SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-3141
JERSEY CENTRAL POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
New Jersey 21-0485010
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 Madison Avenue
Morristown, New Jersey 07962-1911
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (201) 455-8200
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class Title of each class on which registered
Cumulative Preferred
Stock, no par value
$100 stated value: First Mortgage Bonds:
4 % Series 7 1/8% Series due 2004 New York Stock Exchange
7.88% Series E 6 3/8% Series due 2003 "
7 1/2% Series due 2023 "
6 3/4% Series due 2025 "
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the registrant's voting stock held by
nonaffiliates: None
The number of shares outstanding of each of the registrant's classes of
voting stock as of February 28, 1994 was as follows:
Common Stock, par value $10 per share: 15,371,270 shares outstanding
TABLE OF CONTENTS
Page
Number
Part I
Item 1. Business 1
Item 2. Properties 25
Item 3. Legal Proceedings 26
Item 4. Submission of Matters to a Vote of
Security Holders 26
Part II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters 27
Item 6. Selected Financial Data 27
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 27
Item 8. Financial Statements and Supplementary Data 27
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 27
Part III
Item 10. Directors and Executive Officers of the
Registrant 28
Item 11. Executive Compensation 31
Item 12. Security Ownership of Certain Beneficial
Owners and Management 35
Item 13. Certain Relationships and Related Transactions 35
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 36
Signatures 37
Index to Supplementary Data, Financial Statements
and Financial Statement Schedules F-1
PART I
ITEM 1. BUSINESS.
Jersey Central Power & Light Company (the Company), which was
incorporated under the laws of New Jersey in 1925, is a wholly owned
subsidiary of General Public Utilities Corporation (GPU), a holding company
registered under the Public Utility Holding Company Act of 1935 (the 1935
Act). The Company's business consists predominantly of the generation,
transmission, distribution and sale of electricity.
The Company is affiliated with Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are
referred to herein as the "Company and its affiliates." The Company is also
affiliated with GPU Service Corporation (GPUSC), a service company; GPU
Nuclear Corporation (GPUN), which operates and maintains the nuclear units of
the Company and its affiliates; and General Portfolios Corporation (GPC),
parent of Energy Initiatives, Inc. (EI), which develops, owns and operates
nonutility generating facilities. All of the Company's affiliates are wholly
owned subsidiaries of GPU. The Company and its affiliates own all of the
common stock of the Saxton Nuclear Experimental Corporation, which owns a
small demonstration nuclear reactor that has been partially decommissioned.
The Company and its affiliates, GPUSC, GPUN and GPC are referred to as the
"GPU System."
As a subsidiary of a registered holding company, the Company is subject
to regulation by the Securities and Exchange Commission (SEC) under the 1935
Act. The Company's retail rates, conditions of service, issuance of
securities and other matters are subject to regulation by the New Jersey Board
of Regulatory Commissioners (NJBRC). The Nuclear Regulatory Commission (NRC)
regulates the construction, ownership and operation of nuclear generating
stations. The Company is also subject to regulation by the Federal Energy
Regulatory Commission (FERC) under the Federal Power Act. (See "Regulation.")
Industry Developments
The Energy Policy Act of 1992 (Energy Act) has made significant changes
to the 1935 Act and the Federal Power Act. As a result of this legislation,
the FERC is now authorized to order utilities to provide transmission or
wheeling service to third parties for wholesale power transactions provided
specified reliability and pricing criteria are met. In addition, the
legislation amends the 1935 Act to permit the development and ownership of a
broad category of independent power production facilities by utilities and
nonutilities alike without subjecting them to regulation under the 1935 Act.
These and other aspects of the Energy Act are expected to accelerate the
changing character of the electric utility industry.
The electric utility industry appears to be undergoing a major transition
as it proceeds from a traditional rate regulated environment based on cost
recovery to some combination of a competitive marketplace and modified
regulation of certain market segments. The industry challenges resulting from
various instances of competition, deregulation and restructuring thus far have
been minor compared with the impact that is expected in the future. The
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Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry
of competitors into the electric generation business. Since then, more
competition has been introduced through various state actions to encourage
cogeneration and, most recently, the Energy Act. The Energy Act is intended
to promote competition among utility and nonutility generators in the
wholesale electric generation market, accelerating the industry restructuring
that has been underway since the enactment of PURPA. This legislation,
coupled with increasing customer demands for lower-priced electricity, is
generally expected to stimulate even greater competition in both the wholesale
and retail electricity markets. These competitive pressures may create
opportunities to compete for new customers and revenues, as well as increase
risk which could lead to the loss of customers.
Operating in a competitive environment will place added pressures on
utility profit margins and credit quality. Utilities with significantly
higher cost structures than supportable in the marketplace may experience
reduced earnings as they attempt to meet their customers' demands for lower-
priced electricity. This prospect of increasing competition in the electric
utility industry has already led the major credit rating agencies to address
and apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the FERC, subject to certain
criteria, to order owners of electric transmission systems, such as the
Company and its affiliates, to provide third parties with transmission access
for wholesale power transactions. The Energy Act did not give the FERC the
authority, however, to order retail transmission access. Movement toward
opening the transmission network to retail customers is currently under
consideration in several states.
The competitive forces have also begun to influence some retail pricing
in the industry. In a few instances, industrial customers, threatening to
pursue cogeneration, self-generation or relocation to other service
territories, have leveraged price concessions from utilities. Recent state
regulatory actions, such as in New Jersey, suggest that utilities may have
limited success with attempting to shift costs associated with such discounts
to other customers. Utilities may have to absorb, in whole or part, the
effects of price reductions designed to retain large retail customers. State
regulators may put a limit or cap on prices, especially for those customers
unable to pursue alternative supply options.
Insofar as the Company is concerned, unrecovered costs will most likely
be related to generation investment, purchased power contracts, and
"regulatory assets", which are deferred accounting transactions whose value
rests on the strength of a state regulatory decision to allow future recovery
from ratepayers. In markets where there is excess capacity (as there
currently is in the region including New Jersey) and many available sources of
power supply, the market price of electricity may be too low to support full
recovery of capital costs of certain existing power plants, primarily the
capital intensive plants such as nuclear units. Another significant exposure
in the transition to a competitive market results if the prices of a utility's
existing purchase power contracts, consisting primarily of contractual
obligations with nonutility generators, are higher than future market prices.
Utilities locked into expensive purchase power arrangements may be forced to
value the contracts at market prices and recognize certain losses. A third
2
source of exposure is regulatory assets which if not supported by regulators
would have no value in a competitive market. Financial Accounting Standard
No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation,"
applies to regulated utilities that have the ability to recover their costs
through rates established by regulators and charged to customers. If a
portion of the Company's operations continues to be regulated, FAS 71
accounting may only be applied to that portion. Write-offs of utility plant
and regulatory assets may result for those operations that no longer meet the
requirements of FAS 71. In addition, under deregulation, the uneconomical
costs of certain contractual commitments for purchased power and/or fuel
supplies may have to be expensed. Management believes that to the extent that
the Company no longer qualifies for FAS 71 accounting treatment, a material
adverse effect on its results of operations and financial position may result.
At this time, it is difficult for management to project the future level of
stranded assets or other unrecoverable costs, if any, without knowing what the
market price of electricity will be, or if regulators will allow recovery of
industry transition costs from customers.
Corporate Realignment
In February 1994, GPU announced a corporate realignment and related
actions as a result of its ongoing strategic planning studies. GPU Generation
Corporation (GPU Generation) will be formed to operate and maintain the
fossil-fueled and hydroelectric generating units of the Company and its
affiliates; ownership of the generating assets will remain with the Company
and its affiliates. GPU Generation will also build new generation facilities
as needed by the Company and its affiliates in the future. Involvement in the
independent power generation market will continue through EI. Additionally,
the management and staff of Penelec and Met-Ed will be combined but the two
companies will not be merged and will retain their separate corporate
existence. This action is intended to increase effectiveness and lower cost.
Included in this effort will be a search for parallel opportunities at GPUN
and the Company. Completion of these realignment initiatives will be subject
to various regulatory reviews and approvals from the SEC, FERC, NJBRC and the
Pennsylvania Public Utility Commission (PaPUC). The GPU System is also
developing a performance improvement and cost reduction program to help assure
ongoing competitiveness, and, among other matters, will also address workforce
issues in terms of compensation, size and skill mix. The GPU System is
seeking annual cost savings of approximately $80 million by the end of 1996 as
a result of these organizational changes.
Duquesne Transaction
In September 1990, the Company and its affiliates entered into a series
of interdependent agreements with Duquesne Light Company (Duquesne) for the
purchase of a 50% ownership interest in Duquesne's 300 megawatt (MW) Phillips
generating station and the joint construction and ownership of associated high
voltage bulk transmission facilities. The Company and its affiliates' share
of the total cost of these agreements was estimated to be $500 million, of
which the Company's share was $215 million, the major part of which was
expected to be incurred after 1994. In addition, the Company and Met-Ed
simultaneously entered into a related agreement with Duquesne to purchase
350 MW of capacity and energy from Duquesne for 20 years beginning in 1997.
The Company and its affiliates and Duquesne filed several petitions with the
3
PaPUC and the NJBRC seeking certain of the regulatory authorizations required
for the transactions.
In December 1993, the NJBRC denied the Company's request to participate
in the proposed transactions. As a result of this action and other
developments, the Company and its affiliates notified Duquesne that they were
exercising their rights under the agreements to withdraw from and thereby
terminate the agreements. Consequently, the Company wrote off the
approximately $9 million it had invested in the project.
General
The Company is an electric public utility furnishing service entirely
within the State of New Jersey. It provides retail service in northern,
western and east central New Jersey having an estimated population of
approximately 2.4 million.
The electric generating and transmission facilities of the Company,
Met-Ed and Penelec are physically interconnected and are operated as a single
integrated and coordinated system. The transmission facilities are physically
interconnected with neighboring nonaffiliated utilities in Pennsylvania, New
Jersey, Maryland, New York and Ohio. The Company and its affiliates are
members of the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and the
Mid-Atlantic Area Council, an organization providing coordinated review of the
planning by utilities in the PJM area. The interconnection facilities are
used for substantial capacity and energy interchange and purchased power
transactions as well as emergency assistance.
