidated Financial Statements,
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site. Unless there is a
probable amount, Edison International records the lower end of this range
of costs.
Edison International's recorded estimated minimum liability to remediate
its 56 identified sites (55 at SCE and 1 at EME) was $114 million at
December 31, 1996. One of SCE's sites, a former pole-treating facility,
is considered a federal Superfund site and represents 71% of Edison
International's recorded liability. The ultimate costs to clean up Edison
International's identified sites may vary from its recorded liability due
to numerous uncertainties inherent in the estimation process. Edison
International believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to
$211 million. The upper limit of this range of costs was estimated using
assumptions least favorable to Edison International among a range of
reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 35 of its
sites, representing $101 million of Edison International's recorded
liability, through an incentive mechanism. Under this mechanism, SCE will
page 12
recover 90% of cleanup costs through customer rates; shareholders fund
the remaining 10%, with the opportunity to recover these costs from
insurance carriers and other third parties. SCE has successfully settled
insurance claims with a number of its carriers. Costs incurred at SCE's
remaining 20 sites are expected to be recovered through customer rates.
SCE has recorded a regulatory asset of $104 million for its estimated
minimum environmental-cleanup costs expected to be recovered through
customer rates.
Edison International's identified sites include several sites for which
there is a lack of currently available information, including the nature
and magnitude of contamination, and the extent, if any, that Edison
International may be held responsible for contributing to any costs
incurred for remediating these sites. Thus, no reasonable estimate of
cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a
period of up to 30 years. Remediation costs in each of the next several
years are expected to range from $4 million to $8 million. Recorded costs
for 1996 were $7 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 have a material adverse effect on its results
of operations or financial position. There can be no assurance, however,
that future developments, including additional information about existing
sites or the identification of new sites, will not require material
revisions to such estimates.
The 1990 federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions
allowances from the federal government and may bank or sell excess
allowances. SCE expects to have excess allowances under Phase II of the
Clean Air Act (2000 and later). The act also calls for a study to
determine if additional regulations are needed to reduce regional haze in
the southwestern U.S. In addition, another study is in progress to
determine the specific impact of air contaminant emissions from the Mohave
Coal Generating Station on visibility in Grand Canyon National Park. The
potential effect of these studies on sulfur dioxide emissions regulations
for Mohave is unknown.
Edison International's projected capital expenditures to protect the
environment are $900 million for the 1997-2001 period, mainly for
aesthetics treatment, including undergrounding certain transmission and
distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects is receiving increased
attention. The scientific community has not yet reached a consensus on
the nature of any health effects of EMF. However, the CPUC has issued a
decision which provides for a rate-recoverable research and public
education program conducted by California electric utilities, and
authorizes these utilities to take no-cost or low-cost steps to reduce EMF
in new electric facilities. SCE is unable to predict when or if the
scientific community will be able to reach a consensus on any health
effects of EMF, or the effect that such a consensus, if reached, could
have on future electric operations.
Palo Verde Steam Tube Rupture
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
page 13
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in only one of the units will have to be replaced within five
to ten years. Based on APS' 100% share estimate, SCE estimates its share
of the costs to be between $22 million and $24 million, plus replacement
power costs. SCE is evaluating APS' analyses, conducting its own review,
and has not yet decided whether it supports replacement of the steam
generators.
Workforce Reductions
During 1996, Edison International offered a voluntary retirement program
to certain eligible employees. Approximately 3,000 employees (2,200 non-
represented and 800 represented employees) accepted the terms of this
program. After allowance for the effects of pension settlement gains at
SCE, Edison International's net expense for this program was $7 million.
Proposed New Accounting Standard
During 1996, the Financial Accounting Standards Board issued an exposure
draft that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for the decommissioning of its nuclear power plants, obligations for coal
mine reclamation costs and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
The nonutility subsidiaries are currently reviewing what impact the
exposure draft may have on their results of operations and financial
position.
The management of Edison International is responsible for the integrity
and objectivity of the accompanying financial statements. The statements
have been prepared in accordance with generally accepted accounting
principles applied on a consistent basis and are based, in part, on
management estimates and judgment.
Edison International and its subsidiaries maintain systems of internal
control to provide reasonable, but not absolute, assurance that assets are
safeguarded, transactions are executed in accordance with management's
authorization and the accounting records may be relied upon for the
preparation of the financial statements. There are limits inherent in all
systems of internal control, the design of which involves management's
judgment and the recognition that the costs of such systems should not
exceed the benefits to be derived. Edison International believes its
systems of internal control achieve this appropriate balance. These
systems are augmented by internal audit programs through which the
adequacy and effectiveness of internal controls and policies and
procedures are monitored, evaluated and reported to management. Actions
are taken to correct deficiencies as they are identified.
Edison International's independent public accountants, Arthur Andersen
LLP, are engaged to audit the financial statements in accordance with
generally accepted auditing standards and to express an informed opinion
on the fairness, in all material respects, of Edison International's
reported results of operations, cash flows and financial position.
As a further measure to assure the ongoing objectivity of financial
information, the audit committee of the board of directors, which is
page 14
composed of outside directors, meets periodically, both jointly and
separately, with management, the independent public accountants and
internal auditors, who have unrestricted access to the committee. The
committee recommends annually to the board of directors the appointment
of a firm of independent public accountants to conduct audits of its
financial statements; considers the independence of such firm and the
overall adequacy of the audit scope and Edison International's systems of
internal control; reviews financial reporting issues; and is advised of
management's actions regarding financial reporting and internal control
matters.
Edison International and its subsidiaries maintain high standards in
selecting, training and developing personnel to assure that their
operations are conducted in conformity with applicable laws and are
committed to maintaining the highest standards of personal and corporate
conduct. Management maintains programs to encourage and assess compliance
with these standards.
Richard K. Bushey John E. Bryson
Vice President and Controller Chairman of the Board and
Chief Executive Officer
January 31, 1997
page 15
To the Shareholders and the Board of Directors, Edison International:
We have audited the accompanying consolidated balance sheets of Edison
International (a California corporation) and its subsidiaries as of
December 31, 1996, and 1995, and the related consolidated statements of
income, retained earnings and cash flows for each of the three years in
the period ended December 31, 1996. These financial statements are the
responsibility of Edison International's management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Edison International
and its subsidiaries as of December 31, 1996, and 1995, and the results
of their operations and their cash flows for each of the three years in
the period ended December 31, 1996, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Los Angeles, California
January 31, 1997 (except with respect to the "Subsequent Event" discussed
under "Electric Utility Industry Restructuring" in Note 2, as to which the
date is February 21, 1997).
page 16
Consolidated Statements of Income
In millions, except per-share amounts Year ended December 31, 1996 1995 1994
- ------------------------------------- ----------------------- ---- ---- ----
Electric utility revenue $7,583 $7,873 $7,799
Diversified operations 962 532 546
------ ------ ------
Total operating revenue 8,545 8,405 8,345
------ ------ ------
Fuel 768 694 896
Purchased power 2,706 2,582 2,563
Provisions for regulatory adjustment clauses-net (226) 230 55
Other operating expenses 1,555 1,411 1,563
Maintenance 331 359 332
Depreciation and decommissioning 1,173 1,014 945
Income taxes 563 528 481
Property and other taxes 197 210 211
------ ------ ------
Total operating expenses 7,067 7,028 7,046
------ ------ ------
Operating income 1,478 1,377 1,299
------ ------ ------
Provision for rate phase-in plan (84) (122) (137)
Allowance for equity funds used during construction 16 19 14
Interest income 63 65 41
Minority interest (70) (48) (46)
Other nonoperating income-net (13) 41 97
------ ------ ------
Total other income (deductions)-net (88) (45) (31)
------ ------ ------
Income before interest and other expenses 1,390 1,332 1,268
------ ------ ------
Interest on long-term debt 604 539 527
Other interest expense 90 81 79
Allowance for borrowed funds used during construction (10) (14) (14)
Capitalized interest (58) (60) (46)
Dividends on subsidiary preferred securities 47 47 41
------ ------ ------
Total interest and other expenses-net 673 593 587
------ ------ ------
Net income $ 717 $ 739 $ 681
====== ====== ======
Weighted-average shares of common stock outstanding 437 446 448
Earnings per share $ 1.64 $ 1.66 $ 1.52
Consolidated Statements of Retained Earnings
In millions, except per-share amounts Year ended December 31, 1996 1995 1994
- ------------------------------------- ----------------------- ---- ---- ----
Balance at beginning of year $3,700 $3,452 $3,266
Net income 717 739 681
Dividends declared on common stock (435) (446) (495)
Stock repurchase and retirement (229) (45) --
------ ------ ------
Balance at end of year $3,753 $3,700 $3,452
====== ====== ======
Dividends declared per common share $1.00 $1.00 $1.105
The accompanying notes are an integral part of these financial statements.
