PAGE
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report: February 23, 1996
Date of earliest event reported: February 23, 1996
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
CALIFORNIA 1-2313 95-1240335
(State or other jurisdiction of (Commission (I.R.S. employer
incorporation or organization) file number) identification no.)
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California 91770
(Address of principal executive offices, including zip code)
818-302-1212
(Registrant's telephone number, including area code)
PAGE
Item 5. Other Events
1995 Financial Information
Set forth below are the audited financial statements of
Southern California Edison Company for the year ended December
31, 1995 along with the related Notes and Management's
Discussion and Analysis of Financial Condition.
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Results of Operations
Earnings
Southern California Edison Company's (SCE) 1995 earnings were $643
million, compared with $599 million in 1994, and $637 million in 1993.
Earnings in 1995 increased $44 million over 1994, primarily due to a
higher authorized return on common equity for 1995, partially offset by
the financial effect of the 1995 general rate case settlement. SCE also
recorded employee severance costs of $15 million after-tax in 1995,
compared with $18 million after-tax in 1994. SCE's 1994 earnings
decreased $38 million from 1993, due to employee severance expenses and
a lower authorized return on common equity, partially offset by lower
maintenance expenses at the San Onofre Nuclear Generating Station.
Operating Revenue
Operating revenue increased slightly over 1994, mainly due to a 2.6%
California Public Utilities Commission (CPUC)-authorized rate increase,
partially offset by a decrease in the volume of sales to resale cities and
milder weather in 1995, compared with 1994. Operating revenue increased
in 1994, mainly due to a 3.2% CPUC-authorized rate increase and a 6%
increase in sales volume. Retail sales volume increased from warmer
weather in the third quarter of 1994 compared with 1993. Wholesale volume
increased, as SCE's power was priced lower than many other sources (see
Operating Expenses). In 1995, over 98% of operating revenue was 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, operating revenue during the
third quarter of each year is materially higher than other quarters of the
year.
The changes in operating revenue resulted from:
In millions Year ended December 31, 1995 1994 1993
- ----------- ----------------------- ------ ------ ------
Operating revenue--
Rate changes $ 168 $ 112 $ (251)
Sales volume changes (129) 308 (124)
Other 35 (18) 50
----- ------- -------
Total $ 74 $ 402 $ (325)
===== ======= =======
In March 1995, SCE announced that it intends 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% (from
10.7 cents per kilowatt-hour to below 10 cents per kilowatt-hour), after
adjusting for inflation, subject to CPUC approval. In July 1995, SCE
filed expanded rate options and requested the CPUC expedite the filing in
order to offer these services by 1996. SCE does not anticipate that these
proposals will have a material effect on future earnings trends.
Operating Expenses
Fuel expense decreased 27% in 1995, primarily reflecting a change in the
fuel mix from 1994. Hydro generation was up significantly in 1995, due
to greater rainfall, resulting in lower gas purchases compared with 1994.
In addition, the San Onofre units were out of service a total of five
months in 1995 for refueling and maintenance, causing a decrease in
nuclear fuel expense. Lower overall gas prices also contributed to the
decrease in energy costs. Fuel expense increased 6% in 1994. Although the
overall cost per kilowatt-hour of gas decreased 16% in 1994, gas-powered
generation increased 21% due to higher demand for SCE's lower-priced
energy. The cost per kilowatt-hour of nuclear fuel decreased 4% in 1994,
while nuclear generation increased 20% due to a higher than average
operating capacity factor at San Onofre.
Purchased-power expense increased slightly in 1995 and 1994. SCE makes
federally required power purchases from nonutility generators based on
contracts with CPUC-mandated pricing. Energy prices under these contracts
are generally higher than other energy sources, and for 1995, SCE paid
about $1.8 billion (including energy and capacity payments) more for these
power purchases than the cost of power available from other sources.
Provisions for regulatory adjustment clauses increased in 1995 and 1994,
as CPUC-authorized fuel and purchased-power cost estimates exceeded 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. In 1994,
actual energy costs were lower than estimated due to lower overall gas
prices and a higher than average operating capacity factor at San Onofre.
Other operating expenses include employee severance charges of $25 million
in 1995 and $30 million in 1994. As SCE positions itself for a more
competitive operating environment, it is anticipated that workforce
reductions will continue to occur. In 1995, SCE severed 567 employees,
representing total annualized labor costs of about $42 million. SCE
expects a substantial portion of these labor cost savings to reduce other
operating expenses in 1996. Severance costs are comprised of cash
payments for service and a non-cash benefit component. Excluding
severance charges, other operating expenses decreased in 1995 primarily
due to operating efficiencies.
Maintenance expense increased 8% in 1995, due to the scheduled refueling
and maintenance outages at San Onofre in 1995. Maintenance expense
decreased 8% in 1994, primarily from the San Onofre units operating at a
higher than average capacity factor in 1994.
Other Income and Deductions
The provision for rate phase-in plan reflects a CPUC-authorized, 10-year
rate phase-in plan for Palo Verde Nuclear Generating Station, as further
discussed in Note 1 to the Consolidated Financial Statements. The
provision is a non-cash offset to the collection of deferred revenue.
Interest income increased 21% in 1995, primarily from higher interest
rates and higher investment balances. The higher investment balances
reflect the decline in dividend payments, which began in June 1994.
Interest income increased 18% in 1994, mainly due to higher interest
rates.
Other nonoperating income decreased 29% in 1995 and increased 73% in 1994.
In 1994, SCE received CPUC-authorized incentive awards of $5 million
related to nuclear plant performance and $11 million for energy
conservation programs, and an environmental insurance settlement. In
addition, SCE realized a 1994 benefit resulting from the effect of a drop
in Edison International's (formerly SCEcorp) stock price on it's stock
option plan.
Interest Expense
Other interest expense increased 30% in 1995, mainly due to rising
interest rates and higher balances in the regulatory balancing accounts.
Other interest expense increased 21% in 1994, mainly due to higher
interest rates and increased short-term borrowings.
Financial Condition
SCE's liquidity is primarily affected by debt maturities, dividend
payments and capital expenditures. Capital resources include cash from
operations and external financings.
In June 1994, SCE lowered its quarterly common stock dividend to its
parent, Edison International, by 30%, as the result of uncertainty of
future earnings levels arising from the changing nature of California's
electric utility regulation. The cash flow coverage of dividends increased
to 3.5 times in 1995, from 3.1 times in 1994 and 3.2 times in 1993,
primarily from the lower dividend rate.
In January 1995, Edison International authorized the repurchase of up to
$150 million of its common stock. As excess cash becomes available, SCE
intends to pay cash dividends to Edison International, while maintaining
its CPUC authorized capital structure. Edison International repurchased
4.2 million shares ($70 million) through February 2, 1996, funded by
dividends from Edison International subsidiaries.
PAGE
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Cash Flows from Operating Activities
Net cash provided by operating activities totaled approximately $2.0
billion in 1995, $1.8 billion in 1994 and $1.7 billion in 1993. Cash from
operations exceeded capital requirements for all years presented.