During 1993, residential sales accounted for approximately 44% of the
Company's operating revenues from customers and 40% of kilowatt-hour (kWh)
sales to customers; commercial sales accounted for approximately 37% of
operating revenues from customers and 37% of kWh sales to customers;
industrial sales accounted for approximately 17% of operating revenues from
customers and 21% of kWh sales to customers; and sales to a rural electric
cooperative, municipalities (primarily for street and highway lighting), and
others accounted for approximately 2% of operating revenues from customers and
2% of kWh sales to customers. The Company also makes interchange and spot
market sales of electricity to other utilities. The revenues derived from the
largest single customer accounted for less than 3% of the electric operating
revenues for the year and the 25 largest customers, in the aggregate,
accounted for approximately 10% of such revenues. Reference is made to
"Company Statistics" on page F-2 for additional information concerning the
Company's sales and revenues.
The Company and its affiliates along with the other members of the PJM
power pool, experienced an electric emergency due to extremely cold
temperature from January 18 through January 20, 1994. In order to maintain
the electric system and to avoid a total black-out, intermittent black-outs
for periods typically of one to two hours were instituted on January 19, 1994
to control peak loads. In February 1994, the NJBRC, the PaPUC and the FERC
initiated investigations of the energy emergency, and forwarded data requests
to all affected utilities. In addition, the United States House of
Representatives' Energy and Power Subcommittee, among others, held hearings on
this matter. At this time, management is unable to estimate the impact, if
any, from any conclusions that may be reached by the regulators.
4
Competition in the electric utility industry has already played a
significant role in wholesale transactions, affecting the pricing of energy
sales to electric cooperatives and municipal customers. During 1993, Penelec
successfully negotiated power supply agreements with several Company wholesale
customers in response to offers made by other utilities seeking to provide
electric service at rates lower than those of the Company. Wholesale
customers represent a relatively small portion of GPU System sales.
Nuclear Facilities
The Company has made investments in three major nuclear projects -- Three
Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational
generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged
during a 1979 accident. At December 31, 1993, the Company's net investment in
TMI-1 and Oyster Creek, including nuclear fuel, was $173 million and
$784 million, respectively. TMI-1 and TMI-2 are jointly owned by the Company,
Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively.
Oyster Creek is owned by the Company.
Costs associated with the operation, maintenance and retirement of
nuclear plants have continued to increase and become less predictable, in
large part due to changing regulatory requirements and safety standards and
experience gained in the construction and operation of nuclear facilities.
The Company and its affiliates may also incur costs and experience reduced
output at their nuclear plants because of the design criteria prevailing at
the time of construction and the age of the plants' systems and equipment. In
addition, for economic or other reasons, operation of these plants for the
full term of their now assumed lives cannot be assured. Also, not all risks
associated with ownership or operation of nuclear facilities may be adequately
insured or insurable. Consequently, the ability of electric utilities to
obtain adequate and timely recovery of costs associated with nuclear projects,
including replacement power, any unamortized investment at the end of the
plants' useful life (whether scheduled or premature), the carrying costs of
that investment and retirement costs, is not assured. Management intends, in
general, to seek recovery of any such costs described above through the
ratemaking process, but recognizes that recovery is not assured.
TMI-1
TMI-1, a 786 MW pressurized water reactor, was licensed by the NRC in
1974 for operation through 2008. The NRC has extended the TMI-1 operating
license through April 2014, in recognition of the plant's approximate six-year
construction period. During 1993, TMI-1 operated at a capacity factor of
approximately 87%. A scheduled refueling outage that year lasted 36 days; the
next refueling outage is scheduled for late 1995.
Oyster Creek
The Oyster Creek station, a 610 MW boiling water reactor, received a
provisional operating license from the NRC in 1969 and a full-term operating
license in 1991. In April 1993, the NRC extended the station's operating
license from 2004 to 2009 in recognition of the plant's approximate four-year
construction period. The plant operated at a capacity factor of approximately
87% during 1993. A scheduled refueling outage lasted 81 days and the plant
returned to service on February 16, 1993. The next refueling outage is
scheduled for September 1994.
5
TMI-2
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and, after receiving NRC approval,
TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the U. S.
District Court for the Middle District of Pennsylvania. Some of the claims
also seek recovery for injuries from alleged emissions of radioactivity before
and after the accident. Questions have not yet been resolved as to whether
the punitive damage claims are (a) subject to the overall limitation of
liability set by the Price-Anderson Act ($560 million at the time of the
accident) and (b) outside the primary insurance coverage provided pursuant to
that Act (remaining primary coverage of approximately $80 million as of
December 1993). If punitive damages are not covered by insurance or are not
subject to the Price-Anderson liability limitation, punitive damage awards
could have a material adverse effect on the financial position of the Company.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of twelve allegedly representative
cases is scheduled to begin in October 1994. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable Federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment.
Nuclear Plant Retirement Costs
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE). See Note 2
to Financial Statements for further information regarding nuclear fuel
disposal costs.
In 1990, the Company and its affiliates submitted a report, in compliance
with NRC regulations, setting forth a funding plan (employing the external
sinking fund method) for the decommissioning of their nuclear reactors. Under
this plan, the Company and its affiliates intend to complete the funding for
Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014,
respectively. The TMI-2 funding completion date is 2014, consistent with
TMI-2 remaining in long-term storage and being decommissioned at the same time
as TMI-1. Under the NRC regulations, the funding target (in 1993 dollars) for
TMI-1 is $143 million, of which the Company's share is $36 million, and for
Oyster Creek is $175 million. Based on NRC studies, a comparable funding
6
target for TMI-2 (in 1993 dollars), which takes into account the accident, is
$228 million, of which the Company's share is $57 million. The NRC is
currently studying the levels of these funding targets. Management cannot
predict the effect that the results of this review will have on the funding
targets. NRC regulations and a regulatory guide provide mechanisms, including
exemptions, to adjust the funding targets over their collection periods to
reflect increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not actual cost
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $205 to $285 million, of which the Company's share is $51
to $71 million, and $220 to $320 million, respectively (adjusted to 1993
dollars). In addition, the studies estimated the cost of removal of
nonradiological structures and materials for TMI-1 and Oyster Creek at
$72 million, of which the Company's share is $18 million, and $47 million,
respectively.
The ultimate cost of retiring the Company and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies and cannot now be more
reasonably estimated than the level of the NRC funding target because such
costs are subject to (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time
of decommissioning. The Company charges to expense and contributes to
external trusts amounts collected from customers for nuclear plant
decommissioning and nonradiological costs. In addition, in 1990 the Company
contributed to an external trust an amount not recoverable from customers for
nuclear plant decommissioning.
TMI-1 and Oyster Creek
The Company is collecting revenues for decommissioning, which are
expected to result in the accumulation of its share of the NRC funding target
for each plant. The Company is also collecting revenues for the cost of
removal of nonradiological structures and materials at each plant based on its
share ($3.83 million) of an estimated $15.3 million for TMI-1 and
$31.6 million for Oyster Creek. Collections from customers for
decommissioning expenditures are deposited in external trusts. These external
trust funds, including the interest earned, are classified as Decommissioning
Funds on the balance sheet. Provision for the future expenditure of these
funds has been made in accumulated depreciation, amounting to $13 million for
TMI-1 and $80 million for Oyster Creek at December 31, 1993.
7
Management believes that any TMI-1 and Oyster Creek retirement costs, in
excess of those currently recognized for ratemaking purposes, should be
recoverable through the ratemaking process.
TMI-2
The Company has recorded a liability, amounting to $57 million as of
December 31, 1993, for its share of the radiological decommissioning of TMI-
2, reflecting the NRC funding target (unadjusted for an immaterial decrease in
1993). The Company records escalations, when applicable, in the liability
based upon changes in the NRC funding target. The Company has also recorded a
liability in the amount of $5 million for its share of incremental costs
specifically attributable to monitored storage. Such costs are expected to be
incurred between 1994 and 2014, when decommissioning is forecast to begin. In
addition, the Company has recorded a liability in the amount of $18 million
for its share of the nonradiological cost of removal. The above amounts for
retirement costs and monitored storage are reflected as Three Mile Island Unit
2 Future Costs on the balance sheet. The Company has made a nonrecoverable
contribution of $15 million to an external decommissioning trust.
The NJBRC has granted the Company decommissioning revenues for the
remainder of the NRC funding target and allowances for the cost of removal of
nonradiological structures and materials. Management intends to seek recovery
for any increases in TMI-2 retirement costs, but recognizes that recovery
cannot be assured.
As a result of TMI-2's entering long-term monitored storage, the Company
is incurring incremental storage costs currently estimated at $.25 million
annually. The Company has deferred the $5 million for its share of the total
estimated incremental costs attributable to monitored storage through 2014,
the expected retirement date of TMI-1. The Company's share of these costs has
been recognized in rates by the NJBRC.
Insurance
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the Company.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered
one site for insurance purposes) and for Oyster Creek totals $2.7 billion per
site. In accordance with NRC regulations, these insurance policies generally
require that proceeds first be used to stabilize the reactors and then to pay
for decontamination and debris removal expenses. Any remaining amounts
available under the policies may then be used for repair and restoration costs
and decommissioning costs. Consequently, there can be no assurance that, in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of the stations.
8
The Price-Anderson Act limits the GPU System's liability to third parties
for a nuclear incident at one of its sites to approximately $9.4 billion.
Coverage for the first $200 million of such liability is provided by private
insurance. The remaining coverage, or secondary protection, is provided by
retrospective premiums payable by all nuclear reactor owners. Under secondary
protection, a nuclear incident at any licensed nuclear power reactor in the
country, including those owned by the GPU System, could result in assessments
of up to $79 million per incident for each of the GPU System's three reactors,
subject to an annual maximum payment of $10 million per incident per reactor.
In 1993, GPUN requested an exemption from the NRC to eliminate the secondary
protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at their
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years at decreasing levels beginning at weekly amounts of
$1.8 million and $2.6 million for Oyster Creek and TMI-1, respectively.
Under its insurance policies applicable to nuclear operations and
facilities, the Company is subject to retrospective premium assessments of up
to $31 million in any one year, in addition to those payable under the
Price-Anderson Act.