page 17
Consolidated Balance Sheets
In millions December 31, 1996 1995
- ----------- ------------ ---- ----
Assets
Utility plant, at original cost $20,400 $19,850
Less - accumulated provision for depreciation and decommissioning 9,431 8,569
------- -------
10,969 11,281
Construction work in progress 557 728
Nuclear fuel, at amortized cost 177 139
------- -------
Total utility plant 11,703 12,148
------- -------
Nonutility property - less accumulated provision for depreciation
of $203 and $134 at respective dates 3,570 3,141
Nuclear decommissioning trusts 1,486 1,260
Investments in partnerships and unconsolidated subsidiaries 1,372 1,190
Investments in leveraged leases 584 574
Other investments 104 66
------- -------
Total other property and investments 7,116 6,231
------- -------
Cash and equivalents 897 507
Receivables, including unbilled revenue, less allowances of $26
and $24 for uncollectible accounts at respective dates 1,095 1,055
Fuel inventory 72 115
Materials and supplies, at average cost 154 151
Accumulated deferred income taxes-net 240 477
Prepayments and other current assets 114 126
------- -------
Total current assets 2,572 2,431
------- -------
Unamortized debt issuance and reacquisition expense 347 350
Rate phase-in plan 51 130
Unamortized nuclear plant - net - 67
Income tax-related deferred charges 1,741 1,724
Other deferred charges 1,029 865
------- -------
Total deferred charges 3,168 3,136
------- -------
Total assets $24,559 $23,946
======= =======
The accompanying notes are an integral part of these financial statements.
page 18
In millions, except share amounts December 31, 1996 1995
- --------------------------------- ------------ ---- ----
Capitalization and Liabilities
Common shareholders' equity:
Common stock (424,524,178 and 443,607,674 shares
outstanding at respective dates) $ 2,547 $ 2,660
Cumulative translation adjustments-net 64 15
Unrealized gain in equity investments-net 33 18
Retained earnings 3,753 3,700
------- -------
6,397 6,393
Preferred securities of subsidiaries:
Not subject to mandatory redemption 284 284
Subject to mandatory redemption 425 425
Long-term debt 7,475 7,195
------- -------
Total capitalization 14,581 14,297
------- -------
Other long-term liabilities 424 344
------- -------
Current portion of long-term debt 592 40
Short-term debt 397 710
Accounts payable 438 420
Accrued taxes 530 557
Accrued interest 131 101
Dividends payable 109 113
Regulatory balancing accounts - net 182 338
Deferred unbilled revenue and other current liabilities 1,059 973
------- -------
Total current liabilities 3,438 3,252
------- -------
Accumulated deferred income taxes-net 4,283 4,352
Accumulated deferred investment tax credits 372 405
Customer advances and other deferred credits 754 666
------- -------
Total deferred credits 5,409 5,423
------- -------
Minority interest 707 630
------- -------
Commitments and contingencies (Notes 2, 8, 9 and 10)
Total capitalization and liabilities $24,559 $23,946
======= =======
The accompanying notes are an integral part of these financial statements.
page 19
Consolidated Statements of Cash Flows
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Cash flows from operating activities:
Net income $ 717 $ 739 $ 681
Adjustments for non-cash items:
Depreciation and decommissioning 1,173 1,014 945
Amortization 96 73 134
Rate phase-in plan 79 111 123
Deferred income taxes and investment tax credits 91 (166) 22
Equity in income from partnerships and unconsolidated
subsidiaries (158) (115) (130)
Other long-term liabilities 80 33 44
Other-net (94) -- (79)
Changes in working capital:
Receivables 68 (27) (98)
Regulatory balancing accounts (156) 282 (2)
Fuel inventory, materials and supplies 39 (19) (21)
Prepayments and other current assets 13 (17) 14
Accrued interest and taxes 3 19 121
Accounts payable and other current liabilities 70 13 97
Distributions from partnerships and unconsolidated subsidiaries 176 178 205
------- ------- -------
Net cash provided by operating activities 2,197 2,118 2,056
------- ------- -------
Cash flows from financing activities:
Long-term debt issued 1,365 1,496 314
Long-term debt repayments (1,315) (960) (507)
Preferred securities issued 414 63 88
Preferred securities redemptions -- (75) --
Common stock repurchases (344) (70) --
Short-term debt financing-net (312) (46) 141
Dividends paid (440) (447) (549)
Other-net 45 31 (31)
------ ------ ------
Net cash used by financing activities (587) (8) (544)
Cash flows from investing activities:
Additions to property and plant (744) (969) (1,137)
Purchase of nonutility power stations -- (1,015) --
Funding of nuclear decommissioning trusts (148) (151) (130)
Investments in partnerships and unconsolidated subsidiaries (333) (45) (201)
Unrealized gain in equity investments-net 15 8 10
Other-net (10) 35 59
------- ------- -------
Net cash used by investing activities (1,220) (2,137) (1,399)
------- ------- -------
Net increase (decrease) in cash and equivalents 390 (27) 113
Cash and equivalents, beginning of year 507 534 421
------- ------- -------
Cash and equivalents, end of year $ 897 $ 507 $ 534
======= ======= =======
Cash payments for interest and taxes:
Interest $ 486 $ 463 $ 470
Taxes 447 642 320
Non-cash investing and financing activities:
Obligation to fund investments in partnerships and unconsolidated
subsidiaries 237 466 29
Additions to property and plant funded by the minority owner of
consoldiated subsidiaries 33 77 95
Goodwill related to purchase of nonutility power stations -- 312 --
The accompanying notes are an integral part of these financial statements.
page 20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant
Accounting Policies
The consolidated financial statements include Edison International and its
wholly owned subsidiaries: Southern California Edison Company (SCE), a
rate-regulated electric utility which produces and supplies electric
energy for its 4.2 million customers in Central and Southern California;
Edison Mission Energy (EME), a market leader in the development, ownership
and operation of independent power facilities; Edison Capital, a leading
provider of capital and financial services; Edison Source, a provider of
integrated energy solutions; Edison EV, a provider of charging products
and services for electric vehicles; and Edison Select, a consumer product
and services company. The latter three subsidiaries were formed in 1996.
EME and Edison Capital have domestic and international projects, primarily
in Europe. Edison International's subsidiaries use the equity method to
account for significant investments in partnerships and subsidiaries in
which they own 50% or less. In 1994, EME began reporting its share in the
Loy Yang B project under the full consolidation method (with minority
interest), previously reported under the proportional consolidation
method. Intercompany transactions have been eliminated, except EME's
profits from energy sales to SCE, which are allowed in utility rates.
SCE's accounting policies conform with generally accepted accounting
principles (GAAP), including the accounting principles for rate-regulated
enterprises which reflect the rate-making policies of the California
Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC).
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing, as further discussed in Note 2 to the
Consolidated Financial Statements. EME operates predominantly in one
industry segment: independent, electric power generation. EME's projects
generally sell power to a limited number of electric utilities pursuant
to long-term (15 to 30 years) contracts. EME's plants are located in
different geographic areas in order to mitigate the effects of regional
markets, economic down-turns or unusual weather conditions.
Financial statements prepared in compliance with GAAP require management
to make estimates and assumptions that affect the amounts reported in the
financial statements and disclosure of contingencies. Actual results
could differ from those estimates. Certain significant estimates related
to electric utility industry restructuring, decommissioning and
contingencies, are further discussed in Notes 2, 9 and 10, respectively.
Certain prior-year amounts were reclassified to conform to the December
31, 1996, financial statement presentation.
Debt Issuance and Reacquisition Expense
Debt premium, discount and issuance expenses are amortized over the life
of each issue. Under CPUC rate-making procedures, debt reacquisition
expenses are amortized over the remaining life of the reacquired debt or,
if refinanced, the life of the new debt.
Financial Instruments
Edison International enters into interest rate swap and cap agreements to
manage its interest rate exposure. Interest rate differentials and
premiums for interest rate caps to be paid or received are recorded as
page 21
adjustments to interest expense. EME enters into electricity rate swap
agreements to manage its exposure to market (pool) price volatility.
Related price differentials to be paid or received are recorded as
adjustments to diversified revenue.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil
and natural gas, and under the first-in, first-out method for coal.
Investment
Cash equivalents include tax-exempt investments ($376 million at December
31, 1996, and $313 million at December 31, 1995), and time deposits and
other investments ($320 million at December 31, 1996, and $134 million at
December 31, 1995) with maturities of three months or less.
Net unrealized gains (losses) in equity investments are recorded as a
separate component of shareholders' equity under "Unrealized gain (loss)
in equity investments-net." Unrealized gains and losses on
decommissioning trust funds are recorded in the accumulated provision for
decommissioning.
All investments are classified as available-for-sale.
Nuclear
The CPUC authorized rate phase-in plans to defer the collection of $200
million in revenue for each unit at the Palo Verde Nuclear Generating
Station during the first four years of operation and recover the deferred
revenue (including interest) evenly over the following six years. The
phase-in plans ended in February 1996 and September 1996 for Units 1 and
2, respectively. The plan ends in January 1998 for Unit 3.
Decommissioning costs are accrued and recovered in rates over the term of
each nuclear facility's operating license through charges to
decommissioning expense (see Note 9).
Under the Energy Policy Act of 1992, SCE is liable for its share of the
estimated costs to decommission three federal nuclear enrichment
facilities (based on purchases). These costs, which will be paid over 15
years, are recorded as a fuel cost and recovered through customer rates.