Cash Flows from Financing Activities
Short-term debt was used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital
expenditures. External financings are influenced by market conditions and
other factors, including limitations imposed by SCE's articles of
incorporation and trust indenture. As of December 31, 1995, SCE could
issue approximately $7.9 billion of additional first and refunding
mortgage bonds and $4.2 billion of preferred stock at current interest and
dividend rates.
At December 31, 1995, SCE had available lines of credit of $1.4 billion,
with $900 million for short-term debt and $500 million for the long-term
refinancing of its variable-rate pollution-control bonds. These unsecured
revolving lines of credit are at negotiated or bank index rates with
various expiration dates; the majority have five-year terms.
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, 1995, SCE had the capacity to pay $528 million in additional
dividends and continue to maintain its authorized capital structure.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant and funding of nuclear decommissioning trusts. As
further discussed in Note 9 to the Consolidated Financial Statements,
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 to decommission its nuclear facilities, primarily between
2013-2070. This estimate is based on SCE's current-dollar decommissioning
costs ($1.8 billion), escalated using a 6.65% rate and an earnings
assumption on trust funds ranging from 5.5% to 5.75%. These amounts are
expected to be funded from independent decommissioning trusts, which
receive SCE contributions of approximately $100 million per year (until
decommissioning begins). The Financial Accounting Standards Board has
issued an exposure draft related to accounting practices for removal
costs, including decommissioning of nuclear power plants. SCE does not
expect that the accounting changes proposed in the exposure draft would
have an adverse effect on its results of operations due to its current and
expected future ability to recover these costs through customer rates.
Projected Capital Requirements
SCE's projected capital requirements for the next five years are:
1996--$746 million; 1997--$754 million; 1998--$647 million; 1999--$689
million; and 2000--$673 million.
Long-term debt maturities and sinking fund requirements for the next five
years are: 1996--$1 million; 1997--$501 million; 1998--$447 million;
1999--$155 million; and 2000--$325 million.
Regulatory Matters
On January 10, 1996, the CPUC issued its decision on SCE's 1995 general
rate case. The decision affirmed the CPUC's interim order to reduce 1995
operating revenue by $67 million, but decreased 1996 operating revenue by
an additional $9 million, which includes a $44 million decrease for
operating and maintenance expenses. The decision also authorized recovery
of SCE's remaining investment (approximately $2.7 billion) in San Onofre
Units 2 and 3 at a reduced rate of return (7.34% compared to the current
9.55%), over an eight-year period, beginning in the second quarter of
1996. Future operating costs and incremental capital expenditures at San
Onofre are subject to an incentive pricing plan, where SCE receives about
4 cents per kilowatt-hour. Profits or losses resulting from cost
differences from the incentive price will flow through to
PAGE
shareholders. Beginning in 2004, after SCE's investment is fully
recovered, it would be required to share equally with ratepayers the
benefits received from operation of the units.
The CPUC's 1996 cost-of-capital proceeding authorized an increase to SCE's
equity ratio from 47.75% to 48% and authorized SCE an 11.6% return on
common equity, compared with 12.1% for 1995 and 11% for 1994. This
decision, excluding the effects of other rate actions, would reduce 1996
earnings by approximately $19 million.
A CPUC decision related to SCE's 1996 authorized revenue for fuel and
purchased power is pending. At issue is the treatment of a $237 million
overcollection in the energy cost adjustment clause (ECAC). In SCE's May
1995 ECAC filing, it requested that refund of the overcollection be
deferred until 1997 for rate- stabilization purposes. The CPUC's Division
of Ratepayer Advocates (DRA) filed testimony requesting the overcollection
be refunded over 12 months. Subsequent to its original filing, the DRA
filed comments supporting refund of the overcollection by a one-time
credit applied to customer bills in 1996. In January 1996, an
administrative law judge (ALJ) proposed decision recommended that the ECAC
overcollection be refunded over 12 months in 1996; however, a CPUC
commissioner submitted an alternate proposal requesting adoption of the
one-time credit. On February 6, 1996, SCE filed comments supporting the
alternate proposal. If the CPUC adopts the alternate proposal, SCE's 1996
CPUC-authorized revenue, including the effects of other rate actions,
would be reduced by $338 million, or 4.4%, and SCE would be required to
credit customer bills in the second quarter of 1996. If the CPUC adopts
the ALJ proposed decision, SCE's 1996 CPUC-authorized revenue would
decrease by $575 million, or 7.5%. The reduction in authorized revenue
resulting from this matter will not impact 1996 earnings as these costs
receive balancing account treatment; however, cash flows in 1996 will be
affected. Edison believes it will have sufficient liquidity for the 1996
refund from cash provided by operating activities, projected investment
balances and available lines of credit. A final CPUC decision is expected
in February 1996.
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. The CPUC ordered a
second phase of this proceeding to quantify the disallowance. On December
22, 1995, SCE and the DRA filed a $38 million settlement agreement,
subject to CPUC approval. This agreement has been fully reflected in the
financial statements.
In October 1994, the CPUC authorized SCE to accelerate recovery of its
nuclear plant investments by $75 million per year. The rate impact of
this accelerated cost recovery is offset by a corresponding deceleration
in recovery of transmission and distribution facilities through revised
depreciation estimates over their remaining useful lives. The 1995 general
rate case decision authorized further accelerated recovery of San Onofre.
In 1994, the CPUC ordered the California utilities to proceed with an
energy auction to solicit bids for new contracts with unregulated power
producers. This decision would have forced SCE to purchase 686 MW of new
power at fixed prices starting in 1997, costing SCE customers $14 billion
more than other sources over the lives of the contracts. SCE negotiated
agreements, at substantially lower costs than those mandated by auction,
with eight unregulated power producers, representing 648 MW of the 686
MW mandated. These agreements, which are subject to CPUC approval, would
save SCE customers about 85% of anticipated overpayments compared with the
mandated contracts. After extensive review by the CPUC and the FERC, the
CPUC issued a ruling supporting resolution of the energy auction through
negotiated settlements and set criteria to be used to evaluate the
settlements. SCE has evaluated the impact of these criteria on its
existing settlement agreements and, upon conclusion of settlement
negotiations with the remaining parties, will file an application
requesting CPUC approval (expected in 1996).
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 regulation.
As further discussed in Note 2 to the Consolidated Financial Statements,
on December 20, 1995, the CPUC issued its restructuring decision, which
it had been considering since April 1994. The decision reforms
PAGE
Management's Discussion and Analysis of Results of Operations
and Financial Condition
California's electric utility regulation by creating a market structure
that, over a transition period, would open the electric generation market
to competition and offer customer choice. The transition period would
begin January 1, 1998, with all consumers participating by 2003. Key
elements of the decision include:
o Creation of an independent power exchange 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 to control intrastate
transmission access.