Nonutility and Other Power Purchases
The Company has entered into power purchase agreements with independently
owned power production facilities (nonutility generators) for the purchase of
energy and capacity for periods up to 25 years. The majority of these
agreements are subject to penalties for nonperformance and other contract
limitations. While a few of these facilities are dispatchable, most are must-
run and generally obligate the Company to purchase all of the power produced
up to the contract limits. The agreements have been approved by the NJBRC and
permit the Company to recover energy and demand costs from customers through
its energy clause. These agreements provide for the sale of approximately
1,194 MW of capacity and energy to the Company by the mid-to-late 1990s. As
of December 31, 1993, facilities covered by these agreements having 661 MW of
capacity were in service, and 215 MW were scheduled to commence operation in
1994. Payments made pursuant to these agreements were $292 million for 1993
and are estimated to aggregate $325 million for 1994. The price of the energy
and capacity to be purchased under these agreements is determined by the terms
of the contracts. The rates payable under a number of these agreements are
substantially in excess of current market prices. While the Company has been
granted full recovery of these costs from customers by the NJBRC, there can be
no assurance that the Company will continue to be able to recover these costs
throughout the term of the related contracts. The emerging competitive market
has created additional uncertainty regarding the forecasting of the GPU
System's energy supply needs which, in turn, has caused the Company and its
affiliates to change their supply strategy to seek shorter term agreements
offering more flexibility. At the same time, the Company is attempting to
renegotiate, and in some cases buy out, high cost long-term nonutility
generation contracts where opportunities arise. The extent to which the
Company may be able to do so, however, or recover associated costs through
rates, is uncertain. Moreover, these efforts have led to disputes before the
9
NJBRC, as well as to litigation, and may result in claims against the Company
for substantial damages. There can be no assurance as to the outcome of these
matters.
In July 1993, an NJBRC Advisory Council recommended in a report that all
New Jersey electric utilities be required to submit integrated resource plans
for review and approval by the NJBRC.
The NJBRC has asked all electric utilities in the state to assess the
economics of their purchase power contracts with nonutility generators to
determine whether there are any candidates for potential buy out or other
remedial measures. In response, the Company initially identified a 100 MW
project now under development, which it believes is economically undesirable
based on current cost projections. In November 1993, the NJBRC directed the
Company and the developer to negotiate contract repricing to a level more
consistent with the Company's current avoided cost projections or a contract
buy out. The parties have been unable to reach agreement and on February 10,
1994 the NJBRC decided to conduct a hearing on the matter. The developer has
filed a declaratory judgement action in federal court contesting the NJBRC's
jurisdiction in this matter and is seeking to enjoin the NJBRC proceeding.
The matter is pending before the District Court and the NJBRC.
In November 1993, the NJBRC granted two nonutility generators, having a
total of 200 MW under contract with the Company, a one-year extension in the
in-service dates for projects which were originally scheduled to be
operational in 1997. The Company is awaiting a final written NJBRC order and
may appeal this decision.
Also in November 1993, the Company received approval from the NJBRC to
withdraw its request for proposals for the purchase of 150 MW from nonutility
generators. In its petition requesting withdrawal, the Company cited, among
other reasons, that solicitations for long-term contracts would have limited
its ability to compete in a deregulated environment. As a result of the
NJBRC's decision, in January 1994, the Company issued an all source
solicitation for the short-term supply of energy and/or capacity to determine
and evaluate the availability of competitively priced power supply options.
The Company is seeking proposals from utility and nonutility generation
suppliers for periods of one to eight years in length and capable of
delivering electric power beginning in 1996. Although the intention of the
solicitation is to procure short-term and medium-term supplies of electric
power, the Company is willing to give some consideration to proposals in
excess of eight-year terms.
The Company has entered into an arrangement for a peaking generation
project. The Company plans to install a gas-fired combustion turbine at its
Gilbert Generating station and retire two steam units for an 88 MW net
increase in peaking capacity at an expected cost of $50 million. The Company
expects to complete the project by 1996.
The Company and its affiliates have entered into agreements with other
utilities for the purchase of capacity and energy for various periods through
1999. These agreements provide for up to 2,130 MW in 1994, declining to
1,307 MW in 1995 and 183 MW by 1999. Payments pursuant to these agreements
are estimated to aggregate $244 million in 1994. The price of the energy
10
purchased under these agreements is determined by contracts providing
generally for the recovery by the sellers of their costs.
Rate Proceedings
In December 1993, the Company filed a proposal with the NJBRC seeking
approval to implement a new rate initiative designed to retain and expand the
economic base in New Jersey. Under the proposed contract rate service, large
retail customers could enter into contracts for existing electric service at
prevailing rates, with limitations on their exposure to future rate increases.
With this rate initiative, the Company would have to absorb any differential
in price resulting from changes in costs not provided for in the contracts.
This matter is pending before the NJBRC.
Proposed legislation has been introduced in New Jersey which is intended
to allow the NJBRC, at the request of an electric or gas utility, to adopt a
plan of regulation other than traditional ratemaking methods to encourage
economic development and job creation. This legislation would allow electric
utilities to be more competitive with nonutility generators who are not
subject to NJBRC regulation. Combined with other economic development
initiatives, this legislation, if enacted, would provide more flexibility in
responding to competitive pressures, but may also serve to accelerate the
growth of competitive pressures.
The Company's two operating nuclear units are subject to the NJBRC's
annual nuclear performance standard. Operation of these units at an aggregate
generating capacity factor below 65% or above 75% would trigger a charge or
credit based on replacement energy costs. At current cost levels, the maximum
annual effect on net income of the performance standard charge at a 40%
capacity factor would be approximately $10 million. While a capacity factor
below 40% would generate no specific monetary charge, it would require the
issue to be brought before the NJBRC for review. The annual measurement
period, which begins in March of each year, coincides with that used for the
Levelized Energy Adjustment Clause (LEAC).
The NJBRC has instituted a generic proceeding to address the appropriate
recovery of capacity costs associated with electric utility power purchases
from nonutility generation projects. The proceeding was initiated, in part,
to respond to contentions of the New Jersey Public Advocate, Division of Rate
Counsel (Rate Counsel), that by permitting utilities to recover such costs
through the LEAC, an excess or "double recovery" may result when combined with
the recovery of the utilities' embedded capacity costs through their base
rates. In September 1993, the Company and the other New Jersey electric
utilities filed motions for summary judgment with the NJBRC requesting that
the NJBRC dismiss contentions being made by Rate Counsel that adjustments for
alleged "double recovery" in prior periods are warranted. Rate Counsel has
filed a brief in opposition to the utilities' summary judgment motions
including a statement from its consultant that in his view, the "double
recovery" for the Company for the 1988-92 period would be approximately
$102 million. Management believes that the position of Rate Counsel is
without merit. This matter is pending before the NJBRC.
11
Construction Program
General
During 1993, the Company had gross plant additions of approximately
$203 million attributable principally to improvements and modifications to
existing generating stations and additions to the transmission and
distribution system. During 1994, the Company contemplates gross plant
additions of approximately $275 million. The Company's gross plant additions
are expected to total approximately $253 million in 1995. The principal
categories of the 1994 anticipated expenditures, which include an allowance
for other funds used during construction, are as follows:
(In Millions)
1994
Generation - Nuclear $ 74
Nonnuclear 54
Total Generation 128
Transmission & Distribution 135
Other 12
Total $275
In addition, expenditures for maturing debt are expected to be
$60 million and $47 million for 1994 and 1995, respectively. Subject to
market conditions, the Company intends to redeem during these periods
outstanding senior securities pursuant to optional redemption provisions
thereof should it prove economical to do so.
Management estimates that approximately one-half of the Company's total
capital needs for 1994 and approximately three-fourths for 1995 will be
satisfied through internally generated funds. The Company expects to obtain
the remainder of these funds principally through the sale of first mortgage
bonds and preferred stock, subject to market conditions. The Company's bond
indenture and charter include provisions that limit the amount of long-term
debt, preferred stock and short-term debt the Company may issue. The interest
and preferred stock dividend coverage ratios of the Company are currently in
excess of indenture or charter restrictions. (See "Limitations on Issuing
Additional Securities.") Present plans call for the Company to issue long-
term debt and preferred stock during the next three years to finance
construction activities and, depending on the level of interest rates,
refinance outstanding senior securities.
The Company's 1994 construction program includes $19 million in
connection with the federal Clean Air Act Amendments of 1990 (Clean Air Act)
requirements (see "Environmental Matters - Air"). The 1995 construction
program currently includes approximately $16 million for Clean Air Act
compliance.
The Company's gross plant additions exclude nuclear fuel requirements
provided under capital leases that amounted to $13 million in 1993. When
consumed, the currently leased material, which amounted to $86 million at
December 31, 1993, is expected to be replaced by additional leased material at
12
an average rate of approximately $36 million annually. In the event the
replacement nuclear fuel cannot be leased, the associated capital requirements
would have to be met by other means.
In response to the increasingly competitive business climate and excess
capacity of nearby utilities, the GPU System's supply plan places an emphasis
on maintaining flexibility. Supply planning focuses increasingly on short- to
intermediate-term commitments, reliance on "spot" markets, and avoidance of
long-term firm commitments. The Company is expected to experience an average
growth rate in sales to customers (exclusive of the loss of its wholesale
customers) through 1998 of about 1.6% annually. The Company also expects to
experience peak load growth although at a somewhat lesser rate. Through 1998,
the Company's plan consists of the continued utilization of most existing
generating facilities, retirement of certain older units, present commitments
for power purchases and new power purchases (of short or intermediate term
duration), construction of a new facility, and the utilization of capacity of
its affiliates. The plan also includes the continued promotion of economical
energy conservation and load management programs. Given the future direction
of the industry, the Company's present strategy includes minimizing the
financial exposure associated with new long-term purchase commitments and the
construction of new facilities by including projected market prices in the
evaluation of these options. The Company will resist efforts to compel it to
add or contract for new capacity at costs that may exceed future market
prices. In addition, the Company will seek regulatory support to renegotiate
or buy out contracts with nonutility generators where the pricing is in excess
of projected market prices.
Demand-Side Management
The regulatory environment in New Jersey encourages the development of
new conservation and load management programs. This is evidenced by demand-
side management (DSM) incentive regulations adopted in New Jersey in 1992.
DSM includes utility sponsored activities designed to improve energy
efficiency in customer end-use, and includes load management programs (i.e.,
peak reduction) and conservation programs (i.e., energy and peak reduction).
The NJBRC approved the Company's DSM plan in 1992 reflecting DSM
initiatives of 67 MW of summer peak reduction by the end of 1994. Under the
approved regulation, qualified Performance Program DSM investments are
recovered over a six-year period with a return earned on the unrecovered
amounts. Lost revenues will be recovered on an annual basis and the Company
can also earn a performance-based incentive for successfully implementing cost
effective programs. In addition, the Company will continue to make certain
NJBRC mandated Core Program DSM investments which are recovered annually.
Financing Arrangements
The Company expects to have short-term debt outstanding from time to time
throughout the year. The peak in short-term debt is expected to occur in the
spring, coinciding with normal cash requirements for New Jersey Unit Tax
payments.