In August 1992, the CPUC approved a settlement agreement between SCE and
the CPUC's Office (formerly Division) of Ratepayer Advocates (ORA) to
discontinue operation of San Onofre Nuclear Generating Station Unit 1 at
the end of its then-current fuel cycle because operation of the unit was
no longer cost-effective. In November 1992, SCE discontinued operation
of Unit 1. As part of the agreement, SCE recovered its remaining
investment over a four-year period ending August 1996, earning an 8.98%
rate of return on rate base.
In October 1994, the CPUC authorized accelerated recovery of SCE's nuclear
plant investments by $75 million per year, with a corresponding
deceleration in recovery of its transmission and distribution assets
through revised depreciation estimates over their remaining useful lives.
In April 1996, the CPUC authorized, and SCE began accelerating, the
recovery of its remaining investment of $2.6 billion in San Onofre Units
2 and 3. The accelerated recovery will continue through December 2001
(the original end date of 2003 was changed by legislation enacted in
September 1996), earning a 7.35% fixed rate of return (compared to the
page 22
current 9.49%). Future operating costs, including nuclear fuel and
nuclear fuel financing costs and incremental capital expenditures at San
Onofre Units 2 and 3, are subject to an incentive pricing plan whereby SCE
receives about 4 cents per kilowatt-hour through 2003. Any differences
between these costs and the incentive price will flow through to the
shareholders. Beginning in 2004, SCE will be required to share equally
with ratepayers the benefits received from operation of the units.
Prior to January 1, 1997, the cost of nuclear fuel for Palo Verde,
including disposal, was amortized to fuel expense on the basis of
generation. Under CPUC rate-making procedures in effect for Palo Verde
prior to January 1, 1997, nuclear-fuel financing costs were capitalized
until the fuel was placed into production.
Property and Plant
Utility plant additions, including replacements and betterments, are
capitalized. Such costs include direct material and labor, construction
overhead and an allowance for funds used during construction (AFUDC).
AFUDC represents the estimated cost of debt and equity funds that finance
utility plant construction. AFUDC is capitalized during plant
construction and reported in current earnings. AFUDC is recovered in
rates through depreciation expense over the useful life of the related
asset.
Depreciation of utility plant is computed on a straight-line, remaining-
life basis. Replaced or retired property and removal costs less salvage
are charged to the accumulated provision for depreciation. Depreciation
expense stated as a percent of average original cost of depreciable
utility plant was 4.2% for 1996, and 3.6% for both 1995 and 1994.
Nonutility property is capitalized at cost, including interest incurred
on borrowed funds that finance construction. Depreciation of nonutility
properties is primarily computed on a straight-line basis over their
estimated useful lives. Depreciation expense stated as a percent of
average original cost of depreciable nonutility property was, on a
composite basis, 3.9% for 1996, 3.8% for 1995 and 5.2% for 1994.
Regulatory Balancing Accounts
The differences between CPUC-authorized and actual base-rate revenue from
kilowatt-hour sales and CPUC-authorized and actual energy costs are
accumulated in balancing accounts until they are refunded to, or
recovered from, utility customers through authorized rate adjustments
(with interest). Income tax effects on balancing account changes are
deferred.
Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant
construction. If construction does not occur, these costs are charged to
expense. RD&D expenses are recorded in a balancing account and, at the
end of the rate-case cycle, any authorized but unspent RD&D funds are
refunded to customers. RD&D expenses were $21 million in 1996, $28
million in 1995 and $63 million in 1994.
Revenue
Electric utility revenue includes amounts for services rendered but
unbilled at the end of each year.
page 23
Stock-Based Compensation
Edison International measures compensation expense relative to stock-based
compensation by the intrinsic-value method.
Note 2. Regulatory Matters
Electric Utility Industry Restructuring
On September 23, 1996, the State of California enacted legislation to
provide a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision
(discussed below) by addressing stranded-cost recovery for utilities,
providing a certain cost recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, thereby
allowing SCE to give a rate reduction of at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of a
non-bypassable competition transition charge (CTC) that provides utilities
the opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses for utility workers. In light of the
legislation, the CPUC is reassessing the need to prepare an environmental
impact report.
In December 1995, the CPUC issued its decision on restructuring
California's electric utility industry. The transition to a new market
structure, which is expected to provide competition and customer choice,
would begin January 1, 1998, with all consumers participating by 2003
(changed to 2002 by the recently enacted legislation). Key elements of
the CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from and sell to the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore, control
the scheduling and dispatch of all electricity on the state's power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
page 24
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the existing
framework and reasonable employee-related costs) through a non-bypassable
charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture (through
spin-off or sale to an unaffiliated entity) of at least 50% of utilities'
gas-fueled generation to address market power issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the FERC regarding the creation of
the PX and the ISO. On November 26, 1996, the FERC conditionally accepted
the proposal and directed the three utilities to file more specific
information by March 31, 1997. In July 1996, the three utilities jointly
filed an application with the CPUC requesting approval to establish a
restructuring trust which would obtain loans up to $250 million for the
development of the ISO and PX through January 1, 1998. The loans would
be backed by utility guarantees; SCE's share would be 45%. Once the ISO
and PX are formed, they will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million which will be used to build the hardware and software
systems for the ISO and PX.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, transmission and distribution (T&D), nuclear decommissioning and
public benefit programs). Nevertheless, the CPUC directed that the
amended application provide estimates of SCE's potential transition costs
from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value), assuming the fossil plants have
a market value equal to their net book value, and $13.8 billion (1998 net
present value), assuming the fossil plants have no market value. These
estimates are based on incurred costs, and forecasts of future costs and
assumed market prices. However, changes in the assumed market prices
could materially affect these estimates. The potential transition costs
are comprised of: $7.5 billion from SCE's qualifying facility contracts,
which are the direct result of legislative and regulatory mandates; and
$5.6 billion to $6.3 billion from costs pertaining to certain generating
plants and regulatory commitments consisting of costs incurred (whose
recovery has been deferred by the CPUC) to provide service to customers.
Such commitments include the recovery of income tax benefits previously
flowed-through to customers, postretirement benefit transition costs,
accelerated recovery of San Onofre (as discussed in Note 1) and Palo
Verde, nuclear decommissioning and certain other costs.
On November 27, 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
page 25
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil-and gas-fueled generation
divestiture was requested for late 1997.
In September 1996, the CPUC adopted a non-generation T&D PBR mechanism for
SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations. In July 1996, SCE filed
a PBR proposal for its hydroelectric plants and a proposed structure for
performance-based local reliability contracts for certain fossil-fueled
plants. If approved, the hydro PBR would be in effect for three years
and the initial terms of the local reliability contacts, which are subject
to FERC approval, would be in effect for up to three years, both beginning
January 1, 1998. A final CPUC decision on hydro PBR is expected by year-
end 1997.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public benefit programs and the CTC. The filing was in
response to CPUC and FERC directives which require electric services, such
as T&D, to be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers. On
December 6, 1996, SCE filed a more comprehensive plan for the functional
unbundling of SCE's rates for electric service, beginning on January 1,
1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates in separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The filing also included proposals for
establishing new regulatory proceedings to replace current proceedings
that will no longer be necessary during the rate freeze period.
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have write-offs
associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
page 26
Subsequent Event
If the CPUC's restructuring is implemented as outlined, SCE would be
allowed to recover its CTC (subject to a lower return on equity) and
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996 SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and its
independent accountants continue to believe that SCE meets such criteria
and plan to meet with the SEC staff to present additional and clarifying
information seeking to convince the SEC staff of the merits of SCE's
position. The authority to require SCE to discontinue applying regulatory
accounting standards rests with the SEC. If SCE is required to
discontinue the application of these accounting standards for its
generation-related assets, it would have to write-off generation-related
regulatory assets, which at December 31, 1996 totaled approximately $600
million on an after-tax basis, primarily for the recovery of income tax
benefits previously flowed-through to customers, the Palo Verde phase-in
plan and unamortized loss on reacquired debt.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write-off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
FERC Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision requires all
electric utilities subject to the FERC's jurisdiction to file transmission
tariffs which provide competitors with increased access to transmission
facilities for wholesale transactions and also establishes information
requirements for the transmission utility. The decision also provides
utilities with the recovery of stranded costs, which are prior-service
costs incurred under the current regulatory framework. In addition to
providing recovery of stranded costs associated with existing wholesale
customers, the FERC directed that it would have primary jurisdiction over
the recovery of stranded costs associated with retail-turned-wholesale
customers, such as the formation of a new municipal electric system.
Retail stranded costs resulting from a state-authorized retail direct-
access program are the responsibility of the states and the FERC would
only address recovery of these costs if the state has no authority to do
page 27
so. In compliance with the April 1996 FERC decision, SCE filed a revised
open access tariff with the FERC in July 1996. The tariff became
effective on an interim basis, subject to refund, as of its filing date.
Several wholesale customers have filed protests with the FERC on the
transmission rate levels, and a ruling from the FERC setting the rates to
be decided at formal hearings is anticipated in early 1997.
Mohave Generating Station
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the ORA which
resulted in a $39 million (including interest) refund to SCE's customers.