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
power exchange.
o Recovery of costs to transition to a competitive market (utility
investments and obligations incurred to serve customers under the
existing regulatory framework) through a non-bypassable charge,
applied to all customers, called the competition transition charge
(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.
SCE must file within 90 days its plan to address these issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition. SCE had originally filed for a PBR mechanism
in 1993, requesting a revenue-indexing formula to combine operating
expenses and capital-related costs into a single index to determine
most of its revenue (excluding fuel) from 1996-2000. The filing was
subsequently divided between transmission and distribution, and power
generation. Hearings concluded on the transmission and distribution
phase in December 1994. The CPUC's restructuring decision requested
comments addressing whether SCE's transmission and distribution PBR
proposal should be amended or reviewed as filed. On January 19,
1996, SCE requested the CPUC approve its PBR as filed. SCE expects
to file its proposal for the power generation phase in July 1996.
SCE estimates its potential costs to transition to a competitive market
(CTC) at approximately $9.3 billion (net present value), based on incurred
costs, and forecasts of future costs and assumed market prices. These
costs are mainly for qualifying facility contracts, regulatory assets and
other costs incurred (whose recovery has been deferred by the CPUC) to
provide service to customers, and costs pertaining to certain generating
plants. Changes in the assumed market price could require material
revisions to SCE's estimated CTC.
Since restructuring California's electric service industry will have
widespread impact, federal participation and oversight will be required.
The CPUC is seeking to build a California consensus involving the
legislature, governor, public and municipal utilities, and customers, and
to have this consensus in place when approval is sought from the FERC.
In addition the CPUC will prepare an environmental impact report. If the
CPUC's restructuring decision is upheld and implemented as outlined, SCE
would be allowed to recover its CTC (subject to a lower return on equity)
and would continue to apply accounting standards that recognize the
economic effects of rate regulation. The effect of such an outcome would
not be expected to materially affect SCE's results of operations or
financial condition during the transition period.
If revisions are made to the CPUC's restructuring decision that result in
SCE no longer meeting the criteria to apply regulatory accounting
standards to its generation operations, SCE may be required to write off
its recorded generation-related regulatory assets. At December 31, 1995,
these amounts totaled $1.4 billion, excluding balancing account
overcollections of $237 million, which are expected to be refunded to
customers in the near term. 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
PAGE
bases depreciable lives on periodic studies that reflect the assets'
physical useful life. SCE also believes that any depreciation-related
differences would be recovered through the CTC.
Additionally, if revisions are made to the CPUC's restructuring decision
that result in all or a portion of the CTC not being probable of recovery,
SCE could have additional write-offs associated with these costs if they
are not recovered through another regulatory mechanism. At this time, SCE
cannot predict when, or if, a consensus on restructuring will be reached,
what revisions will ultimately be made in the CPUC's restructuring plan
in subsequent proceedings or implementation phases, or the effect, after
the transition period, that competition will have on its results of
operations or financial condition.
FERC Restructuring Proposal
In March 1995, the FERC proposed rules which would require utilities to
provide wholesale open transmission access to the nation's interstate
transmission grid, while allowing them to recover stranded costs
associated with open access. The proposal defines stranded costs as
legitimate, prudent and verifiable costs incurred to provide service to
customers that would subsequently become unbundled wholesale transmission
service customers of the utility. SCE supports the basic principles in
the FERC's proposal and filed comments in August 1995. A final FERC
decision is expected in mid-1996.
Environmental Protection
SCE 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,
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE 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, SCE records the lower
end of this reasonably likely range of costs.
SCE's recorded estimated minimum liability to remediate its 58 identified
sites was $114 million at December 31, 1995, and 1994. One of SCE's
sites, a former pole-treating facility, is considered a federal Superfund
site and represents 71% of its recorded liability. The ultimate costs to
clean up SCE's identified sites may vary from its recorded liability due
to numerous uncertainties inherent in the estimation process. SCE believes
that due to these uncertainties, it is reasonably possible that cleanup
costs could exceed its recorded liability by up to $215 million. The
upper limit of this range of costs was estimated using assumptions least
favorable to SCE among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 24 of its
sites, representing $90 million of its recorded liability, through an
incentive mechanism. Under this mechanism, SCE will recover 90% of
cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs through insurance and other
third-party recoveries. SCE has settled insurance claims with several
carriers, and is continuing to pursue additional recovery. Costs incurred
at SCE's remaining 34 sites are expected to be recovered through customer
rates. SCE has recorded regulatory assets of $104 million for its
estimated minimum environmental-cleanup costs expected to be recovered
through customer rates.
SCE'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 SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can be made for these sites at this
time.
SCE 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 1995 were $3
million.
PAGE
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Based on currently available information, SCE believes it is not likely
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, SCE believes that costs ultimately recorded
will not have a material adverse effect on its results of operations or
financial condition. 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 underway to determine
the specific impact of the effect 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.
SCE's projected capital expenditures to protect the environment are $1.2
billion for the 1996-2000 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.
New Accounting Standard
Effective January 1996, SCE adopted a new accounting standard that
requires impairment losses to be recognized when the book value of an
asset exceeds its future cash flows (undiscounted). The standard also
imposes stricter criteria for the retention of regulatory-created assets,
requiring that they continue to be probable of recovery, rather than
concluding they are not probable of loss. Adoption of this standard did
not materially affect SCE's results of operations or financial condition.