GPU and the Company and its affiliates have $398 million of credit
facilities, which includes a Revolving Credit Agreement (Credit Agreement)
with a consortium of banks that permits total borrowing of $150 million
13
outstanding at any one time. The credit facilities generally provide for the
payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually.
Borrowings under these credit facilities generally bear interest based on the
prime rate or money market rates. Notes issued under the Credit Agreement,
which expires April 1, 1995, are subject to various covenants and acceleration
under certain conditions.
In 1993, the Company refinanced higher cost long-term debt in the
principal amount of $394 million resulting in an estimated annualized after-
tax savings of $4 million. Total long-term debt issued during 1993 amounted
to $555 million. In addition, the Company redeemed $50 million of high-
dividend rate preferred stock issues.
The Company has regulatory authority to issue and sell first mortgage
bonds, which may be issued as secured medium-term notes, and preferred stock
through June, 1995. Under existing authorization, the Company may issue
senior securities in the amount of $275 million, of which $100 million may
consist of preferred stock. The Company also has regulatory authority to
incur short-term debt, a portion of which may be through the issuance of
commercial paper.
Under the Company's nuclear fuel lease agreements with nonaffiliated fuel
trusts, an aggregate of up to $250 million ($125 million each for Oyster Creek
and TMI-I) of nuclear fuel costs may be outstanding at any one time. It is
contemplated that when consumed, portions of the currently leased material
will be replaced by additional leased material. The Company and its
affiliates are responsible for the disposal costs of nuclear fuel leased under
these agreements.
Limitations on Issuing Additional Securities
The Company's first mortgage bond indenture and/or charter include
provisions that limit the total amount of securities evidencing secured
indebtedness and/or unsecured indebtedness that the Company can issue, the
more restrictive of which are described below.
The Company's first mortgage bond indenture requires that, for any period
of 12 consecutive months out of the 15 calendar months preceeding the issuance
of additional bonds, net earnings available for interest shall have been at
least twice the interest requirements on bonds to be outstanding immediately
after such issuance. Net earnings available for interest generally consist of
the excess of gross operating revenues over operating expenses (other than
income taxes), plus or minus net nonoperating income or loss with nonoperating
income limited to 5% of operating income. Moreover, the Company's first
mortgage bond indenture restricts the ratio of the principal amount of first
mortgage bonds that can be issued to not more than 60% of bondable value of
property additions. In addition, the indenture, in general, permits the
Company to issue additional first mortgage bonds against a like principal
amount of previously retired bonds.
At December 31, 1993, the net earnings requirement under the Company's
mortgage indenture, as described above, would have permitted it to issue
14
approximately $821 million of first mortgage bonds at an assumed interest rate
of 8%. However, the Company had bondable value of property additions and
previously retired bonds that would have permitted it to issue an aggregate of
only approximately $334 million of additional first mortgage bonds.
Among other restrictions, the Company's charter provides that, without
the consent of the holders of two-thirds of the total voting power of the
outstanding preferred stock, no additional shares of preferred stock may be
issued unless, for any period of 12 consecutive months of the 15 calendar
months preceding such issuance, the Company's net after tax earnings available
for the payment of interest on indebtedness shall have been at least one and
one-half times the aggregate of (a) the annual interest charges on
indebtedness and (b) the annual dividend requirements on all shares of
preferred stock to be outstanding immediately after such issuance. At
December 31, 1993, these earnings restrictions would have permitted the
Company to issue approximately $659 million stated value of cumulative
preferred stock at an assumed dividend rate of 8%.
The Company's ability to effect bank loans and issue commercial paper is
limited by the provisions of its charter concerning the ratio of loans to
total capitalization. The Company's charter provides that, without the
consent of the holders of a majority of the total voting power of the
Company's outstanding preferred stock, unsecured indebtedness having an
initial maturity of less than 10 years (or within three years of maturity)
cannot exceed 10% of the sum of secured indebtedness, capital stock, including
premium thereon, and surplus. At December 31, 1993, these restrictions would
have permitted the Company to have approximately $277 million of unsecured
indebtedness outstanding.
The Company has obtained authorization from the SEC to incur short-term
debt (including indebtedness under the Credit Agreement, bank credit
facilities and commercial paper) up to the Company's charter limitation.
Regulation
As a registered holding company, GPU is subject to regulation by the SEC
under the 1935 Act. The Company, as a subsidiary of GPU, is also subject to
regulation under the 1935 Act with respect to accounting, the issuance of
securities, the acquisition and sale of utility assets, securities or any
other interest in any business, the entering into, and performance of,
service, sales and construction contracts, and certain other matters. The SEC
has determined that the electric facilities of the Company and its affiliates
constitute a single integrated public utility system under the standards of
the 1935 Act. The 1935 Act also limits the extent to which the Company may
engage in nonutility businesses. The Company's retail rates, conditions of
service, issuance of securities and other matters are subject to regulation by
the NJBRC. Moreover, with respect to the transmission of electric energy,
accounting, the construction and maintenance of hydroelectric projects and
certain other matters, the Company is subject to regulation by the FERC under
the Federal Power Act. The NRC regulates the construction, ownership and
operation of nuclear generating stations and other related matters. The
Company is also subject, in certain respects, to regulation by the PaPUC in
connection with its participation in the ownership and operation of certain
15
facilities located in Pennsylvania. (See "Electric Generation and the
Environment - Environmental Matters" for additional regulation to which the
Company is or may be subject.)
The rates charged by the Company for electric service are set by
regulators under statutory requirements that they be "just and reasonable."
As such, they are subject to adjustment, up or down, in the event they vary
from that statutory standard. In 1989, the NJBRC issued proposed regulations
designed to establish a mechanism to evaluate the earnings of New Jersey
utilities to determine whether their rates continue to be just and reasonable.
As proposed, the regulations would permit the NJBRC to establish interim rates
subject to refund without prior hearing. There has been no activity
concerning this matter since the Company filed comments with the NJBRC.
Electric Generation and the Environment
Fuel
Of the portion of its energy requirements supplied by its own generation,
the Company utilized fuels in the generation of electric energy during 1993 in
approximately the following percentages: Nuclear--72%; Coal--23%; Gas--4%;
and Other (primarily Oil)--1%. Approximately 58% of the Company's energy
requirements in 1993 was supplied by purchases (including net interchange)
from other utilities and nonutility generators. For 1994, the Company
estimates that its generation of electric energy will be in the following
proportions: Nuclear--64%; Coal--26%; Gas--9%; and Other (primarily Oil)--1%.
The anticipated changes in 1994 fuel utilization percentages are principally
attributable to the refueling outage scheduled during 1994 for the Oyster
Creek nuclear generating station. Approximately 65% of the Company's 1994
energy requirements is expected to be supplied by purchases (including net
interchange) from other utilities and nonutility generators.
Fossil: The Company has entered into a long-term contract with a
nonaffiliated mining company for the purchase of coal for the Keystone
generating station of which the Company owns a one-sixth undivided interest.
This contract, which expires in 2004, requires the purchase of minimum amounts
of the station's coal requirements. The price of the coal is determined by a
formula generally providing for the recovery by the mining company of its
costs of production. The Company's share of the cost of coal purchased under
this agreement is expected to aggregate $21 million for 1994.
The Company's portion of the station's estimated coal requirements
aggregates approximately 15 million tons over the next 20 years, of which five
million tons are expected to be supplied by the nonaffiliated mine-mouth coal
company under the long-term contract, with the balance supplied by spot
purchases or short-term contracts.
At the current time, adequate supplies of fossil fuels are readily
available to the Company, but this situation could change rapidly as a result
of actions over which it has no control.
Nuclear: Preparation of nuclear fuel for generating station use involves
various manufacturing stages for which the Company and its affiliates contract
16
separately. Stage I involves the mining and milling of uranium ores to
produce natural uranium concentrates. Stage II provides for the chemical
conversion of the natural uranium concentrates into uranium hexafluoride.
Stage III involves the process of enrichment to produce enriched uranium
hexafluoride from the natural uranium hexafluoride. Stage IV provides for the
fabrication of the enriched uranium hexafluoride into nuclear fuel assemblies
for use in the reactor core at the nuclear generating station.
For TMI-1, under normal operating conditions, there is, with minor
planned modifications, sufficient on-site storage capacity to accommodate
spent nuclear fuel through the end of its licensed life while maintaining the
ability to remove the entire reactor core. While Oyster Creek currently has
sufficient on-site storage capacity to accommodate, under normal operating
conditions, its spent nuclear fuel while maintaining the ability to remove the
entire reactor core, additional on-site storage capacity will be required at
the Oyster Creek station beginning in 1996 in order to continue operation of
the plant. Contract commitments, with an outside vendor, have been made for
on-site incremental spent fuel dry storage capacity at Oyster Creek for 1996
and 1998. Currently, public hearings on plans to build an interim spent fuel
facility at the plant are underway.
Environmental Matters
The Company is subject to federal and state water quality, air quality,
solid waste disposal and employee health and safety legislation and to
environmental regulations issued by the U.S. Environmental Protection Agency
(EPA), state environmental agencies and other federal agencies. In addition,
the Company is subject to licensing of hydroelectric projects by the FERC and
of nuclear power projects by the NRC. Such licensing and other actions by
federal agencies with respect to projects of the Company are also subject to
the National Environmental Policy Act.
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including, but
not limited to, acid rain, water quality, air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, the Company may be required to incur substantial additional costs to
construct new equipment, modify or replace existing and proposed equipment,
remediate or clean up waste disposal and other sites currently or formerly
used by it, including formerly owned manufactured gas plants, and with regard
to electromagnetic fields, postpone or cancel the installation of, or replace
or modify, utility plant, the costs of which could be material. The
consequences of environmental issues, which could cause the postponement or
cancellation of either the installation or replacement of utility plant are
unknown. Management believes the costs described above should be recoverable
through the ratemaking process, but recognizes that recovery cannot be
assured.
Water: The federal Water Pollution Control Act (Clean Water Act)
generally requires, with respect to existing steam electric power plants, the
application of the best conventional or practicable pollutant control
technology available and compliance with state-established water quality
standards. With respect to future plants, the Clean Water Act requires the
17
application of the "best available demonstrated control technology, processes,
operating methods or other alternatives" to achieve, where practicable, no
discharge of pollutants. Congress may amend the Clean Water Act during 1994.