The refund, which had been previously reserved, was completed by year-end
1996.
Canadian Gas Contracts
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA filed its report on the reasonableness of SCE's gas supply costs
for both the 1993 and 1994 record periods. The report recommends a
disallowance of $13.3 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding SCE's
Canadian supply and transportation agreements reasonable for the duration
of their terms and that the costs under these contracts be reviewed on a
yearly basis. In October 1996, the ORA issued its report for the 1995
record period recommending a $37.6 million disallowance for excessive
costs incurred from April 1994 through March 1995. Both proposed
disallowances have been consolidated into one proceeding. SCE and the ORA
have filed several rounds of testimony on this issue. Hearings began in
January 1997 and are expected to conclude in February 1997. A decision
is expected in late 1997.
Palo Verde Rate-making Mechanism
On December 23, 1996, the CPUC issued a final decision on SCE's proposal
for a new rate mechanism for its 15.8% share of the three units at Palo
Verde. The decision adopts the Palo Verde All-Party Settlement filed with
the CPUC on November 15, 1996. The settlement was based on a Memorandum
of Understanding signed by all of the active parties to the Palo Verde
proceeding. Under the settlement, SCE has the opportunity to recover its
remaining investment (approximately $1.2 billion) in Palo Verde beginning
January 1, 1997, and ending December 31, 2001, earning a reduced rate of
return on rate base of 7.35% instead of the current 9.49%. Also, SCE will
utilize a balancing account to pass through Palo Verde's incremental
operating costs (considered reasonable as long as they do not exceed 30%
of a baseline forecast and the site's gross annual capacity factor does
not go below 55%) to ratepayers. Beginning January 1, 1998, this
balancing account will become part of the CTC mechanism. If SCE's actual
costs are less than the forecast, the difference will benefit ratepayers
as a credit to the CTC mechanism. The existing nuclear unit incentive
procedure will continue only for purposes of calculating a reward for
performance of any unit above an 80% capacity factor for a fuel cycle.
After 2001, SCE's ratepayers will receive 50% of the benefits derived from
the operation of Palo Verde.
page 28
Note 3. Financial Instruments
Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien.
SCE has pledged first and refunding mortgage bonds as security for
borrowed funds obtained from pollution-control bonds issued by government
agencies. SCE uses these proceeds to finance construction of pollution-
control facilities. Bondholders have limited discretion in redeeming
certain pollution-control bonds, and SCE has arranged with securities
dealers to remarket or purchase them if necessary.
Long-term debt maturities and sinking-fund requirements for the next five
years are: 1997-$573 million; 1998-$560 million; 1999-$459 million;
2000-$405 million; and 2001-$500 million.
Long-term debt consisted of:
In millions December 31, 1996 1995
- ------------ ---------------- ------ -----
First and refunding mortgage bonds:
1997-2000 (5.45% to 7.5%) $1,025 $1,025
2001-2005 (5.625% to 6.25%) 450 450
2017-2026 (6.9% to 8.875%) 1,250 1,637
Pollution-control bonds:
1999-2027 (5.4% to 7.2% and variable) 1,204 1,205
Funds held by trustees (2) (2)
Debentures and notes:
1997-2026 (5% to 20% and variable) 3,891 2,717
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 112 70
Capital lease obligation 91 97
Current portion of capital lease obligation (19) (15)
Long-term debt due within one year (573) (25)
Unamortized debt discount-net (54) (64)
------ ------
Total $7,475 $7,195
======= ======
Short-Term Debt
Short-term debt consisted of:
In millions December 31, 1996 1995
- ------------ ---------------- ------ ------
Commercial paper $ 470 $ 508
Other short-term debt 167 350
Amount reclassified as long-term (237) (145)
Unamortized discount (3) (3)
------ ------
Total $ 397 $ 710
====== ======
Weighted-average interest rate 5.6% 5.9%
At December 31, 1996, Edison International and its subsidiaries had $1.8
billion of borrowing capacity available under lines of credit totaling
$2.1 billion. SCE had available lines of credit of $1.1 billion, with
$600 million for short-term debt and $500 million for the long-term
page 29
refinancing of its variable-rate pollution-control bonds. The nonutility
subsidiaries had lines of credit of $700 million, with $575 million of
borrowing capacity available to finance general cash requirements. The
holding company has lines of credit totaling $350 million. At December
31, 1996, $165 million was used in support of EME's 1995 acquisition of
First Hydro and Edison International's ongoing share repurchase program.
Edison International's unsecured revolving lines of credit are at
negotiated or bank index rates with various expiration dates; the majority
have five-year terms.
Other Financial Instruments
Edison International's risk management policy allows the use of derivative
financial instruments to manage financial exposure on its investments,
fluctuations in interest rates, foreign exchange rates and energy prices,
but prohibits the use of these instruments for speculative or trading
purposes.
Projects in the United Kingdom (U.K.) sell their energy and capacity
through a centralized electricity pool which establishes a half-hourly
clearing price. The half-hourly price is extremely volatile, and can vary
by a factor of ten or more over the course of a few hours due to large
differentials in demand according to the time of day. First Hydro
attempts to mitigate the market risk of the pool by entering into
electricity rate swap agreements, related to either the selling or
purchase price of power, whereby payments are made when pool selling
prices rise above the price specified in the contract. These contracts
attempt to stabilize production revenue or purchasing costs by removing
one element of net exposure to pool price volatility. The Roosecote
project has avoided the pool price volatility by entering into a long-term
power-sales contract which provides for contract pricing.
Interest rate swaps and caps are used to reduce the potential impact of
interest rate fluctuations on floating rate long-term debt. SCE's
interest rate swap agreement requires the parties to pledge collateral
according to bond rating and market interest rate changes. At December
31, 1996, SCE had pledged $16 million as collateral due to a decline in
market interest rates. SCE is exposed to credit loss in the event of
nonperformance by counterparties to these agreements, but does not expect
the counterparties to fail to meet their obligations.
Edison International is subject to concentrations of credit risk as the
result of elements involved in EME's financial instruments and power-sales
contracts. Credit risk relates to the risk of loss that EME would incur
as a result of nonperformance by counterparties (major financial
institutions and domestic and foreign utilities) pursuant to the terms of
their contractual obligations. EME attempts to mitigate this risk by
contracting with counterparties that have a strong capacity to meet their
contractual obligations and by monitoring their credit quality. In
addition, EME attempts to secure long-term power-sales contracts for its
projects that are expected to result in adequate cash flow under a wide
range of economic and operating circumstances. To accomplish this, EME
attempts to structure its long-term contracts so that fluctuations in fuel
costs will produce similar fluctuations in electric energy and/or steam
revenue by entering into long-term fuel supply and transportation
agreements. Accordingly, EME does not anticipate a material impact to its
results of operations or financial condition as a result of counterparty
nonperformance.
page 30
Edison International had the following derivative financial instruments
at December 31, 1996, and 1995, except where noted:
Contract Amount/Terms Purpose
- --------------------- ---------------------------------------
Interest rate swaps:
$196 million expires 2008 fix interest rate exposure at 5.585%
$100 million expires 1999 convert fixed-rate debt of 7.75% and
$100 million expires 2002 8.125% to a floating rate capped at 9.0%
$45 million expires 1999 convert fixed-rate debt of 9.875%
preferred securities due 2024 to a floating rate
$75 million expired August 1996 fix interest rate exposure at 7.98%
$50 million expires 1999 fix interest rate exposure at 8.095%
10.9 billion Spanish pesetas (12/31/96) convert floating-rate debt to fixed rates
(U.S. $84 million) ranging from 8.4% to 11.38%
expires 1998-2003
45 million pounds (12/31/96) convert floating-rate debt to a fixed
(U.S. $77 million) rate of 12.4%
51 million pounds (12/31/95)
(U.S. $79 million) debt due 2005
expires 1997
A$42 million (12/31/96) convert floating-rate debt to a fixed
(U.S. $33 million) rate of 10.98%
A$34 million (12/31/95)
(U.S. $25 million) expires 2007
Interest rate caps:
$30 million expires 1997 fix interest rate exposure at 6%
debt due 2027 over the variable term of the debt
A$58 million (12/31/95) fix interest rate exposure at 11.25%
(U.S. $43 million)
expired November 1996
U.K. electricity rate swaps:
1,735 MW (12/31/96) fix market electricity sales rates
1,500 MW (12/31/95)
various expirations through 2000
416 MW (12/31/96) fix market electricity purchase rates
expires March 1997
page 31
Fair values of financial instruments were:
December 31,
---------------------------------------------------
1996 1995
--------------------- ----------------------
Cost Fair Cost Fair
Instrument (in millions) Basis Value Basis Value
- ------------------------ -------- ----- -------- -----
Financial assets:
Decommissioning trusts $1,217 $1,485 $1,069 $1,260
Electricity rate swaps - 27 - 22
Equity investments 11 68 9 41
Financial liabilities:
DOE decommissioning and
decontamination fees 54 45 58 49
Interest rate swaps and caps - 34 - 28
Long-term debt 7,475 7,712 7,195 7,531
Preferred securities subject to
mandatory redemption 425 445 425 448
Financial assets are carried at their fair value, which is based on quoted
market prices. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs for interest rate
swaps; brokers' quotes for long-term debt, preferred stock and caps;
discounted future cash flows for U.S. Department of Energy (DOE)
decommissioning and decontamination fees; and discounted future cash flows
for the difference between contract prices and forecasted market prices
for electricity rate swaps. Amounts reported for cash equivalents and
short-term debt approximate fair value, due to their short maturities.