Quarterly Financial Data
1995 1994
----------------------------------------------------------------------------
In millions Total Fourth Third Second First Total Fourth Third Second First
- ----------- ------ ------ ----- ------ ----- ------ ------ ----- ------ -----
Operating revenue $7,873 $1,903 $2,510 $1,738 $1,722 $7,799 $1,846 $2,530 $1,746 $1,677
Operating income 1,149 246 369 261 273 1,094 235 356 253 250
Net income 680 130 251 150 149 639 129 237 132 141
Earnings available for
common stock 643 121 243 140 139 599 119 227 122 131
Common dividends declared 546 136 136 137 137 502 112 119 112 159
PAGE
Consolidated Statements of Income Southern California Edison Company
In thousands Year ended December 31, 1995 1994 1993
- ------------ ----------------------- ------------ ------------ ------------
Operating revenue $ 7,872,718 $ 7,798,601 $ 7,396,599
Fuel 614,954 840,607 792,056
Purchased power 2,581,878 2,562,890 2,498,349
Provisions for regulatory adjustment clauses--net 229,744 54,772 (286,894)
Other operating expenses 1,226,534 1,315,249 1,263,046
Maintenance 356,693 330,161 360,423
Depreciation and decommissioning 954,141 890,656 892,502
Income taxes 559,694 507,626 505,899
Property and other taxes 200,236 202,711 206,775
----------- ---------- ----------
Total operating expenses 6,723,874 6,704,672 6,232,156
----------- ---------- ----------
Operating income 1,148,844 1,093,929 1,164,443
----------- ---------- ----------
Provision for rate phase-in plan (122,233) (136,596) (137,300)
Allowance for equity funds used during construction 19,082 14,348 20,262
Interest income 37,644 31,082 26,318
Other nonoperating income--net 45,651 64,597 37,385
----------- ---------- ----------
Total other income (deductions)--net (19,856) (26,569) (53,335)
----------- ---------- ----------
Income before interest expense 1,128,988 1,067,360 1,111,108
----------- ---------- ----------
Interest on long-term debt 385,187 381,827 399,137
Other interest expense 80,130 61,646 51,071
Allowance for borrowed funds used during construction (14,489) (14,440) (16,167)
Capitalized interest (1,531) (254) (978)
----------- ---------- ----------
Total interest expense--net 449,297 428,779 433,063
----------- ---------- ----------
Net income 679,691 638,581 678,045
Dividends on preferred stock 36,764 40,080 40,722
----------- ---------- ----------
Earnings available for common stock $ 642,927 $ 598,501 $ 637,323
=========== ========== ==========
Consolidated Statements of Retained Earnings
In thousands Year ended December 31, 1995 1994 1993
- ------------ ----------------------- ----------- ----------- -----------
Balance at beginning of year $ 2,683,568 $ 2,586,890 $ 2,428,945
Net income 679,691 638,581 678,045
Dividends declared on common stock (545,672) (501,823) (476,874)
Dividends declared on preferred stock (36,764) (40,080) (40,722)
Reacquired capital stock expense (765) -- (2,504)
----------- ----------- -----------
Balance at end of year $ 2,780,058 $ 2,683,568 $ 2,586,890
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
PAGE
Consolidated Balance Sheets
In thousands December 31, 1995 1994
- ------------ ------------ ------------- -----------
ASSETS
- ------
Utility plant, at original cost $19,850,179 $19,121,964
Less--accumulated provision for depreciation
and decommissioning 8,569,265 7,710,227
----------- -----------
11,280,914 11,411,737
Construction work in progress 727,865 906,766
Nuclear fuel, at amortized cost 139,411 98,044
----------- -----------
Total utility plant 12,148,190 12,416,547
----------- -----------
Nonutility property--less accumulated provision
for depreciation of $25,454 and $30,593
at respective dates 70,191 77,338
Nuclear decommissioning trusts 1,260,095 919,351
Other investments 65,963 39,584
----------- -----------
Total other property and investments 1,396,249 1,036,273
----------- -----------
Cash and equivalents 261,767 192,092
Receivables, including unbilled revenue, less allowances
of $24,139 and $23,806 for uncollectible accounts
at respective dates 911,963 902,090
Fuel inventory 114,357 116,929
Materials and supplies, at average cost 151,180 129,109
Accumulated deferred income taxes--net 476,725 271,308
Prepayments and other current assets 114,289 98,778
----------- -----------
Total current assets 2,030,281 1,710,306
----------- -----------
Unamortized debt issuance and reacquisition expense 350,563 356,557
Rate phase-in plan 129,714 240,730
Unamortized nuclear plant--net 67,185 171,071
Income tax-related deferred charges 1,723,605 1,816,414
Other deferred charges 309,328 327,613
----------- -----------
Total deferred charges 2,580,395 2,912,385
----------- -----------
Total assets $18,155,115 $18,075,511
=========== ===========
The accompanying notes are an integral part of these financial statements.
PAGE
Southern California Edison Company
In thousands, except share amounts December 31, 1995 1994
- ---------------------------------- ------------ ------------- ------------
CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
Common stock (434,888,104 shares outstanding
at each date) $ 2,168,054 $ 2,168,054
Additional paid-in capital 177,333 177,351
Retained earnings 2,780,058 2,683,568
----------- -----------
5,125,445 5,028,973
Preferred stock:
Not subject to mandatory redemption 283,755 358,755
Subject to mandatory redemption 275,000 275,000
Long-term debt 5,215,117 4,987,978
----------- -----------
Total capitalization 10,899,317 10,650,706
----------- -----------
Other long-term liabilities 344,192 311,063
----------- -----------
Current portion of long-term debt 1,375 201,275
Short-term debt 359,508 675,514
Accounts payable 346,258 317,082
Accrued taxes 550,384 514,441
Accrued interest 86,494 87,733
Dividends payable 138,334 115,803
Regulatory balancing accounts--net 337,867 55,710
Deferred unbilled revenue and other current liabilities 809,826 779,257
----------- -----------
Total current liabilities 2,630,046 2,746,815
----------- -----------
Accumulated deferred income taxes--net 3,310,322 3,386,775
Accumulated deferred investment tax credits 374,142 399,662
Customer advances and other deferred credits 597,096 580,490
----------- -----------
Total deferred credits 4,281,560 4,366,927
----------- -----------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $18,155,115 $18,075,511
=========== ===========
The accompanying notes are an integral part of these financial statements.
PAGE
Consolidated Statements of Cash Flows Southern California Edison Company
In thousands Year ended December 31, 1995 1994 1993
- ------------- ----------------------- ------------ ------------ ------------
Cash flows from operating activities:
Net income $679,691 $ 638,581 $ 678,045
Adjustments for non-cash items:
Depreciation and decommissioning 954,141 890,656 892,502
Amortization 68,064 126,131 100,740
Rate phase-in plan 111,016 123,479 123,412
Deferred income taxes and investment tax credits (214,578) (102,179) 106,216
Other long-term liabilities 33,129 44,468 (75,079)
Other--net (261) (23,841) (33,666)
Changes in working capital components:
Receivables (9,873) (64,311) 14,912
Regulatory balancing accounts 282,157 (2,222) (29,591)
Fuel inventory, materials and supplies (19,499) (21,087) (6,592)
Prepayments and other current assets (15,511) (1,260) 78,538
Accrued interest and taxes 34,704 117,819 (176,598)
Accounts payable and other current liabilities 59,745 106,642 (1,554)
---------- ---------- ----------
Net cash provided by operating activities 1,962,925 1,832,876 1,671,285
---------- ---------- ----------
Cash flows from financing activities:
Long-term debt issued 393,829 964 2,155,919
Preferred stock issued -- -- 74,598
Long-term debt repayments (422,503) (170,224) (2,179,772)
Preferred stock redemptions (75,000) -- (86,392)
Nuclear fuel financing--net 31,134 (31,444) 7,663
Short-term debt financing--net (316,006) 62,420 5,447
Dividends paid (559,886) (588,917) (516,121)
---------- ---------- ----------
Net cash used by financing activities (948,432) (727,201) (538,658)
Cash flows from investing activities:
Additions to property and plant (772,950) (981,894) (1,040,425)
Funding of nuclear decommissioning trusts (150,595) (130,155) (140,955)
Other--net (21,273) (6,453) (13,035)
---------- ---------- ----------
Net cash used by investing activities (944,818) (1,118,502) (1,194,415)
---------- ---------- ----------
Net increase (decrease) in cash and equivalents 69,675 (12,827) (61,788)
Cash and equivalents, beginning of year 192,092 204,919 266,707
---------- ---------- ----------
Cash and equivalents, end of year $ 261,767 $ 192,092 $ 204,919
========== ========== ==========
Cash payments for interest and taxes:
Interest $ 382,798 $ 365,126 $ 398,151
Taxes 692,780 443,801 454,201
The accompanying notes are an integral part of these financial statements.