The EPA has adopted regulations that establish thermal and other
limitations for effluents discharged from both existing and new steam electric
generating stations. Standards of performance are developed and enforcement
of effluent limitations is accomplished through the issuance by the EPA, or
states authorized by the EPA, of discharge permits that specify limitations to
be applied. Discharge permits, which have been issued for all of the
Company's generating stations, where required, have expired. Timely
reapplications for such permits have been filed as required by regulations.
Until new permits are issued, the currently expired permits remain in effect.
The discharge permit received by the Company for the Oyster Creek station
may, among other things, require the installation of a closed-cycle cooling
system, such as a cooling tower, to meet New Jersey state water quality-based
thermal effluent limitations. Although construction of such a system is not
required in order to meet the EPA's regulations setting effluent limitations
for the Oyster Creek station (such regulations would accept the use of the
once-through cooling system now in operation at this station), a closed-cycle
cooling system may be required in order to comply with the water quality
standards imposed by the New Jersey Department of Environmental Protection and
Energy (NJDEPE) for water quality certification and incorporated in the
station's discharge permit. If a cooling tower is required, the capital costs
could exceed $150 million. In 1988, the NJDEPE prepared a draft evaluation
that assessed the impact of cooling water intake and discharge from Oyster
Creek. This evaluation concluded that the thermal impact of water discharge
from Oyster Creek operation was small and localized, but that the impact of
cooling water intake was inconclusive, requiring further study. In 1993, the
NJDEPE advised GPUN that rather than conduct hearings, it will determine water
quality standards in the context of renewing the discharge permit. The NJDEPE
has indicated that water quality standards (on an interim basis) will be set
as requested by GPUN and that physical or operational changes to the intake
structure will not be necessary at this time. Final standards will be
established based upon results of a study to determine the optimum operational
schedule for the dilution pumps.
The NJDEPE has proposed thermal and other conditions for inclusion in the
discharge permits for the Company's Gilbert and Sayreville generating stations
that, among other things, could require the Company to install cooling towers
and/or modify the water intake/discharge systems at these facilities. The
Company has objected to these conditions and has requested an adjudicatory
hearing with respect thereto. Implementation of these permit conditions has
been stayed pending action on the Company's hearing request. The Company has
made filings with the NJDEPE that the Company believes demonstrate compliance
with state water quality standards at the Gilbert generating station and
justify the issuance of a thermal variance at the Sayreville generating
station to permit the continued use of the current once-through cooling
system. Based on the NJDEPE's review of these demonstrations, substantial
18
modifications may be required at these stations, which may result in material
capital expenditures.
The Company is also subject to environmental and water diversion
requirements adopted by the Delaware River Basin Commission and the
Susquehanna River Basin Commission as administered by those commissions or the
Pennsylvania Department of Environmental Resources (PaDER) and the NJDEPE.
Nuclear: Reference is made to "Nuclear Facilities" for information
regarding the TMI-2 accident, its aftermath and the Company's other nuclear
facilities.
New Jersey and Pennsylvania have each established, in conjunction with
other states, a low level radioactive waste (radwaste) compact for the
construction, licensing and operation of low level radwaste disposal
facilities to service their respective areas by the year 2000.
New Jersey and Connecticut have established the Northeast Compact. The
estimated cost to license and build a low level radwaste disposal facility in
New Jersey is approximately $74 million. The Company's expected $29.5 million
share of the cost for this facility is to be paid annually over an eight year
period ending 1999. In its February 1993 rate order, the NJBRC granted the
Company's request to recover these amounts currently from customers. The
facility would be available for disposal of low level waste from Oyster Creek.
Similarly, Pennsylvania, Delaware, Maryland and West Virginia have
established the Appalachian Compact, which will build a single facility to
dispose of low level radwaste in their areas, including low level radwaste
from TMI-1. The estimated cost to license and build this facility is
approximately $60 million, of which the Company and its affiliates' share is
$12 million. These payments are considered advance waste disposal fees and
will be recovered during the facility's operation.
The Company has provided for future contributions to the Decontamination
and Decommissioning Fund (part of the Energy Act) for the cleanup of
enrichment plants operated by the federal government. The Company's share of
the total liability at December 31, 1993 amounted to $29 million. The Company
made its initial payment in 1993. The remaining amount recoverable from
ratepayers is $28 million at December 31, 1993.
Air: The Company is subject to certain state environmental regulations
of the NJDEPE, the New Jersey Department of Health and the PaDER. The Company
is also subject to certain federal environmental regulations of the EPA.
The PaDER, NJDEPE and the EPA have adopted air quality regulations
designed to implement Pennsylvania, New Jersey and federal statutes relating
to air quality.
Current Pennsylvania environmental regulations prescribe criteria that
generally limit the sulfur dioxide content of stack gas emissions from
generating stations constructed before 1972 and stations constructed after
1971 but before 1978, to 3.7 pounds and 1.2 pounds per million BTUs of heat
input, respectively. On a weighted average basis, the Company and its
19
affiliates have been able to obtain coal having a sulfur content meeting these
criteria. If, and to the extent that, the Company and its affiliates cannot
continue to meet such limitations with processed coal, it may be necessary to
retrofit operating stations with sulfur removal equipment that may require
substantial capital expenditures as well as substantial additional operating
costs. Such retrofitting, if it could be accomplished to permit continued
reliable operation of the facilities concerned, would take approximately five
years.
As a result of the Clean Air Act, which requires substantial reductions
in sulfur dioxide and nitrogen oxide (NOx) emissions by the year 2000, it may
be necessary for the Company to install and operate emission control equipment
at the Keystone station, in which it has a 16.67% ownership interest. To
comply with Title IV of the Clean Air Act, the Company expects to expend up to
$145 million by the year 2000 for the installation of scrubbers, low NOx
burner technology and various precipitator upgrades, of which approximately
$2 million had been spent as of December 31, 1993. The capital costs of this
equipment and the increased operating costs are expected to be recoverable
through the ratemaking process.
The current strategy for Phase II compliance under the Clean Air Act is
to install scrubbers at the Keystone station.
The Company continues to review available options to comply with the
Clean Air Act, including those that may result from the development of an
emission allowance trading market. The Company's compliance strategy,
especially with respect to Phase II, could change as a result of further
review, discussions with co-owners of jointly owned stations and changes in
federal and state regulatory requirements.
The ultimate impact of Title I of the Clean Air Act, which deals with the
attainment of ambient air quality standards, is highly uncertain. In
particular, this Title has established an ozone transport or emission control
region that includes 11 northeast states. Pennsylvania and New Jersey are
part of this transport region, and will be required to control NOx emissions
to a level that will provide for the attainment of the ozone standard in the
northeast. As an initial step, major sources of NOx will be required to
implement Reasonably Available Control Technology (RACT) by May 31, 1995.
This will affect the Company and its affiliates' steam generating stations.
PaDER's RACT regulations have been approved by the Environmental Quality Board
and became effective in January 1994. Large coal-fired combustion units are
required to comply with a presumptive RACT emission limitation (technology) or
may elect to use a case-by-case analysis to establish RACT requirements.
NJDEPE's RACT regulations became effective in December 1993. These
regulations establish maximum allowable emission rates for utility boilers
based on fuel used and boiler type, and on combustion turbines based on fuel
used. Existing units are eligible for emissions averaging upon approval of an
averaging plan by the NJDEPE.
The ultimate impact of Title III of the Clean Air Act, which deals with
emissions of hazardous air pollutants, is also highly uncertain.
Specifically, the EPA has not completed a Clean Air Act study to determine
20
whether it is appropriate to regulate emissions of hazardous air pollutants
from electric utility steam generating units.
Both the EPA and PaDER are questioning the attainment of National Ambient
Air Quality Standards (NAAQS) for sulfur dioxide in the vicinity of the
Chestnut Ridge Energy Complex, which includes the Keystone generating station.
The EPA and the PaDER have approved the use of a nonguideline air quality
model. This model is more representative and less conservative than the EPA
guideline model and will be used in the development of a compliance strategy
for all generating stations in the Chestnut Ridge Energy Complex. Significant
sulfur dioxide reductions may be required at the Keystone generating station,
which could result in material capital and additional operating expenditures.
Certain other environmental regulations limit the amount of particulate
matter emitted into the environment. The Company and its affiliates have
installed equipment at their coal-fired generating stations and may find it
necessary to either upgrade or install additional equipment at certain of
their stations to consistently meet particulate emission requirements.
In the fall of 1993, the Clinton Administration announced its climate
change action plan that intends to reduce greenhouse gas emissions to 1990
levels by the year 2000. The climate action plan relies heavily on voluntary
action by industry. The Company and its affiliates have notified the DOE that
they support the voluntary approach proposed by the President and expressed
their intent to work with the DOE.
Title IV of the Clean Air Act requires Phase I and Phase II affected
units to install a continuous emission monitoring system and quality assure
the data for sulfur dioxide, NOx, opacity and volumetric flow. In addition,
Title VIII requires all affected sources to monitor carbon dioxide emissions.
The Clean Air Act has also expanded the enforcement options available to
the EPA and the states and contains more stringent enforcement provisions and
penalties. Moreover, citizen suits can seek civil penalties for violations of
this Act.
In 1988, the Environmental Defense Fund (EDF), the New Jersey
Conservation Foundation, the Sierra Club and Pennsylvanians for Acid Rain
Control requested that the NJDEPE and the NJBRC seek to reduce sulfur
deposition in New Jersey, either by reducing emissions from both in-state and
out-of-state sources, or by requiring that certain electricity imported into
New Jersey be generated from facilities meeting minimum emission standards.
The Company purchases a substantial portion of its net system requirements
from out-of-state coal-fired facilities, including the 1,700 MW Keystone
station in Pennsylvania. Hearings on the EDF petition were held during 1989
and 1990, and the matter is pending before the NJDEPE and the NJBRC.
NJDEPE regulations establish the maximum sulfur content of oil, which may
not exceed .3% for most of the Company's generating stations and 1% for the
balance.
In 1993, the Company made capital expenditures of approximately
$2 million in response to environmental considerations and has included
21
approximately $11 million for this purpose in its 1994 construction program.
The operating and maintenance costs, including the incremental costs of
low-sulfur fuel, for such equipment were approximately $42 million in 1993 and
are expected to be approximately $44 million in 1994.