Gross unrealized holding gains on financial assets were:
In millions December 31, 1996 1995
- ----------- -------------- ---- ----
Decommissioning trusts:
Municipal bonds $ 79 $ 52
Stocks 138 122
U.S. government issues 39 11
Short-term and other 12 6
---- ----
268 191
Equity investments 57 32
---- ----
Total $325 $223
==== ====
There were no unrealized holding losses on financial assets for the years
presented.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may
pay Edison International. At December 31, 1996, SCE had the capacity to
pay $112 million in additional dividends to Edison International and
continue to maintain its authorized capital structure. These restrictions
are not expected to affect Edison International's ability to meet its cash
obligations.
page 32
Edison International's authorized common stock is 800 million shares with
no par value.
During 1996, Edison International purchased on the open market and retired
19,216,627 shares ($344 million) of common stock.
Under Edison International's long-term incentive compensation plan, it
issued 133,131 shares ($2.4 million) in 1996 and 20,900 shares ($0.4
million) in 1995. No shares were issued in 1994.
SCE's authorized shares of preferred and preference stock are: $25
cumulative preferred-24 million; $100 cumulative preferred-12 million; and
preference-50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund
provisions. When preferred shares are redeemed, the premiums paid are
charged to common equity. There are no preferred stock redemption
requirements for the next five years.
EME is a general partner and also owns, indirectly, the limited partner's
share of Mission Capital L.P., which was formed solely for the purpose of
holding parent company debentures. Mission Capital L.P. has 6 million
authorized shares of cumulative preferred securities with a liquidation
preference that obligates EME.
There are no preferred stock redemption requirements for the next five
years.
Edison International subsidiaries' cumulative preferred securities
consisted of:
Dollars in millions, December 31, 1996
except per-share ---------------------------- December 31,
amounts Shares Redemption ------------------
- -------------------- Outstanding Price 1996 1995
------------ ----------- ---- ----
Not subject to mandatory redemption:
$25 par value preferred stock:
4.08% Series 1,000,000 $ 25.50 $ 25 $ 25
4.24 1,200,000 25.80 30 30
4.32 1,653,429 28.75 41 41
4.78 1,296,769 25.80 33 33
5.80 2,200,000 25.25 55 55
7.36 4,000,000 25.00 100 100
---- ----
Total $284 $284
==== ====
Subject to mandatory redemption:
$25 par value preferred securities:
8.50% Series 2,500,000 $ 25.00 $ 63 $ 63
9.875 3,500,000 25.00 87 87
$100 par value preferred stock:
6.05% Series 750,000 100.00 75 75
6.45 1,000,000 100.00 100 100
7.23 1,000,000 100.00 100 100
---- ----
Total $425 $425
==== ====
In 1995, 750,000 shares of Series 7.58% preferred stock were redeemed and
2.5 million shares of Series 8.50% preferred securities were issued. In
1994, 3.5 million shares of Series 9.875% preferred securities were
issued.
page 33
Note 5. Income Taxes
Edison International's subsidiaries will be included in its consolidated
federal income tax and combined state franchise tax returns. Under income
tax allocation agreements, each subsidiary calculates its own tax
liability.
Income tax expense includes the current tax liability from operations and
the change in deferred income taxes during the year. Investment tax
credits are amortized over the lives of the related properties.
The components of the net accumulated deferred income tax liability were:
In millions December 31, 1996 1995
- ----------- ------------ ------ ------
Deferred tax assets:
Property-related $ 247 $ 276
Investment tax credits 206 222
Regulatory balancing accounts 205 166
Decommissioning-related 208 73
Other 660 602
------ ------
Total $1,526 $1,339
Deferred tax liabilities:
Property-related $4,345 $4,346
Leveraged leases 534 508
Other 690 360
------ ------
Total $5,569 $5,214
------ ------
Accumulated deferred income taxes-net $4,043 $3,875
====== ======
Classification of accumulated deferred income taxes:
Included in deferred credits $4,283 $4,352
Included in current assets 240 477
page 34
The current and deferred components of income tax expense were:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Current:
Federal $364 $514 $319
State 108 150 110
---- ---- ----
472 664 429
---- ---- ----
Deferred-federal and state:
Accrued charges (14) 1 (25)
Asset basis adjustment (25) 12 --
Deferred alternative minimum tax credit -- -- 45
Depreciation 71 72 93
Investment and energy tax credits-net (37) (26) (23)
Leveraged leases 26 38 72
Loss carryforwards (41) (37) (37)
Nonutility special charges 9 (21) (14)
Pension reserves 45 (3) (8)
Rate phase-in plan (31) (46) (51)
Regulatory balancing accounts 34 (118) (7)
State tax privilege year 18 (9) (12)
Other (21) (35) (17)
---- ----- ----
34 (172) 16
---- ----- ----
Total income tax expense $506 $492 $445
==== ==== ====
Classification of income taxes:
Included in operating income $563 $528 $481
Included in other income (57) (36) (36)
The composite federal and state statutory income tax rate was 41.045% for
all years presented.
The federal statutory income tax rate is reconciled to the effective tax
rate below:
Year ended December 31, 1996 1995 1994
- ----------------------- ---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software (0.8) (0.8) (2.0)
Depreciation and other 7.3 5.1 5.6
Housing credits (3.6) (2.7) (2.2)
Investment and energy tax credits (2.7) (2.3) (2.2)
State tax-net of federal deduction 6.2 5.6 5.3
---- ---- ----
Effective tax rate 41.4% 39.9% 39.5%
==== ==== ====
Note 6. Employee Benefit Plans
Stock Option Plans
Under Edison International's Long-term Incentive Compensation Plan, 8.2
million shares of common stock were reserved for potential issuance under
various stock compensation programs to directors, officers and senior
managers of Edison International and its affiliates. Under these
programs, there are currently outstanding to officers and senior managers,
options on 3.6 million shares of Edison International common stock. There
page 35
were 4.5 million, 5.4 million, 6.3 million and 6.5 million shares reserved
for future grant at December 31, 1996, 1995, 1994 and 1993, respectively.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market
value of the underlying stock at the date of grant. Edison International
stock options include a dividend equivalent feature. Generally, for
options issued before 1994, amounts equal to dividends accrue on the
options at the same time and at the same rate as would be payable on the
number of shares of Edison International common stock covered by the
options. The amounts accumulate without interest. The optionee has no
right to payment of these dividend equivalents until the underlying stock
options are exercised. For Edison International stock options issued
subsequent to 1993, dividend equivalents are subject to reduction unless
certain shareholder return performance criteria are met.
Edison International stock options have a 10-year term with one-third of
the total award vesting after each of the first three years of the award
term. The options are not transferable, except by will or domestic
relations order. If an optionee retires, dies or is permanently and
totally disabled during the three-year vesting period, the unvested
options will vest and be exercisable to the extent of 1/36 of the grant
for each full month of service during the vesting period. Unvested
options of any person who has served in the past on the Edison
International or SCE Management Committee will vest and be exercisable
upon the member's retirement, death or permanent and total disability.
Upon retirement, death or permanent and total disability, the vested
options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by
retirement, death or permanent and total disability, options which had
vested as of the prior anniversary date of the grant are forfeited unless
exercised within 180 days of the date of termination. All unvested
options are forfeited on the date of termination.
Compensation expense recorded under the stock-compensation program was $9
million, $4 million and $(3) million for 1996, 1995 and 1994,
respectively. A decline during 1994 in the market value of the underlying
shares optioned resulted in the recapture of previously recognized
expense.
Stock-based compensation expense under the fair-value method of accounting
would have resulted in pro forma net income and earnings-per-share
approximating the following amounts:
In millions, except per-share amounts 1996 1995
- ------------------------------------- ---- ----
Pro forma net income $ 714 $ 737
Pro forma earnings-per-share $1.63 $1.65
The fair value for each option granted during 1996 and 1995, reflecting
the basis for the above pro forma disclosures, was determined on the date
of grant using the Black-Scholes option-pricing model. The following
assumptions were used in determining fair value through the model:
1996 1995
---- ----
Expected life 7.0 years 8.0 years
Risk-free interest rate 5.51% 7.93%
Expected volatility 17% 17%
The recognition of dividend equivalents results in no dividends assumed
for purposes of fair-value determination. The application of fair-value
page 36
accounting in arriving at the pro forma disclosures above is not an
indication of future income statement effects. The pro forma disclosures
do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.