PAGE
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Southern California Edison Company's (SCE) outstanding common stock is
owned entirely by its parent company, Edison International (formerly
SCEcorp). SCE is a public utility which produces and supplies electric
energy for its 4.2 million customers in Central and Southern California.
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated.
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 Consolidated
Financial Statements. 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 the CPUC restructuring decision,
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, 1995, 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
SCE 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 adjustments to
interest expense.
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.
Investments
Cash equivalents include tax-exempt investments ($235 million at December
31, 1995, and $132 million at December 31, 1994), and time deposits and
other investments ($23 million at December 31, 1995, and $53 million at
December 31, 1994) with maturities of three months or less.
Unrealized gains (losses) on equity investments are recorded as regulatory
liabilities (assets). 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
A CPUC-authorized rate phase-in plan deferred the collection of $200
million in revenue for each unit at Palo Verde Nuclear Generating Station
during the first four years of operation. The deferred revenue (including
interest) is being collected evenly over the final six years of each
unit's plan. The plans end in February and September 1996, respectively,
for Units 1 and 2, and in 1998 for Unit 3.
PAGE
Notes to Consolidated Financial Statements
The cost of nuclear fuel, including disposal, is amortized to fuel expense
on the basis of generation. Under CPUC rate-making procedures, nuclear-
fuel financing costs are capitalized until the fuel is placed into
production.
Decommissioning costs are accrued and recovered in rates over the term of
each nuclear facility's operating license through charges to depreciation
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 Division of Ratepayer Advocates (DRA) 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. As part of the agreement, SCE will recover its remaining
investment, earning an 8.98% rate of return on rate base, by August 1996.
In November 1992, SCE discontinued operation of Unit 1.
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.
Recovery of the San Onofre nuclear plant investment has been further
accelerated by the 1995 general rate case decision (see Note 2).
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.
CPUC-established target generation levels act as performance incentives
for SCE's nuclear generating stations. Fuel savings or costs above or
below these targets are shared equally by SCE and its customers through
balancing account adjustments. With the implementation of San Onofre's
incentive pricing plan (see Note 2) in the second quarter of 1996, these
performance incentives were discontinued upon completion of the refueling
outages in 1995.
Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant
construction. If construction does not result, 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 $28 million in 1995, $63
million in 1994 and $49 million in 1993.
Revenue
Operating revenue includes amounts for services rendered but unbilled at
the end of each year.
Utility Plant
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 costs of depreciable utility plant
was 3.6% for 1995, 1994 and 1993.
PAGE
Note 2. Regulatory Matters
1995 General Rate Case
On January 10, 1996, the CPUC issued its decision on SCE's 1995 general
rate case. The decision affirmed the CPUC's interim order to reduce 1995
operating revenue by $67 million, but decreased 1996 operating revenue by
an additional $9 million, which includes a decrease of $44 million for
operating and maintenance expenses. The decision also authorized recovery
of SCE's remaining investment (approximately $2.7 billion) in San Onofre
Units 2 and 3 at a reduced rate of return (7.34% compared to the current
9.55%), over an eight-year period, beginning in the second quarter of
1996.
Future operating costs and incremental capital expenditures at San Onofre
are subject to an incentive pricing plan, where SCE receives about 4 cents
per kilowatt-hour. Profits or losses resulting from cost differences from
the incentive price will flow through to shareholders. Beginning in 2004,
after SCE's investment is fully recovered, it would be required to share
equally with ratepayers the benefits received from operation of the units.
Performance-Based Ratemaking (PBR)
SCE originally filed for a PBR mechanism in 1993, requesting a revenue-
indexing formula to combine operating expenses and capital-related costs
into a single index to determine most of its revenue (excluding fuel) from
1996-2000. The filing was subsequently divided between transmission and
distribution, and power generation. Hearings concluded on the
transmission and distribution phase in December 1994. The CPUC's
restructuring decision, as further discussed below, requested comments
addressing whether SCE's transmission and distribution PBR proposal should
be amended or reviewed as filed. On January 19, 1996, SCE requested the
CPUC approve its PBR as filed. SCE expects to file its proposal for the
power generation phase in July 1996.
CPUC Restructuring Decision
On December 20, 1995, the CPUC issued its decision on restructuring
California's electric industry, which it had been considering since April
1994. The new market structure would provide competition and customer
choice. The transition to a competitive electric market would begin
January 1, 1998, with all consumers participating by 2003. Key elements
of the decision are: creation of an independent power exchange; creation
of an independent system operator; implementation of greater customer
choice; transition cost recovery by the utilities; and CPUC-established
incentives to encourage utilities to voluntarily divest at least 50% of
their gas-fueled units to address market power issues. Within 90 days of
the decision's effective date, SCE must file its plans to address
divestiture issues. Also, under the decision the CPUC would regulate the
rates, terms and conditions of utility services not subject to competition
using PBR instead of cost-of-service regulation.
The independent power exchange, which would manage supply and demand
through an economic auction, will be under FERC jurisdiction. Purchasing
from and selling to the power exchange during the transition period will
be mandatory for California's investor-owned utilities, while others can
voluntarily participate. The independent system operator would have
operational control of the utilities' transmission facilities and,
therefore, would control the scheduling and dispatch of all electricity
on the state's power grid.
The new market structure would provide three avenues of customer choice.
The first involves a continuation of utility-tariffed rates with customers
choosing a monthly average rate or hourly time-of-use rates, which allows
customers with specialized meters to access pricing information and alter
their consumption accordingly. The second avenue involves customers
continuing with utility-tariffed rates and entering into "contracts for
differences" which manage risks associated with the market clearing prices
published by the power exchange. The last avenue involves customers
negotiating directly with generation providers and then arranging for
transmission of the power with the transmission system operator (direct
access).
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable competition transition charge (CTC).
This charge would apply to all customers who currently use utility
services or begin utility service after this decision is effective. SCE
estimates its potential transition costs
PAGE
Notes to Consolidated Financial Statements
(CTC), through 2025 to be approximately $9.3 billion (net present value),
based on incurred costs, and forecasts of future costs and assumed market
prices. However, changes in the assumed market price could require
material revisions to such estimates. The potential transition costs are
comprised of $4.9 billion from SCE's qualifying facility contracts, which
are the direct result of legislative and regulatory mandates; and $4.4
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 nuclear plants (including San Onofre Unit 1 as discussed in Note 1 and
San Onofre Units 2 and 3 as discussed above), nuclear decommissioning and
certain other costs.
Because the restructuring of California's electric industry has widespread
impact and the market structure requires the participation and oversight
of the FERC, the CPUC will seek to build a California consensus involving
the legislature, governor, public and municipal utilities, and customers.