Electromagnetic Fields: There have been a number of scientific studies
regarding the possibility of adverse health effects from electric and magnetic
fields (EMF) that are found everywhere there is electricity. While some of
the studies have indicated some association between exposure to EMF and
cancer, other studies have indicated no such association. The studies have
not shown any causal relationship between exposure to EMF and cancer, or any
other adverse health effects. In 1990, the EPA issued a draft report that
identifies EMF as a possible carcinogen, although it acknowledges that there
is still scientific uncertainty surrounding these fields and their possible
link to adverse health effects. On the other hand, a 1992 White House Office
of Science and Technology policy report states that "there is no convincing
evidence in the published literature to support the contention that exposures
to extremely low frequency electric and magnetic fields generated by sources
such as household appliances, video display terminals, and local power lines
are demonstrable health hazards." Additional studies, which may foster a
better understanding of the subject, are currently under way.
Certain parties have alleged that exposure to EMF associated with the
operation of the Company's transmission and distribution facilities will
produce adverse impacts upon public health and safety, and upon property
values. Furthermore, regulatory actions under consideration by the NJDEPE and
bills introduced in the Pennsylvania legislature could, if enacted, establish
a framework under which the intensity of EMF produced by electric transmission
and distribution lines would be limited or otherwise regulated.
The Company cannot determine at this time what effect, if any, this
matter will have on it.
Hazardous/Toxic Wastes: Under the Toxic Substances Control Act (TSCA),
the EPA has adopted certain regulations governing the use, storage, testing,
inspection and disposal of electrical equipment that contains polychlorinated
biphenyls (PCBs). Such regulations permit the continued use and servicing of
certain electrical equipment (including transformers and capacitors) that
contain PCBs. The Company has met all requirements of the TSCA necessary to
allow the continued use of equipment containing PCBs, and has taken
substantive voluntary actions to reduce the amount of PCB containing
electrical equipment.
Prior to 1953, the Company owned and operated manufactured gas plants in
New Jersey. Wastes associated with the operation and dismantlement of these
gas manufacturing plants were disposed of both on-site and off-site. Claims
may be asserted against the Company for the cost of investigation and
remediation of these waste disposal sites. The amount of such remediation
costs and penalties may be significant and may not be covered by insurance.
The Company has identified 17 such sites to date. The Company has entered
into cost-sharing agreements with New Jersey Natural Gas Company and
Elizabethtown Gas Company under which the Company is responsible for 60% of
all costs incurred in connection with the remediation of 12 of these sites.
22
The Company has entered into Administrative Consent Orders (ACOs) with the
NJDEPE for seven of these sites and has entered into Memorandum of Agreements
(MOAs) with the NJDEPE for eight of these sites. The Company anticipates
entering into MOAs for the remaining sites. The ACOs specify the agreed upon
obligations of both the Company and the NJDEPE for remediation of the sites.
The MOAs afford the Company greater flexibility in the schedule for
investigation and remediation of sites. The Company is seeking NJDEPE
approval of its plans for the remediation of these sites. The NJDEPE has
approved the Company's implementation program for five of these sites.
At December 31, 1993, the Company has an estimated environmental
liability of $35 million recorded on its balance sheet relating to these
sites. The estimated liability is based upon ongoing site investigations and
remediation efforts, including capping the sites and pumping and treatment of
ground water. If the periods over which the remediation is currently expected
to be performed are lengthened, the Company believes that it is reasonably
possible that the ultimate costs may range as high as $60 million. Estimates
of these costs are subject to significant uncertainties: the Company does not
presently own or control most of these sites; the environmental standards have
changed in the past and are subject to future change; the accepted
technologies are subject to further development; and the related costs for
these technologies are uncertain. If the Company is required to utilize
different remediation methods, the costs could be materially in excess of $60
million.
In June 1993, the NJBRC approved a mechanism for the recovery of future
manufactured gas plant remediation costs through the Company's LEAC when
expenditures exceed prior collections. The NJBRC decision provides for
interest to be credited to customers until the overrecovery is eliminated and
for future costs to be amortized over seven years with interest. At December
31, 1993, the Company has collected from customers $5.2 million in excess of
expenditures of $12.8 million. The Company is currently awaiting a final
NJBRC order. The Company is pursuing reimbursement of the above costs from
its insurance carriers, and will seek to recover costs to the extent not
covered by insurance through this mechanism.
The federal Resource Conservation and Recovery Act of 1976, the
Comprehensive Environmental Response, Compensation and Liability Act of 1980
(CERCLA) and the Superfund Amendment and Reauthorization Act of 1986 authorize
the EPA to issue an order compelling responsible parties to take cleanup
action at any location that is determined to present an imminent and
substantial danger to the public or to the environment because of an actual or
threatened release of one or more hazardous substances. New Jersey has
enacted legislation giving similar authority to the NJDEPE. Because of the
nature of the Company's business, various by-products and substances are
produced and/or handled that are classified as hazardous under one or more of
these statutes. The Company generally provides for the treatment, disposal or
recycling of such substances through licensed independent contractors, but
these statutory provisions also impose potential responsibility for certain
cleanup costs on the generators of the wastes. The Company has been notified
by the EPA and a state environmental authority that it is among the
potentially responsible parties (PRPs) who may be jointly and severally liable
to pay for the costs associated with the investigation and remediation at six
23
hazardous and/or toxic waste sites (including the one described below). In
addition, the Company has been requested to supply information to the EPA and
state environmental authorities on several other sites for which it has not as
yet been named as a PRP.
The Company received notification in 1986 from the EPA that it is among
the more than 800 PRPs under CERCLA who may be liable to pay for the cost
associated with the investigation and remediation of the Maxey Flats disposal
site, located in Fleming County, Kentucky. The Company is alleged to have
contributed approximately 1.55% of the total volume of waste shipped to the
Maxey Flats site. On September 30, 1991, the EPA issued a Record of Decision
(ROD) advising that a remedial alternative had been selected. The PRPs
estimate the cost of the remedial alternative selected and associated
activities identified in the ROD at more than $60 million, for which all
responsible parties would be jointly and severally liable. The Company has
provided for its proportionate share of this cost in its financial statements.
The ultimate cost of remediation of these sites will depend upon changing
circumstances as site investigations continue, including (a) the technology
required for site cleanup, (b) the remedial action plan chosen and (c) the
extent of site contamination and the portion attributed to the Company.
The Company is unable to estimate the extent of possible remediation and
associated costs of additional environmental matters. Management believes the
costs described above should be recoverable through the ratemaking process.
Franchises
The Company operates pursuant to franchises in the territory served by it
and has the right to occupy and use the public streets and ways of the State
with its poles, wires and equipment upon obtaining the consent in writing of
the owners of the soil, and also to occupy the public streets and ways
underground with its conduits, cables and equipment, where necessary, for its
electric operation. The Company has the requisite legal franchise for the
operation of its electric business within the State of New Jersey, including
in incorporated cities and towns where designations of new streets, public
ways, etc., may be obtained upon application to such municipalities. The
Company holds a FERC license expiring in 2013 authorizing it to operate and
maintain the Yards Creek pumped storage hydroelectric station in which the
Company has a 50% ownership interest.
Employee Relations
At February 28, 1994, the Company had 3,439 full-time employees. The
nonsupervisory production and maintenance employees of the Company and certain
of the Company's nonsupervisory clerical employees are represented for
collective bargaining purposes by local unions of the International
Brotherhood of Electrical Workers (IBEW). The Company's three-year contract
with the IBEW expires on October 31, 1994.
24
ITEM 2. PROPERTIES.
Generating Stations
At December 31, 1993, the generating stations of the Company had an
aggregate effective summer capability of 2,849,000 net kilowatts (kW), as
follows:
Year of
Name and Location of Station Installation Net kW
Nuclear:
Oyster Creek, Lacey Twp., NJ 1969 610,000
Three Mile Island
Unit No. 1
Dauphin County, PA (a) 1974 196,000
Gas or Oil:
Gilbert, Holland Twp., NJ 1930-1949 117,000
Sayreville, Sayreville, NJ (b) 1930-1958 313,000
Other (18 combustion turbines
and 1 combined cycle), various
locations 1970-1989 868,000
Oil:
E. H. Werner, South Amboy, NJ 1953 58,000
Other (4 combustion turbines
and 4 diesel units), various
locations 1968-1972 214,000
Coal:
Keystone, Indiana, PA (c) 1967-1968 283,000
Pumped Storage:
Yards Creek, Blairstown, NJ (d) 1965 190,000
Total 2,849,000
(a) Represents the Company's undivided 25% interest in the station.
(b) Effective February 1, 1994, 84,000 kW of capability were retired.
(c) Represents the Company's undivided 16.67% interest in the station.
(d) Represents the Company's undivided 50% interest in the station, which is
a net user rather than a net producer of electric energy.
Substantially all of the Company's properties are subject to the lien of
its first mortgage bond indenture.
The Company's peak load was 4,564,000 kW, reached on July 9, 1993.
25
Transmission and Distribution System
At December 31, 1993, the Company owned 299 transmission and distribution
substations that had an aggregate installed transformer capacity of 21,810,169
kilovoltamperes (kVA), and 2,572 circuit miles of transmission lines, of which
18 miles were operated at 500 kilovolts (kV), 570 miles at 230 kV, 228 miles
at 115 kV and the balance of 1,756 miles at 69 kV and 34.5 kV. The Company's
distribution system included 9,707,504 kVA of line transformer capacity,
15,459 pole miles of overhead lines and 6,362 trench miles of underground
cables.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to "Nuclear Facilities - TMI-2," "Rate Proceedings,"
and "Environmental Matters" under Item 1 and Note 1 to Financial Statements
contained in Item 8 for a description of certain pending legal proceedings
involving the Company. See Page F-1 for reference to Notes to Financial
Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
26
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
All of the Company's outstanding common stock is owned by GPU. During
1993, the Company paid $60 million in dividends on its common stock.
In accordance with the Company's mortgage indenture, as supplemented,
$1.7 million of the balance of retained earnings at December 31, 1993 is
restricted as to the payment of dividends on its common stock.
ITEM 6. SELECTED FINANCIAL DATA.
See page F-1 for reference to Selected Financial Data required by this
item.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
See page F-1 for reference to Management's Discussion and Analysis of
Financial Condition and Results of Operations required by this item.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See page F-1 for reference to Financial Statements and Quarterly
Financial Data (unaudited) required by this item.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
27
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Identification of Directors
The current directors of the Company, their ages, positions held and
business experience during the past five years are as follows:
Year First
Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief Executive Officer 1986
D. Baldassari (b) 44 President 1982
R. C. Arnold (c) 56 Director 1989
J. G. Graham (d) 55 Vice President and Chief Financial
Officer 1986
M. P. Morrell (e) 45 Vice President 1993
G. E. Persson (f) 62 Director 1983
P. H. Preis (g) 60 Vice President and Comptroller 1982
S. C. Van Ness (h) 60 Director 1983
S. B. Wiley (i) 64 Director 1982
(a) Mr. Leva became Chairman of the Board and Chief Executive Officer of the
Company in 1992. He became Chairman, President and Chief Executive
Officer of GPU in 1992. He is also Chairman, President, Chief Executive
Officer and a director of GPUSC, Chairman of the Board, Chief Executive
Officer and a director of Met-Ed, Penelec and GPC, and Chairman of the
Board and a director of GPUN. Prior to assuming his current positions,
Mr. Leva served as President of the Company since 1986. He is also a
director of Utilities Mutual Insurance Company, the New Jersey Utilities
Association, Chemical Bank NJ and Princeton Bank & Trust Company.