A summary of the status of Edison International's stock options is as
follows:
Weighted-Average
------------------------------------------------
Share Exercise Exercise Fair Value Remaining
Options Price Price at Grant Life
- ----------------------------------------------------------------------------------------------------------
Outstanding,
Dec. 31, 1993 1,390,634 $16.00- $24.44 $20.47 7.4 years
Granted 408,800 20.19- 21.94 20.20 $8.07
Expired (7,712) 21.94- 23.28 22.25
Forfeited (25,631) 20.19- 23.28 21.41
Exercised -- -- --
---------
Outstanding,
Dec. 31, 1994 1,766,091 $16.00- $24.44 $20.41 6.9 years
Granted 910,100 14.56- 17.44 14.77 $6.92
Expired (9,930) 20.19- 23.28 21.91
Forfeited (9,120) 14.56- 21.94 19.74
Exercised (20,900) 17.38- 17.75 17.64
---------
Outstanding,
Dec. 31, 1995 2,636,241 $14.56- $24.44 $18.69 7.0 years
Granted 1,091,850 15.81- 18.31 17.57 $6.27
Expired (18,394) 14.56- 23.28 20.08
Forfeited (21,810) 14.56- 20.19 16.24
Exercised (133,131) 14.56- 23.28 18.19
---------
Outstanding,
Dec. 31, 1996 3,554,756 $14.56- $24.44 $18.68 7.0 years
The number of options exercisable and their weighted-average exercise
prices at December 31, 1996, 1995 and 1994 were 1,760,766 at $20.54;
1,240,425 at $21.08 and 1,044,224 at $20.02, respectively.
Phantom Stock Options
"Phantom stock" option performance awards have been developed for two
affiliate companies, EME and Edison Capital, as part of the Edison
International long-term incentive compensation program for senior
management. Each phantom stock option may be exercised to realize any
appreciation in the deemed value of one hypothetical share of EME or
Edison Capital stock over exercise prices. Exercise prices for EME and
Edison Capital phantom stock are escalated on an annually-compounded basis
over the grant price by 12% and 10%, respectively. The deemed values of
the phantom stock are recalculated annually as determined by a formula
linked to the value of its portfolio of investments, less general and
administrative costs. The options have a 10-year term with one-third of
the total award vesting in each of the first three years of the award
term.
Compensation expense recorded with respect to phantom stock options was
$17 million in 1996 and $1 million in 1995. There was no related
compensation expense in 1994, the year the phantom stock option program
commenced.
page 37
Pension Plan
Edison International has a noncontributory, defined-benefit pension plan
that covers employees meeting minimum service requirements. Benefits are
based on years of accredited service and average base pay. Edison
International funds the plan on a level-premium actuarial method. These
funds are accumulated in an independent trust. Annual contributions meet
minimum legal funding requirements and do not exceed the maximum amounts
deductible for income taxes. Prior service costs from pension plan
amendments are funded over 30 years. Plan assets are primarily common
stocks, corporate and government bonds, and short-term investments. In
1996, SCE recorded pension gains from a special voluntary early retirement
program.
The plan's funded status was:
In millions December 31, 1996 1995
- ------------ ------------ ----- ----
Actuarial present value of benefit obligation:
Vested benefits $1,679 $1,703
Nonvested benefits 73 214
------ ------
Accumulated benefit obligation 1,752 1,917
Value of projected future compensation levels 267 487
------ ------
Projected benefit obligation 2,019 2,404
------ ------
Fair value of plan assets 2,171 2,636
------ ------
Projected benefit obligation less than plan assets (152) (232)
Unrecognized net gain 294 327
Unrecognized prior service cost (199) (6)
Unrecognized net obligation
(17-year amortization) (45) (51)
------ ------
Pension liability (asset) $(102) $ 38
====== ======
Discount rate 7.75% 7.25%
Rate of increase in future compensation 5.0% 5.0%
Expected long-term rate of return on assets 8.0% 8.0%
Edison International's utility operations recognize pension expense
calculated under the actuarial method used for ratemaking.
The components of pension expense were:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Service cost for benefits earned $51 $59 $69
Interest cost on projected benefit obligation 180 157 149
Actual return on plan assets (345) (457) (28)
Net amortization and deferral 146 270 (141)
----- ----- -----
Pension expense under accounting standards 32 29 49
Special termination benefits 1 3 15
Regulatory adjustment-deferred 22 23 2
----- ----- -----
Net pension expense recognized 55 55 66
Settlement gain (121) -- --
----- ----- -----
Total expense (gain) $ (66) $ 55 $ 66
===== ===== =====
<page 38>
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service
(or those eligible under the 1996 special voluntary early retirement
program), are eligible for postretirement health and dental care, life
insurance and other benefits. Health and dental care benefits are subject
to deductibles, copayment provisions and other limitations.
Edison International is amortizing its obligation related to prior service
over 20 years. SCE funds its share of these benefits (by contributions
to independent trusts) up to tax-deductible limits, in accordance with
rate-making practices. In 1996, SCE recorded special termination expenses
due to a special voluntary early retirement program. Any difference
between recognized expense and amounts authorized for rate recovery is not
expected to be material (except for the impact of the early retirement
program) and will be charged to earnings.
Trust assets are primarily common stocks, corporate and government bonds,
and short-term investments.
The funded status of these benefits is reconciled to the recorded
liability below:
In millions December 31, 1996 1995
- ----------- ------------ ------ ------
Actuarial present value of benefit obligation:
Retirees $ 933 $ 403
Employees eligible to retire 35 103
Other employees 394 564
------ ------
Accumulated benefit obligation $1,362 $1,070
====== ======
Fair value of plan assets $ 617 $ 400
====== ======
Plan assets less than accumulated benefit
obligation $ 745 $ 670
Unrecognized transition obligation (432) (460)
Unrecognized net gain (loss) (236) (203)
------ ------
Recorded liability $ 77 $ 7
------ ------
Discount rate 7.75% 7.5%
Expected long-term rate of return on assets 8.5 % 8.5%
The components of postretirement benefits other than pensions expense
were:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ----- ----- -----
Service cost for benefits earned $33 $ 36 $30
Interest cost on benefit obligation 91 78 73
Actual return on plan assets (43) (28) (20)
Amortization of loss 6 1 --
Amortization of transition obligation 27 27 36
--- --- ---
Net expense 114 114 119
Amortization of prior funding -- -- 2
Special termination expense 72 -- --
---- ---- ----
Total expense $186 $114 $121
==== ==== ====
page 39
The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1997, gradually decreasing to 5% for 2004 and
beyond. Increasing the health care cost trend rate by one percentage
point would increase the accumulated obligation as of December 31, 1996,
by $206 million and annual aggregate service and interest costs by $24
million.
Employee Savings Plan
Edison International has a 401(k) defined contribution savings plan
designed to supplement employees' retirement income. The plan received
employer contributions of $25 million in 1996, $20 million in 1995 and $21
million in 1994.
Note 7. Jointly-Owned Utility Projects
SCE owns interests in several generating stations and transmission systems
for which each participant provides its own financing. SCE's share of
expenses for each project is included in the consolidated statements of
income.
The investment in each project, as included in the consolidated balance
sheet as of December 31, 1996, was:
Plant in Accumulated Under Ownership
In millions Service Depreciation Construction Interest
- ----------- --------- ------------ ------------ ---------
Transmission systems:
Eldorado $29 $ 8 $ 2 60%
Pacific Intertie 227 72 12 50
Generating stations:
Four Corners (coal)
Units 4 and 5 458 236 2 48
Mohave (coal) 300 142 8 56
Palo Verde (nuclear) 1,596 425 6 16
San Onofre (nuclear) 4,186 1,836 28 75
----- ----- ----
Total $6,796 $2,719 $58
====== ====== ====
Note 8. Leases
Leveraged Leases
Edison Capital is the lessor in several leveraged-lease agreements with
terms of 13 to 30 years. All operating, maintenance, insurance and
decommissioning costs are the responsibility of the lessees. The total
cost of these facilities was $1.8 billion and $1.9 billion at December 31,
1996, and 1995, respectively.
The equity investment in these facilities is 20% of the purchase price.
The remainder is nonrecourse debt secured by first liens on the leased
property. The lenders have accepted their security interests as their
only remedy if the lessee defaults.
page 40
The net investment in leveraged leases consisted of:
In millions December 31, 1996 1995
- ----------- ------------ ---- ----
Rentals receivable (net of principal and
interest on nonrecourse debt) $ 830 $ 833
Unearned income (303) (317)
----- -----
Investment in leveraged leases 527 516
Estimated residual value 58 58
Deferred income taxes (534) (508)
------ ------
Net investment in leveraged leases $ 51 $ 66
====== ======
Lease Commitments
Edison International has operating leases, primarily for vehicles (with
varying terms, provisions and expiration dates) and a capital lease ($91
million) for a nonutility power-production facility.