Once the consensus is in place, FERC approval will be sought, and together
both agencies would move forward to implement the new market structure.
In addition, the CPUC will prepare an environmental impact report. As a
result, the CPUC will not proceed with implementation of its decision
until March 1996. If the CPUC's restructuring decision is upheld and
implemented as outlined, SCE would be allowed to recover its CTC (subject
to a lower return on equity) and would continue to apply accounting
standards that recognize the economic effects of rate regulation. The
effect of such an outcome would not be expected to materially affect SCE's
results of operations or financial condition during the transition period.
If revisions are made to the CPUC's restructuring decision that result in
SCE no longer meeting the criteria to apply regulatory accounting
standards to its generation operations, SCE may be required to write-off
its recorded generation-related regulatory assets. At December 31, 1995,
these amounts totaled $1.4 billion (excluding balancing account
overcollections of $237 million expected to be refunded to customers in
the near term), 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. 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 assets'
physical useful life. SCE also believes that any depreciation-related
differences would be recovered through the CTC.
Additionally, if revisions are made to the CPUC's restructuring decision
that result in all or a portion of the CTC not being probable of recovery,
SCE could have additional write-offs associated with these costs if they
are not recovered through another regulatory mechanism. At this time, SCE
cannot predict when, or if, a consensus on restructuring will be reached,
what revisions will ultimately be made in the CPUC's restructuring plan
in subsequent proceedings or implementation phases, or the effect, after
the transition period, that competition will have on its results of
operations or financial condition.
FERC Restructuring Proposal
In March 1995, the FERC proposed rules which would require utilities to
provide wholesale open transmission access to the nation's interstate
transmission grid, while allowing them to recover stranded costs
associated with open access. The proposal defines stranded costs as
legitimate, prudent and verifiable costs incurred to provide service to
customers that would subsequently become unbundled wholesale transmission
service customers of the utility. SCE supports the basic principles in
the FERC's proposal and filed comments in August 1995. A final FERC
decision is expected in mid-1996.
Mohave Generating Station
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. The CPUC ordered a
second phase of this proceeding to quantify the disallowance. On December
22, 1995, SCE and the DRA filed a $38 million settlement agreement subject
to CPUC approval. This agreement has been fully reflected in the
financial statements.
PAGE
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: 1996 $1 million; 1997 $501 million; 1998 $447 million;
1999 $155 million; and 2000 $325 million.
Long-term debt consisted of:
In millions December 31, 1995 1994
- ----------- ------------- ------ ------
First and refunding mortgage bonds:
1997--1999 (5.45% to 7.5%) $ 800 $1,000
2000--2004 (5.625% to 6.75%) 675 675
2017--2026 (6.9% to 9.25%) 1,637 1,850
Pollution-control bonds:
1999--2027 (5.4% to 7.2% and variable) 1,205 1,206
Funds held by trustees (2) (2)
Debentures and notes:
1998--2003 (5.6% to 8.25%) 795 495
Subordinated debentures:
2044 (8.375%) 100 --
Commercial paper for nuclear fuel 70 39
Long-term debt due within one year (1) (201)
Unamortized debt discount--net (64) (74)
------ ------
Total $5,215 $4,988
====== ======
On January 16, 1996, SCE issued $200 million of 5.875% notes, due 2001 and
$200 million of 6.375% notes, due 2006.
Short-Term Debt
SCE has lines of credit it can use at negotiated or bank index rates. At
December 31, 1995, available lines totaled $1.4 billion, with $900 million
for short-term debt and $500 million available for the long-term
refinancing of certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel
inventories, and general cash requirements. Commercial paper outstanding
at December 31, 1995, and 1994, was $433 million and $717 million,
respectively. A portion of commercial paper intended to finance nuclear
fuel scheduled to be used more than one year after the balance sheet date
is classified as long-term debt in connection with refinancing terms under
five-year lines of credit with commercial banks. Weighted-average
interest rates were 5.8% and 5.9%, at December 31, 1995, and 1994,
respectively.
Other Financial Instruments
SCE's risk management policy allows the use of derivative financial
instruments to manage financial exposure on its investments and
fluctuations in interest rates, but prohibits the use of these instruments
for speculative or trading purposes.
PAGE
Notes to Consolidated Financial Statements
Interest rate swaps and caps are used to reduce the potential impact of
interest rate fluctuations on floating rate long-term debt. The interest
rate swap agreement requires the parties to pledge collateral according
to bond rating and market interest rates changes. At December 31, 1995,
SCE had pledged $13 million as collateral due to a downgrade of its bond
rating and 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.
SCE had the following derivative financial instruments at December 31,
1995:
Category Contract Amount/Terms Purpose
- -------- --------------------- -------
Interest rate swaps $196 million fix interest rate exposure
due 2008 at 5.585%
Interest rate cap $30 million fix interest rate exposure
expires 1997 at 6% over variable term
debt due 2027 of the debt
Fair values of financial instruments were:
December 31, 1995 1994
------------- ---- ----
Cost Fair Cost Fair
Instrument In millions Basis Value Basis Value
- ---------- ----------- -------- ----- -------- -----
Financial asset:
Decommissioning trusts $1,069 $1,260 $ 920 $ 919
Equity investments 9 41 9 26
Financial liabilities:
DOE decommissioning and decontamination fees 58 49 62 45
Interest rate swap and cap -- 18 -- 1
Long-term debt 5,215 5,487 4,988 4,763
Preferred stock subject to mandatory redemption 275 288 275 257
Financial assets are carried at their fair value based on quoted market
prices. Financial liabilities are recorded at cost. Financial
liabilities' fair values were based on: termination costs for the
interest rate swap; brokers' quotes for long-term debt, preferred stock
and the cap; and discounted future cash flows for U.S. Department of
Energy (DOE) decommissioning and decontamination fees. Amounts reported
for cash equivalents and short-term debt approximate fair value, due to
their short maturities.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may
pay Edison International. At December 31, 1995, SCE had the capacity to
pay $528 million in additional dividends and continue to maintain its
authorized capital structure.
Authorized common stock is 560 million shares with no par value.
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.
PAGE
Cumulative preferred stock consisted of:
Dollars in millions, except per-share amounts December 31, 1995 1994
- --------------------------------------------- ------------ ---- ----
December 31, 1995
--------------------------
Shares Redemption
Outstanding Price
------------ ----------
Not subject to mandatory redemption:
$25 par value:
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
$100 par value:
7.58% Series -- -- -- 75
---- ----
Total $284 $359
---- ----
Subject to mandatory redemption:
$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 $275 $275
==== ====
Changes in preferred securities were:
Shares in thousands Year ended December 31, 1995 1994 1993
- ------------------- ----------------------- ------ ------ -----
- -
Series:
6.05% -- -- 750
7.325 -- -- (427)
7.80 -- -- (411)
7.58 (750) -- --
----- ----- -----
Net issuances (redemptions) (750) -- (88)
===== ===== =====
Note 5. Income Taxes
SCE and its subsidiaries will be included in Edison International's
consolidated federal income tax and combined state franchise tax returns.