(b) Mr. Baldassari became President of the Company and a director of GPUSC
and GPUN in February 1992. Prior to assuming his current positions, Mr.
Baldassari served as Vice President - Rates and a director of the Company
since 1982. He also served as Vice President - Materials and Services of
the Company since 1990, and as Treasurer of the Company from October 1979
through December 31, 1989. He is also a director of First Morris Bank
and the New Jersey Utilities Association.
(c) Mr. Arnold became Executive Vice President - Power Supply of GPUSC in
1990. He was Senior Vice President - Power Supply of GPUSC from 1987 to
1989. He is also a director of GPUSC, Met-Ed and Penelec.
(d) Mr. Graham became Senior Vice President in 1989 and Chief Financial
Officer of GPU in 1987. He is also Executive Vice President, Chief
Financial Officer and a director of GPUSC; Vice President, Chief
Financial Officer and a director of Met-Ed and Penelec; Vice President
and Chief Financial Officer of GPUN; President and a director of GPC; and
a director of EI.
28
(e) Mr. Morrell was elected Vice President - Materials, Services and
Regulatory Affairs of the Company and a director of the Company in 1993.
Prior to assuming these positions, Mr. Morrell served as Vice President
of GPU since 1989 and Treasurer of GPU since 1987, and had also served as
Vice President and Treasurer of the Company, GPUSC, Met-Ed and Penelec
and as Treasurer of GPUN and GPC. He is also a director of Utilities
Mutual Insurance Company.
(f) Mrs. Persson is owner and President of Business Dynamics Associates of
Farmingdale, NJ. Prior to that, she was owner and operator of a
family-owned business in Little Silver and Farmingdale, NJ since 1965.
Mrs. Persson is a member of the United States Small Business
Administration National Advisory Board, the New Jersey Small Business
Advisory Council, the Board of Advisors of Brookdale Community College
and the Board of Advisors of Georgian Court College.
(g) Mr. Preis became a Vice President and a director of the Company in 1982
and Comptroller in 1979.
(h) Mr. Van Ness has been affiliated with the law firm of Pico, Mack,
Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since July 1990.
Prior to that time, he was affiliated with the law firm of Jamison,
McCardell, Moore, Peskin and Spicer of Princeton, NJ since 1983. He also
served as Commissioner of the Department of the Public Advocate, State of
New Jersey, from 1974 to September 1982. Mr. Van Ness is a director of
The Prudential Insurance Company of America.
(i) Mr. Wiley has been a partner in the law firm of Wiley, Malehorn and
Sirota of Morristown, NJ since 1973. He is also Chairman of First Morris
Bank.
The Company's directors are elected at the annual meeting of stockholder
to serve until the next meeting of stockholder and until their respective
successors are duly elected and qualified. There are no family relationships
among the directors of the Company.
Identification of Executive Officers
The executive officers of the Company, their ages, positions held and
business experience during the past five years are as follows:
29
Year First
Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief Executive Officer 1992
D. Baldassari (b) 44 President 1992
C. D. Cudney (c) 55 Vice President 1982
C. R. Fruehling (d) 58 Vice President 1982
J. G. Graham (e) 55 Vice President and
Chief Financial Officer 1987
E. J. McCarthy (f) 55 Vice President 1982
M. P. Morrell (g) 45 Vice President 1990
R. W. Muilenburg (h) 60 Vice President 1982
D. W. Myers (i) 49 Vice President and Treasurer 1993
P. H. Preis (j) 60 Vice President and Comptroller 1979
R. J. Toole (k) 51 Vice President 1990
J. J. Westervelt (l) 53 Vice President 1982
R. S. Cohen (m) 51 Secretary and Corporate Counsel 1986
(a) See Note (a) on page 28.
(b) See Note (b) on page 28.
(c) Mr. Cudney has been Vice President of the Company since 1982. Prior to
that time, Mr. Cudney served as Manager - Operations of the Company since
May 1975.
(d) Mr. Fruehling has been Vice President of the Company since 1982. Prior
to that time, Mr. Fruehling served as Director - Transmission &
Distribution Engineering of the Company since October 1979.
(e) See Note (d) on page 28.
(f) Mr. McCarthy has been Vice President of the Company since 1982. Prior to
that time, Mr. McCarthy served as Manager - Business Offices of the
Company since May 1971.
(g) See note (e) on page 29.
(h) Mr. Muilenburg has been Vice President of the Company since 1982. Prior
to that time, Mr. Muilenburg served as Manager - Corporate Communications
of the Company since June 1976.
(i) Mr. Myers became Vice President and Treasurer of the Company in 1993. He
is also Vice President and Treasurer of GPU, GPUSC, Met-Ed, Penelec, GPUN
and GPC. Prior to assuming his current positions, Mr. Myers served as
Vice President and Comptroller of GPUN since 1986.
(j) See Note (g) on page 29.
(k) Mr. Toole has been Vice President of the Company since 1990. He has also
been a Vice President of Met-Ed since 1989. Prior to that he served as
Director - Generation Operations of Met-Ed and GPUSC and as Operations
and Maintenance Director of TMI-1.
30
(l) Mr. Westervelt has been Vice President of the Company since 1982. Prior
to that time, Mr. Westervelt served as Director - Human Resources of the
Company since April 1979.
(m) Mr. Cohen has been Secretary and Corporate Counsel of the Company since
1986.
The Company's executive officers are elected each year at the first
meeting of the Board of Directors held following the annual meeting of
stockholder. Executive officers hold office until the next meeting of
directors following the annual meeting of stockholder and until their
respective successors are duly elected and qualified. There are no family
relationships among the Company's executive officers.
ITEM 11. EXECUTIVE COMPENSATION.
Remuneration of Executive Officers
SUMMARY COMPENSATION TABLE
Long-Term
Annual Compensation Compensation
Other Awards All
Name and Annual Restricted Other
Principal Compen- Stock/Unit Compen-
Position Year Salary Bonus sation(1) Awards(2) sation
J. R. Leva
Chairman and
Chief Executive
Officer (3) (3) (3) (3) (3) (3)
D. Baldassari 1993 $253,750 $57,000 $ - $41,850 $11,192(4)
President 1992 211,480 50,000 - 35,100 8,985
1991 117,600 18,500 - 12,190 9,227
M. P. Morrell 1993(5) 144,200 26,000 1,932 15,500 5,768(6)
Vice Presi- 1992 137,500 24,900 1,166 14,560 5,267
dent 1991 128,750 21,000 547 12,650 5,150
C. D. Cudney 1993 137,675 24,000 - 14,260 7,573(7)
Vice Presi- 1992 132,400 20,900 - 14,300 5,741
dent 1991 125,800 19,000 - 13,340 4,994
P. H. Preis 1993 135,900 22,500 - 14,260 4,881(8)
Vice Presi- 1992 130,725 20,600 - 13,780 4,285
dent and 1991 125,825 19,000 - 12,190 3,794
Comptroller
E. J. McCarthy 1993 125,825 22,500 - 13,020 5,033(6)
Vice Presi- 1992 121,125 19,100 - 13,000 4,845
dent 1991 116,625 18,000 - 11,270 2,744
31
(1) "Other Annual Compensation" is composed entirely of the above-market
interest accrued on the preretirement portion of deferred compensation.
(2) Number and value of aggregate restricted shares/units at the end of 1993
(dividends are paid or accrued on these restricted shares/units and
reinvested):
Aggregate Aggregate
Shares/Units Value
D. Baldassari 3,500 $95,114
M. P. Morrell 1,910 $49,348
C. D. Cudney 1,880 $48,316
P. H. Preis 1,810 $46,646
E. J. McCarthy 1,680 $43,264
(3) As noted above, Mr. Leva is Chairman and Chief Executive Officer of the
Company and its affiliates, as well as Chairman and Chief Executive
Officer of GPU and GPUSC. Mr. Leva is compensated by GPUSC for his
overall services on behalf of the GPU System and, accordingly, is not
compensated directly by the Company for his services. Information with
respect to Mr. Leva's compensation is included on pages 13 to 15 of GPU's
1994 definitive proxy statement, which are incorporated herein by
reference.
(4) Consists of the Company's matching contributions under the Savings Plan
($9,427) and the imputed interest on employer-paid premiums for split-
dollar life insurance ($1,765).
(5) Mr. Morrell was elected Vice President-Materials, Services and Regulatory
Affairs of the Company effective January 15, 1993. Prior to assuming
this position, Mr. Morrell served as Vice President and Treasurer of the
Company.
(6) Consists of the Company's matching contributions under the Savings Plan.
(7) Consists of the Company's matching contributions under the Savings Plan
($4,847) and above-market interest accrued on the retirement portion of
deferred compensation ($2,726).
(8) Consists of the Company's matching contributions under the Savings Plan
($3,805) and above-market interest accrued on the retirement portion of
deferred compensation ($1,076).
32
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Performance Estimated future payouts
Number of or other under nonstock price-
shares, period until based plans(1)
units or maturation
Name other rights or payout Target ($ or #)
D. Baldassari 1,350 5 years $29,177
M. P. Morrell 500 5 years 10,806
C. D. Cudney 460 5 years 9,942
P. H. Preis 460 5 years 9,942
E. J. McCarthy 420 5 years 9,077
(1) The 1990 Stock Plan for Employees of General Public Utilities Corporation
and Subsidiaries also provides for a Performance Cash Incentive Award in
the event that the annualized GPU Total Shareholder Return exceeds the
annualized Industry Total Return (Edison Electric Institute's Investor-
Owned Electric Utility Index) for the period between the award and
vesting dates. These payments are designed to compensate recipients of
restricted stock/unit awards for the amount of federal and state income
taxes that will be payable upon the restricted stock/units that are
vesting for the recipient. The amount is computed by multiplying the
applicable gross-up percentage by the amount of gross income the
recipient recognizes for federal income tax purposes when the
restrictions lapse. The estimated amounts above are computed based on
the number of restricted units awarded for 1993 multiplied by the 1993
year-end market value of $30.875. Actual payments would be based on the
market value of GPU common stock at the time the restrictions lapse, and
may be different from those indicated above.