Estimated remaining commitments for noncancelable leases at December 31,
1996, were:
Operating Capital
In millions Leases Lease
- ----------- --------- -------
Year ended December 31,
1997 $ 25 $ 29
1998 21 28
1999 16 28
2000 14 28
2001 9 --
Thereafter 33 1
---- ----
Total future commitments $118 114
====
Amount representing interest (9.65%) (23)
----
Net commitments $ 91
====
Note 9. Commitments
Nuclear Decommissioning
SCE plans to decommission its nuclear generating facilities at the end of
each facility's operating license by a prompt removal method authorized
by the Nuclear Regulatory Commission. Decommissioning is estimated to
cost $2 billion in current-year dollars, based on site-specific studies
performed in 1993 for San Onofre and 1992 for Palo Verde. Changes in the
estimated costs, timing of decommissioning, or the assumptions underlying
these estimates could cause material revisions to the estimated total cost
to decommission in the near term. Decommissioning is scheduled to begin
in 2013 at San Onofre and 2024 at Palo Verde. San Onofre Unit 1, which
shut down in 1992, is expected to be secured until decommissioning begins
at the other San Onofre units.
Decommissioning costs, which are recovered through customer rates, are
recorded as a component of depreciation expense. Decommissioning expense
was $148 million in 1996, $151 million in 1995 and $122 million in 1994.
page 41
The accumulated provision for decommissioning was $949 million at December
31, 1996, and $823 million at December 31, 1995. The estimated costs to
decommission San Onofre Unit 1 ($263 million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Trust investments include:
December 31,
Maturity ---------------
In millions Dates 1996 1995
- ----------- --------- ---- ----
Municipal bonds 1999-2021 $ 400 $ 348
Stocks -- 549 390
U.S. government issues 1998-2024 212 145
Short-term and other 1996-2024 56 186
------ ------
Trust fund balance (at cost) $1,217 $1,069
====== ======
Trust fund earnings (based on specific identification) increase the trust
fund balance and the accumulated provision for decommissioning. Net
earnings were $49 million in 1996, $51 million in 1995 and $26 million in
1994. Proceeds from the sale of securities (which are reinvested) were
$1.0 billion in 1996 and in 1995, and $1.1 billion in 1994. Approximately
89% of the trust fund contributions were tax-deductible.
The Financial Accounting Standards Board has issued an exposure draft
related to accounting practices for removal costs, including
decommissioning of nuclear power plants. The exposure draft would require
SCE to report its estimated decommissioning costs as a liability, rather
than recognizing these costs over the term of each facility's operating
license (current industry practice). SCE does not believe that the
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
Other Commitments
SCE and EME have fuel supply contracts which require payment only if the
fuel is made available for purchase.
SCE has power-purchase contracts with certain qualifying facilities
(cogenerators and small power producers) and other utilities. The
qualifying facility contracts provide for capacity payments if a facility
meets certain performance obligations and energy payments based on actual
power supplied to SCE. There are no requirements to make debt-service
payments.
SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another
utility. Minimum payments are based, in part, on the debt-service
requirements of the provider, whether or not the plant or transmission
line is operable. The purchased-power contract is not expected to provide
more than 5% of current operating capacity. SCE's minimum commitment
under both contracts is approximately $205 million through 2017.
page 42
Certain commitments for the years 1997 through 2001 are estimated below:
In millions 1997 1998 1999 2000 2001
- ----------- ---- ---- ---- ---- ----
Projected construction $855 $636 $664 $647 $650
expenditures
Fuel supply contracts 358 325 319 340 336
Purchased-power
capacity payments 696 699 701 702 695
Unconditional purchase
obligations 9 10 10 10 10
EME has firm commitments to make equity and other contributions to its
projects of $408 million, primarily for the Paiton project in Indonesia
and the ISAB project in Italy. EME also has contingent obligations to
make additional contributions of $461 million, primarily for a guarantee
as a condition of obtaining a $254 million tax-exempt financing for the
Brooklyn Navy Yard project (discussed further in Note 10), and equity
support guarantees related to Paiton.
Note 10. Contingencies
In addition to the matters disclosed in these notes, Edison International
is involved in legal, tax and regulatory proceedings before various courts
and governmental agencies regarding matters arising in the ordinary course
of business. Edison International believes the outcome of these
proceedings will not materially affect its results of operations or
liquidity.
Brooklyn Navy Yard Project
EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard
project, but funded all of the required equity during construction. The
estimated total cost is $485 million, of which $442 million had been spent
through December 31, 1996. In December 1995, a tax-exempt bond financing
for the project in the amount of $254 million was obtained through the New
York City Industrial Development Agency (NYCIDA). EME has guaranteed the
obligations of the project pursuant to the financing, as well as an
indemnity agreement on behalf of NYCIDA in the amount of $40 million. In
the fourth quarter of 1996, EME executed a new energy sales agreement with
Consolidated Edison Company of New York, which has contracted to buy most
of the project's power and steam, and began selling power and steam under
that agreement. The contractor has recently asserted general monetary
claims under the turnkey agreement against Brooklyn Navy Yard and has
served a complaint for damages in the amount of $136.8 million against
Brooklyn Navy Yard. Brooklyn Navy Yard intends to vigorously defend this
action and to assert general monetary claims against the contractor. EME
believes that the outcome of this litigation will not have a material
adverse effect on its consolidated results of operations or financial
position.
Environmental Protection
Edison International is subject to numerous environmental laws and
regulations, which require it to incur substantial costs to operate
existing facilities, construct and operate new facilities, and mitigate
or remove the effect of past operations on the environment.
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International reviews its
page 43
sites and measures the liability quarterly, by assessing a range of
reasonably likely costs for each identified site using currently available
information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level
of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure.
Unless there is a probable amount, Edison International records the lower
end of this reasonably likely range of costs (classified as other long-
term liabilities at undiscounted amounts). While Edison International has
numerous insurance policies that it believes may provide coverage for some
of these liabilities, it does not recognize recoveries in its financial
statements until they are realized.
Edison International's recorded estimated minimum liability to remediate
its 56 identified sites (55 at SCE and 1 at EME) was $114 million at
December 31, 1996. 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 $211 million. The upper limit of this
range of costs was estimated using assumptions least favorable to Edison
International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 35 of its
sites, representing $101 million of Edison International's recorded
liability, through an incentive mechanism. SCE may request to include
additional sites. Under this mechanism, SCE will recover 90% of cleanup
costs through customer rates; shareholders fund the remaining 10%, with
the opportunity to recover these costs through insurance carriers and
other third parties. SCE has successfully settled insurance claims with
a number of its carriers. Costs incurred at SCE's remaining 20 sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $104 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which
there is a lack of currently available information, including the nature
and magnitude of contamination and the extent, if any, that Edison
International may be held responsible for contributing to any costs
incurred for remediating these sites. Thus, no reasonable estimate of
cleanup costs can now be made for these sites.
Edison International expects to clean up its identified sites over a
period of up to 30 years. Remediation costs in each of the next several
years are expected to range from $4 million to $8 million. Recorded costs
for 1996 were $7 million.
In 1994, SCE utilized an estimating technique to quantify its potential
liability for environmental cleanup in an effort to obtain a reasonably
possible objective and reliable estimate of environmental cleanup. During
1995, EME completed a similar review of some of its sites where known
contamination and potential liability exist and does not believe a
material liability exists as of December 31, 1996.
page 44
Based on currently available information, Edison International believes
it 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 have a material adverse effect on its results
of operations or financial position. There can be no assurance, however,
that future developments, including additional information about existing
sites or the identification of new sites, will not require material
revisions to such estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased
the maximum private primary insurance available ($200 million). The
balance is covered by the industry's retrospective rating plan that uses
deferred premium charges to every reactor licensee if a nuclear incident
at any licensed reactor in the U.S. results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary
level, effective June 1994. The maximum deferred premium for each nuclear
incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its
ownership interests, SCE could be required to pay a maximum of $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability
claims and are subject to adjustment for inflation. If the public
liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500 million
has also been purchased in amounts greater than federal requirements.
Additional insurance covers part of replacement power expenses during an
accident-related nuclear unit outage. These policies are issued primarily
by mutual insurance companies owned by utilities with nuclear facilities.
If losses at any nuclear facility covered by the arrangement were to
exceed the accumulated funds for these insurance programs, SCE could be
assessed retrospective premium adjustments of up to $34 million per year.
Insurance premiums are charged to operating expense.
Note 11. Investments in Partnerships and
Unconsolidated Subsidiaries
Edison International's nonutility subsidiaries have equity interests in
energy generation projects and real estate investment partnerships.
Summarized financial information of these investments was:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Revenue $ 40 $1,400 $1,256
Expenses 62 1,121 969
----- ------ ------
Net income/(loss) $ (22) $ 279 $ 287
====== ====== ======
<page 45>
In millions December 31, 1996 1995
- ----------- ------------ ---- ----
Current assets $ 26 $ 643
Other assets 680 4,818
----- ------
Total assets $ 706 $5,461
----- ------
Current liabilities $ 89 $ 490
Other liabilities 405 3,164
Equity 212 1,807
----- ------
Total liabilities and equity $ 706 $5,461
===== ======
Note 12. Business Segments
Edison International's business segments include electric utility
operations (SCE) and six nonutility segments: unregulated power
generation (EME); financial investments (Edison Capital); real estate
holdings (Mission Land Company); integrated energy solutions (Edison
Source); electric vehicle charging operations (Edison EV); and consumer
products and services (Edison Select). Other than EME, the nonutility
segments are not individually significant and are combined for reporting
purposes.