Under income tax allocation agreements, each subsidiary calculates its own
tax liability.
SCE adopted an income tax accounting standard in 1993 that requires the
balance sheet method to account for income taxes. The cumulative effect
of adoption increased 1993 earnings by $8 million and total assets and
liabilities by about $2 billion.
Change in Accounting Principle
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.
PAGE
Notes to Consolidated Financial Statements
The components of the net accumulated deferred income tax liability were:
In millions December 31, 1995 1994
- ----------- ------------ ---- ----
Deferred tax assets:
Property-related $ 276 $ 260
Investment tax credits 222 237
Regulatory balancing accounts 166 85
Other 674 521
-------- --------
Total $ 1,338 $ 1,103
-------- --------
Deferred tax liabilities:
Property-related $ 3,670 $ 3,706
Other 501 513
-------- --------
Total $ 4,171 $ 4,219
-------- --------
Accumulated deferred income taxes--net $ 2,833 $ 3,116
======== ========
Classification of accumulated deferred income taxes:
Included in deferred credits $ 3,310 $ 3,387
Included in current assets 477 271
The current and deferred components of income tax expense were:
In millions Year ended December 31, 1995 1994 1993
- ----------- ----------------------- ---- ---- ----
Current:
Federal $560 $431 $219
State 165 123 83
---- ---- ----
725 554 302
---- ---- ----
Deferred--federal and state:
Accrued charges 1 (25) (38)
Depreciation 21 46 62
Investment and energy tax credits--net (25) (22) (26)
Prior year state tax (12) (14) 13
Rate phase-in plan (46) (51) (51)
Regulatory balancing accounts (118) (7) 118
Resale revenue -- 8 26
Retirement of debt (10) (9) 33
Unbilled revenue (7) (3) 1
Other (19) (25) (32)
---- ---- ----
(215) (102) 106
---- ---- ----
Total income tax expense $510 $452 $408
==== ==== ====
Classification of income taxes:
Included in operating income $560 $508 $506
Included in other income (50) (56) (98)
The composite federal and state statutory income tax rate was 41.045% for
all years presented.
PAGE
The federal statutory income tax rate is reconciled to the effective tax
rate below:
Year ended December 31, 1995 1994 1993
----------------------- ---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software (0.8) (2.1) (1.8)
Investment and energy tax credits (2.2) (2.0) (2.4)
State tax--net of federal deduction 6.5 5.7 5.5
Depreciation and other 4.3 4.9 1.3
---- ---- ----
Effective tax rate 42.8% 41.5% 37.6%
==== ==== ====
Note 6. Employee Benefit Plans
Pension Plan
SCE 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. SCE 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.
The plan's funded status was:
In millions December 31, 1995 1994
- ----------- ------------ ------ ------
Actuarial present value of benefit obligations:
Vested benefits $1,696 $1,260
Nonvested benefits 210 147
------ ------
Accumulated benefit obligation 1,906 1,407
Value of projected future compensation levels 479 450
------ ------
Projected benefit obligation $2,385 $1,857
------ ------
Fair value of plan assets $2,620 $2,194
------ ------
Plan assets greater than projected benefit obligation $ (235) $ (337)
Unrecognized net gain 326 451
Unrecognized prior service cost (6) (5)
Unrecognized net obligation (17-year amortization) (49) (54)
------ ------
Pension liability $ 36 $ 55
====== ======
Discount rate 7.25% 8.5%
Rate of increase in future compensation 5.0% 5.0%
Expected long-term rate of return on assets 8.0% 8.0%
SCE recognizes pension expense calculated under the actuarial method used
for ratemaking.
The components of pension expense were:
In millions Year ended December 31, 1995 1994 1993
- ----------- ----------------------- -------- ------ -------
Net pension expense:
Service cost for benefits earned $ 57 $ 67 $ 69
Interest cost on projected benefit obligation 156 148 138
Actual return on plan assets (454) (28) (289)
Net amortization and deferral 268 (140) 141
----- ----- -----
Pension expense under accounting standards 27 47 59
Special termination benefits 3 15 --
Regulatory adjustment--deferred 22 1 (11)
----- ----- -----
Net pension expense recognized $ 52 $ 63 $ 48
===== ===== =====
PAGE
Notes to Consolidated Financial Statements
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55, with at least 10 years of service,
are eligible for postretirement health care, dental, life insurance and
other benefits. Health care benefits are subject to deductibles,
copayment provisions and other limitations.
In 1993, SCE adopted a new accounting standard for these benefits, which
requires their expected cost to be expensed during employees' years of
service. SCE is amortizing its obligation related to prior service over
20 years. SCE funds these benefits (by contributions to independent
trusts) up to tax-deductible limits, in accordance with rate-making
practices. SCE began funding its liability for these benefits in 1991.
Amounts funded prior to 1993 were amortized and recovered in rates over
12 months. Any difference between recognized expense and amounts
authorized for rate recovery is not expected to be material and will be
charged to earnings.
Trust assets are primarily common stocks, corporate and government bonds,
and short-term investments.
The components of postretirement benefits other than pensions expense
were:
In millions Year ended December 31, 1995 1994 1993
- ----------- ----------------------- ---- ---- ----
Service cost for benefits earned $ 35 $ 29 $ 26
Interest cost on projected benefit obligation 78 72 66
Actual return on plan assets (28) (20) (12)
Amortization of transition obligation 27 36 36
----- ----- -----
Net expense 112 117 116
Amortization of prior funding -- 2 48
----- ----- -----
Total expense $ 112 $ 119 $ 164
====== ====== ======
The funded status of these benefits is reconciled to the recorded liability
below:
In millions December 31, 1995 1994
- ----------- ------------ ---- ----
Actuarial present value of benefit obligation:
Retirees $ 402 $ 530
Employees eligible to retire 103 47
Other employees 556 293
------ ------
Accumulated benefit obligation $1,061 $ 870
------ ------
Fair value of plan assets $ 400 $ 303
------ ------
Plan assets less than accumulated benefit obligation $ 661 $ 567
Unrecognized transition obligation (457) (622)
Unrecognized net loss (gain) (203) 50
------ ------
Recorded liability (asset) $ 1 $ (5)
------ ------
Discount rate 7.5% 8.75%
Expected long-term rate of return on assets 8.5% 8.5%
The assumed rate of future increases in the per-capita cost of health care
benefits is 10% for 1996, gradually decreasing to 5% for 2003 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 1995, by $166
million and annual aggregate service and interest costs by $20 million.
Employee Savings Plan
SCE has a 401(k) stock plan designed to supplement employees' retirement
income. The plan received employer contributions of $20 million in 1995
and $21 million in both 1994 and 1993.