Edison International's business segment information was:
Unregulated
Power Generation Edison
Electric ------------------- Inter-
In millions Utility Domestic Foreign Other national
- ----------- --------- -------- ------- -------- --------
1996
Operating revenue $7,583 $ 170 $ 674 $ 118 $ 8,545
Operating income 1,711 75 292 (37)(a) 2,041(b)
Depreciation and
decommissioning 1,064 15 75 19 1,173
Assets 17,737 949 4,204 1,669 24,559
Additions to
property and plant 616 4 116 8 744
1995
Operating revenue $7,873 $ 177 $ 290 $ 65 $8,405
Operating income 1,709 73 131 (8)(a) 1,905(b)
Depreciation and
decommissioning 954 10 36 14 1,014
Assets 18,155 842 3,532 1,417 23,946
Additions to
property and plant 773 4 1,231(c) 3 2,011
1994
Operating revenue $ 7,799 $ 170 $ 211 $ 165 $ 8,345
Operating income 1,602 96 85 (3)(a) 1,780(b)
Depreciation and
decommissioning 891 9 31 14 945
Assets 18,076 974 1,869 1,471 22,390
Additions to
property and plant 982 11 136 8 1,137
Corporate items and eliminations are not material.
(a) Excludes reported tax benefits of $80 million in 1996, $44 million in
1995 and $34 million in 1994.
page 46
(b) Excludes income taxes of $563 million in 1996, $528 million in 1995
and $481 million in 1994.
(c) Includes $1,042 million from EME's acquisition of First Hydro.
Quarterly Financial Data
Unaudited
1996
In millions, ---------------------------------------------------
except per-share amounts Total Fourth Third Second First
- ------------------------ ------- ------- ------- ------- -------
Operating revenue $ 8,545 $ 2,195 $ 2,568 $ 1,814 $ 1,968
Operating income 1,478 328 468 332 350
Net income 717 117 277 156 167
Per share:
Earnings 1.64 .27 .63 .35 .38
Dividends declared 1.00 .25 .25 .25 .25
Common stock prices:
High $20 3/8 $20 3/8 $18 1/4 $17 5/8 $18 5/8
Low 15 1/8 17 3/4 15 1/8 15 3/8 16 5/8
Close 19 7/8 19 7/8 17 7/8 17 5/8 17 1/8
1995
In millions, ----------------------------------------------------
except per-share amounts Total Fourth Third Second First
- ------------------------ ------- ------ ------- ------- ------
Operating revenue $ 8,405 $ 2,052 $ 2,670 $ 1,861 $1,822
Operating income 1,377 301 448 310 318
Net income 739 138 288 160 153
Per share:
Earnings 1.66 .31 .65 .36 .34
Dividends declared 1.00 .25 .25 .25 .25
Common stock prices:
High $ 18 $ 18 $ 18 $ 18 $16 7/8
Low 14 3/8 14 7/8 16 3/8 15 3/8 14 3/8
Close 17 5/8 17 5/8 17 3/4 17 1/8 15 5/8
page 47
EDISON INTERNATIONAL AND SUBSIDIARIES
Selected Financial and Operating Data: 1992 - 1996
Dollars in millions,
except per-share amounts* 1996 1995 1994 1993 1992
- ------------------------- ---- ---- ---- ---- ----
Edison International and Subsidiaries
Operating revenue $ 8,545 $ 8,405 $ 8,345 $ 7,839 $ 7,984
Operating expenses $ 7,067 $ 7,028 $ 7,046 $ 6,611 $ 6,641
Net income $ 717 $ 739 $ 681 $ 639 $ 739
Weighted-average shares of common
stock outstanding (in millions) 437 446 448 448 445
Per-share data:
Earnings $ 1.64 $ 1.66 $ 1.52 $ 1.43 $ 1.66
Dividends paid $ 1.00 $ 1.00 $ 1.21 $ 1.41 $ 1.38
Dividends declared $ 1.00 $ 1.00 $ 1.105 $ 1.415 $ 1.39
Book value at year-end $ 15.07 $ 14.41 $ 13.72 $ 13.30 $ 13.30
Market value at year-end $19-7/8 $17-5/8 $14-5/8 $ 20 $ 22
Dividend payout ratio (paid) 61.0% 60.2% 79.6% 98.6% 83.1%
Rate of return on common equity 11.1% 11.8% 11.3% 11.7% 12.5%
Price/earnings ratio 12.1 10.6 9.6 14.0 13.3
Ratio of earnings to fixed charges 2.40 2.55 2.48 2.28 2.68
Assets $24,559 $23,946 $22,390 $21,831 $19,311
Retained earnings $ 3,753 $ 3,700 $ 3,452 $ 3,266 $ 3,263
Common shareholders' equity $ 6,397 $ 6,393 $ 6,144 $ 5,958 $ 5,954
Preferred securities:
Not subject to mandatory redemption $ 284 $ 284 $ 359 $ 359 $ 359
Subject to mandatory redemption $ 425 $ 425 $ 362 $ 275 $ 278
Long-term debt $ 7,475 $ 7,195 $ 6,347 $ 6,459 $ 6,320
Southern California Edison Company
Operating revenue $ 7,583 $ 7,873 $ 7,799 $ 7,397 $ 7,722
Earnings $ 621 $ 643 $ 599 $ 637 $ 631
Earnings per Edison International
common share $ 1.42 $ 1.44 $ 1.34 $ 1.42 $ 1.42
Rate of return on common equity 12.1% 12.6% 12.0% 12.9% 13.2%
Internal generation of funds 130.2% 89% 76% 78% 83%
Peak demand in megawatts (MW) 18,207 17,548 18,044 16,475 18,413
Generation capacity at peak (MW) 21,602 21,603 20,615 20,606 20,712
Kilowatt-hour sales (in millions) 75,572 74,296 77,986 73,308 74,186
Customers (in millions) 4.22 4.18 4.15 4.12 4.11
Full-time employees** 12,057 14,886 16,351 16,585 16,922
Edison Mission Energy
Revenue $ 844 $ 467 $ 381 $ 291 $ 183
Net income $ 92 $ 64 $ 55 $ 2 $ 89
Earnings per Edison International
common share $ .21 $ .14 $ .12 $ .01 $ .20
Assets $ 5,153 $ 4,374 $ 2,843 $ 2,286 $ 2,388
Rate of return on common equity 8.8% 9.5% 9.6% 0.3% 13.7%
Ownership in operating projects (MW) 4,706 4,212 2,048 1,862 1,521
Full-time employees 940 902 690 673 488
Edison Capital
Revenue $ 49 $ 49 $ 47 $ 39 $ 46
Net income $ 41 $ 39 $ 33 $ 29 $ 29
Assets $ 1,423 $ 1,063 $ 1,008 $ 972 $ 826
Rate of return on common equity 17.7% 18.5% 16.8% 14.5% 17.3%
Full-time employees 70 42 33 20 18
* Per share figures reflect the two-for-one split of Edison International
common stock effective June 1, 1993.
** 1992-1994 are based on twelve-month averages.
<page 48>
SHAREHOLDER INFORMATION
Annual Meeting
The 1997 annual meeting of shareholders will be held on Thursday, April
17, 1997, at 10:00 a.m. at the Industry Hills Sheraton Resort and
Conference Center, One Industry Hills Parkway, City of Industry,
California.
Stock Listing and Trading Information
Edison International Common Stock
The New York, Pacific, and London stock exchanges use the ticker symbol
EIX. Daily papers list as EdisonInt.
Preferred Stocks
Southern California Edison's preferred stocks are listed on the American
and Pacific stock exchanges under the ticker symbol SCE. Previous day's
closing prices, when traded, are listed in the daily newspapers in the
American Stock Exchange table under the symbol SoCalEd. The 6.05%, 6.45%
and 7.23% series are not listed. The preferred securities of Mission
Capital, an affiliate of Edison Mission Energy, are listed on the New York
Stock Exchange under the ticker symbol MEPrA for the 9.875% series and
MEPrB for the 8.50% series.
Transfer Agent and Registrar
Southern California Edison maintains shareholder records and is transfer
agent and registrar for Edison International common stock and Southern
California Edison preferred stocks. Shareholders may call Shareholder
Services, (800) 347-8625, between 8:00 a.m. and 4:00 p.m. (Pacific time)
every business day regarding:
o stock transfer and name-change requirements;
o address changes including dividend addresses;
o electronic deposit of dividends;
o taxpayer identification number submission or changes;
o duplicate 1099 and W-9 forms;
o notices of and replacement of lost or destroyed stock certificates
and dividend checks;
o requests to eliminate multiple annual report mailings; and
o Edison International's Dividend Reinvestment Plan, including
enrollments, withdrawals, terminations, sales, transfers and
statements.
The address of Shareholder Services is:
P.O. Box 400, Rosemead, California 91770-0400. FAX: (818) 302-4815
DIVIDEND REINVESTMENT AND ELECTRONIC FUNDS TRANSFER
Shareholders can purchase additional common shares by reinvesting their
quarterly dividends. A prospectus on Edison International's Dividend
Reinvestment Plan is available from Shareholder Services.
Dividend checks can be electronically deposited directly to your financial
institution. Enrollment forms are available upon request.
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