PAGE
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, 1995, was:
Plant in Accumulated Under Ownership
In millions Service Depreciation Construction Interest
- ----------- -------- ------------ ------------ ---------
Transmission systems:
Eldorado $ 28 $ 8 $ -- 60%
Pacific Intertie 221 69 13 50
Generating stations:
Four Corners Units 4 and 5 (coal) 456 230 5 48
Mohave (coal) 289 142 16 56
Palo Verde (nuclear) 1,576 358 17 16
San Onofre (nuclear) 4,203 1,578 22 75
------- ------- ------
Total $ 6,773 $ 2,385 $ 73
======= ======= ======
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms,
provisions and expiration dates.
Estimated remaining commitments for noncancelable leases at December 31,
1995, were:
Year ended December 31, In millions
- ----------------------- -----------
1996 $21
1997 18
1998 15
1999 10
2000 8
Thereafter 8
---
Total $80
===
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 $1.8 billion in current-year dollars based on site-specific studies
performed in 1993 for San Onofre and 1992 for Palo Verde. This estimate
considers the total cost of decommissioning and dismantling the plant,
including labor, material, burial and other costs. The site specific
studies are updated approximately every three years. 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. Currently, San Onofre Unit
1, which shut down in 1992, is expected to be stored 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 $151 million in 1995, $122 million in 1994 and $141 million in 1993.
The accumulated provision for decommissioning was $823 million at December
31, 1995,
PAGE
Notes to Consolidated Financial Statements
and $692 million at December 31, 1994. The estimated costs to
decommission San Onofre Unit 1 ($247 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 (in millions) include:
Gross Unrealized Holding
--------------------------------------
Gains Losses
---------------- ----------------
December 31, 1995 1994 1995 1994 1995 1994
Municipal bonds $ 348 $ 447 $ 48 $ -- $ -- $ (10)
Stocks 390 258 127 9 -- --
U.S. government issues 145 98 10 -- -- --
Short-term and other 186 117 6 -- -- --
------ ----- ---- --- ---- -----
Total $1,069 $ 920 $191 $ 9 $ -- $ (10)
====== ===== ==== === ==== =====
Maturities by class of security are: municipal bonds--1998-2002; U.S.
government issues--1997-2025; and other--1997-2045.
Trust fund earnings (based on specific identification) increase the trust
fund balance and the accumulated provision for decommissioning. Net
earnings were $51 million in 1995, $26 million in 1994 and $45 million in
1993. Proceeds from sales of securities (which are reinvested) were $1.0
billion in 1995, $1.1 billion in 1994 and $372 million in 1993.
Approximately 88% 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 due to its current and expected future ability to
recover these costs through customer rates.
Other Commitments
SCE has 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 or estimated future operating capacity. SCE's
minimum commitment under both contracts is approximately $225 million
through 2017.
Certain commitments for the years 1996 through 2000 are estimated below:
In millions 1996 1997 1998 1999 2000
- ----------- ----- ----- ----- ----- -----
Projected construction expenditures $ 746 $ 754 $ 647 $ 689 $ 673
Fuel supply contracts 214 212 207 215 220
Purchased-power capacity payments 722 727 731 735 736
Unconditional purchase obligations 12 12 12 12 12
PAGE
Note 10. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in
legal, tax and regulatory proceedings before various courts and
governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these proceedings will not
materially affect its results of operations or liquidity.
Environmental Protection
SCE 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.
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing
technology, presently enacted laws and regulations, experience gained at
similar sites, and the probable level of involvement and financial
condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and
maintenance, monitoring and site closure. Unless there is a probable
amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities at undiscounted amounts).
While SCE 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.
SCE's recorded estimated minimum liability to remediate its 58 identified
sites was $114 million, at December 31, 1995 and 1994. The ultimate costs
to clean up SCE'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. SCE believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed
its recorded liability by up to $215 million. The upper limit of this
range of costs was estimated using assumptions least favorable to SCE
among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 24 of its
sites, representing $90 million of its recorded liability, through an
incentive mechanism (SCE may request to include additional sites). Under
this mechanism, SCE will recover 90% of cleanup costs through customer
rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs through insurance and other third-party recoveries.
SCE has settled insurance claims with several carriers, and is continuing
to pursue additional recovery. Costs incurred at the remaining 34 sites
are expected to be recovered through customer rates. SCE has filed a
request with the CPUC to add 11 of these sites ($6 million in estimated
minimum liability) to the incentive mechanism. SCE has recorded a
regulatory asset of $104 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates.
SCE'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 SCE may be held responsible
for contributing to any costs incurred for remediating these sites. Thus,
no reasonable estimate of cleanup costs can be made for these sites at
this time.
SCE 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 1995 were $3
million.
Based on currently available information, SCE believes it is not likely
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, SCE believes that costs ultimately recorded will not have
a material adverse effect on its results of operations or financial
condition. There can be no assurance, however, that future developments,
PAGE
Notes to Consolidated Financial Statements
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 in the event that a
nuclear incident at any licensed reactor in the U.S. results in
claims/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. In the event that the
public liability limit above is insufficient Federal Regulations will
impose further revenue raising measures to pay claims, including a
possible additional assessment upon all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500 million
also has been purchased in amounts greater than federal requirements.
Additional insurance covers part of replacement power expenses during an
accident-related nuclear unit outage. These policies are issued
primarily by mutual insurance companies owned by utilities with nuclear
facilities. If losses at any nuclear facility covered by the arrangement
were to exceed the accumulated funds for these insurance programs, SCE
could be assessed retrospective premium adjustments of up to $44 million
per year. Insurance premiums are charged to operating expense.
PAGE
Responsibility for Financial Reporting
The management of Southern California Edison Company (SCE) 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.
SCE maintains 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. SCE
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, policies and procedures
are monitored, evaluated and reported to management. Actions are taken
to correct deficiencies as they are identified.
SCE'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 SCE'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
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 SCE's systems of internal control;
reviews financial reporting issues; and is advised of management's actions
regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing
personnel to assure that its operations are conducted in conformity with
applicable laws and is 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 Chairman of the Board
and Controller and Chief Executive Officer
February 2, 1996
PAGE
Report of Independent Public Accountants Southern California Edison Company
To the Shareholders and the Board of Directors,
Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE, a California corporation) and its
subsidiaries as of December 31, 1995, and 1994, and the related
consolidated statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1995. These
financial statements are the responsibility of SCE'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 SCE and its
subsidiaries as of December 31, 1995, and 1994, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.
As discussed in Notes 5 and 6 to the financial statements, and as required
by generally accepted accounting principles, SCE changed its methods of
accounting for income taxes and postretirement benefits other than
pensions in 1993.
ARTHUR ANDERSEN LLP
Los Angeles, California
February 2, 1996
Item 7. Financial Statements, Pro Forma
(c) Exhibits
12 Computation of Ratio of Earnings
to Fixed Charges
23 Consent of Independent Public
Accountants
27 Financial Data Schedule
PAGE
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
Kenneth S. Stewart
______________________________________
Kenneth S. Stewart
Assistant General Counsel
February 23, 1996