Proposed Remuneration of Executive Officers
No executive officer of the Company has an employment contract with the
Company. The compensation of the Company's executive officers is determined
from time to time by the Board of Directors of the Company.
Retirement Plans
The GPU System pension plans provide for pension benefits, payable for
life after retirement, based upon years of creditable service with the GPU
System and the employee's career average annual compensation as defined below.
Under federal law, an employee's pension benefits that may be paid from a
qualified trust under a qualified pension plan such as the GPU System plans
are subject to certain maximum amounts. The GPU System companies also have
adopted nonqualified plans providing that the portion of a participant's
pension benefits that, by reason of such limitations or source, cannot be paid
from such a qualified trust shall be paid directly on an unfunded basis by the
participant's employer.
33
The following table illustrates the amount of aggregate annual pension
from funded and unfunded sources resulting from employer contributions to the
qualified trust and direct payments payable upon retirement in 1994 (computed
on a single life annuity basis) to persons in specified salary and years of
service classifications:
Estimated Annual Retirement Benefits(2)(3)(4)
Based Upon Career Average Compensation
(1994 Retirement)
15 Years 20 Years 25 Years 30 Years 35 Years 40 Years
of Service of Service of Service of Service of Service of Service
Career Average
Compensation (1)
$100,000 $ 29,114 $ 38,819 $ 48,524 $ 58,229 $ 67,934 $ 76,956
150,000 44,114 58,819 73,524 88,229 102,934 116,556
200,000 59,114 78,819 98,524 118,229 137,934 156,156
250,000 74,114 98,819 123,524 148,229 172,934 195,756
300,000 89,114 118,819 148,524 178,229 207,934 235,356
350,000 104,114 138,819 173,524 208,229 242,934 274,956
400,000 119,114 158,819 198,524 238,229 277,934 314,556
(1) Career Average Compensation is the average annual compensation
received from January 1, 1984 to retirement and includes Base
Salary, Deferred Compensation and Incentive Compensation Plan
awards. The Career Average Compensation amounts for the following
named executive officers differ by more than 10% from the three-
year average annual compensation set forth in the Summary
Compensation Table and are as follows: Messrs. Baldassari -
$140,376; Morrell - $117,030; Cudney - $117,193; Preis - $124,340;
and McCarthy - $115,745.
(2) Years of creditable service: Messrs. Baldassari - 24; Morrell - 22;
Cudney - 32; Preis - 33; and McCarthy - 33.
(3) Based on an assumed retirement at age 65 in 1994. To reduce the
above amounts to reflect a retirement benefit assuming a continual
annuity to a surviving spouse equal to 50% of the annuity payable at
retirement, multiply the above benefits by 90%. The estimated
annual benefits are not subject to any reduction for Social Security
benefits or other offset amounts.
(4) Annual retirement benefit cannot exceed 55% of the average
compensation received during the last three years prior to
retirement.
Remuneration of Directors
Nonemployee directors receive annual compensation of $13,000, a fee of
$1,000 for each Board meeting attended and a fee of $1,000 for each Committee
meeting attended. The Company has in effect a deferred remuneration plan
pursuant to which outside directors may elect to defer all or a portion of
current remuneration.
34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All of the Company's 15,371,270 outstanding shares of common stock are
owned beneficially and of record by the Company's parent, General Public
Utilities Corporation, 100 Interpace Parkway, Parsippany, New Jersey 07054.
The following table sets forth, as of February 1, 1994, the beneficial
ownership of equity securities of the Company and other GPU System companies
of each of the Company's directors and each of the executive officers named in
the Summary Compensation Table, and of all directors and officers of the
Company as a group. The shares owned by all directors and executive officers
as a group constitute less than 1% of the total shares outstanding.
Title of Amount and Nature of
Name Security Beneficial Ownership(1)
J. R. Leva GPU Common Stock 3,912 shares - Direct
D. Baldassari GPU Common Stock 945 shares - Direct
R. C. Arnold GPU Common Stock 6,751 shares - Direct
C. D. Cudney GPU Common Stock 1,445 shares - Direct
J. G. Graham GPU Common Stock 6,411 shares - Direct
1,780 shares - Indirect
E. J. McCarthy GPU Common Stock 897 shares - Direct
M. P. Morrell GPU Common Stock 1,003 shares - Direct
G. E. Persson GPU Common Stock None
P. H. Preis GPU Common Stock 1,305 shares - Direct
S. C. Van Ness GPU Common Stock None
S. B. Wiley GPU Common Stock None
All Directors and GPU Common Stock 28,658 shares - Direct
Officers as a group 1,780 shares - Indirect
(1) The number of shares owned and the nature of such ownership, not being
within the knowledge of the Company, have been furnished by each
individual.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
35
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K.
(a) See page F-1 for reference to Financial Statement Schedules required by
this item.
1. Exhibits:
3-A Restated Certificate of Incorporation of Jersey Central Power
& Light Company, as amended to date.
3-B Jersey Central Power & Light Company By-Laws, as amended.
10-A 1990 Stock Plan for Employees of General Public Utilities
Corporation and Subsidiaries, incorporated by reference to
Exhibit 10-B of the GPU Annual Report on Form 10-K for 1993 -
SEC File No. 1-6047.
10-B Form of Restricted Units Agreement under the 1990 Stock Plan,
incorporated by reference to Exhibit 10-C of the GPU Annual
Report on Form 10-K for 1993 - SEC File No. 1-6047.
10-C Incentive Compensation Plan for Officers of GPU System
Companies, incorporated by reference to Exhibit 10-E of the
GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
12 Statements Regarding Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends.
23 Consent of Independent Accountants.
(b) Reports on Form 8-K:
For the month of December 1993, dated December 10, 1993, under Item 5
(Other Events).
For the month of February 1994, dated February 16 and February 28,
1994, under Item 5 (Other Events).
36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
JERSEY CENTRAL POWER & LIGHT COMPANY
Dated: March 10, 1994 BY: /s/ D. Baldassari
D. Baldassari, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature and Title Date
/s/ J. R. Leva March 10, 1994
J. R. Leva, Chairman
(Principal Executive Officer) and Director
/s/ D. Baldassari March 10, 1994
D. Baldassari, President
(Principal Operating Officer) and Director
/s/ R. C. Arnold March 10, 1994
R. C. Arnold, Director
/s/ J. G. Graham March 10, 1994
J. G. Graham, Vice President
(Principal Financial Officer) and Director
/s/ M. P. Morrell March 10, 1994
M. P. Morrell, Vice President and Director
/s/ P. H. Preis March 10, 1994
P. H. Preis, Vice President-Comptroller
(Principal Accounting Officer) and Director
/s/ G. E. Persson March 10, 1994
G. E. Persson, Director
/s/ S. C. Van Ness March 10, 1994
S. C. Van Ness, Director
/s/ S. B. Wiley March 10, 1994
S. B. Wiley, Director
37
JERSEY CENTRAL POWER & LIGHT COMPANY
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Supplementary Data Page
Company Statistics F-2
Selected Financial Data F-3
Management's Discussion and Analysis of Financial
Condition and Results of Operations F-4
Quarterly Financial Data F-16
Financial Statements
Report of Independent Accountants F-17
Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991 F-19
Balance Sheets as of December 31, 1993 and 1992 F-20
Statements of Retained Earnings for the Years Ended
December 31, 1993, 1992 and 1991 F-22
Statement of Capital Stock as of December 31, 1993 F-22
Statements of Cash Flows for the Years Ended
December 31, 1993, 1992 and 1991 F-23
Statement of Long-Term Debt as of December 31, 1993 F-24
Notes to Financial Statements F-25
Financial Statement Schedules
Schedule V - Property, Plant and Equipment for the
Years 1991-1993 F-45
Schedule VI - Accumulated Depreciation and Amortization of
Property, Plant and Equipment for the Years 1991-1993 F-47
Schedule VIII - Valuation and Qualifying Accounts for the
Years 1991-1993 F-50
Schedule IX - Short-Term Borrowings for the Years 1991-1993 F-51
Schedules other than those listed above have been omitted since they are not
required, are inapplicable or the required information is presented in the
Financial Statements or Notes thereto.
F-1
Jersey Central Power & Light Company
COMPANY STATISTICS
For the Years Ended December 31, 1993 1992 1991 1990 1989 1988
Capacity at Company Peak (in MW):
Company-owned 2 839 2 826 2 836 2 821 2 823 2 757
Contracted 2 033 2 364 1 995 1 600 1 661 1 294
Total capacity (a) 4 872 5 190 4 831 4 421 4 484 4 051
Hourly Peak Load (in MW):
Summer peak 4 564 4 149 4 376 4 047 3 972 4 161
Winter peak 3 129 3 135 3 222 2 879 3 189 3 124
Reserve at Company peak (%) 6.7 25.1 10.4 9.2 12.9 (2.6)
Load factor (%) (b) 49.1 51.7 49.3 51.3 53.3 50.2
Sources of Energy:
Energy sales (in thousands of MWh):
Net generation 8 594 8 514 7 354 8 649 8 372 8 965
Power purchases and interchange 12 073 12 447 13 077 10 854 11 109 9 803
Total sources of energy 20 667 20 961 20 431 19 503 19 481 18 768
Company use, line loss, etc. (2 026) (2 075) (1 799) (1 404) (1 641) (1 592)
Total 18 641 18 886 18 632 18 099 17 840 17 176
Energy mix (%):
Coal 10 10 9 9 10 11
Nuclear 30 30 21 29 22 26
Utility purchases and interchange 35 34 47 46 50 51
Nonutility purchases 23 25 18 10 7 1
Other (gas, hydro & oil) 2 1 5 6 11 11
Total 100 100 100 100 100 100
Energy cost (in mills per KWh):
Coal 14.06 13.08 14.66 13.75 13.18 12.74
Nuclear 6.80 6.48 7.34 7.28 8.74 7.00
Utility purchases and interchange 18.35 18.72 20.50 22.30 22.32 21.69
Nonutility purchases 60.49 59.99 60.45 64.13 63.20 65.26
Other (gas & oil) 43.26 37.99 31.57 37.40 36.60 32.81
Average 25.34 25.57 25.07 22.33 23.09 18.93
Electric Energy Sales (in thousands of MWh):
Residential 6 983 6 568 6 757 6 497 6 615 6 638
Commercial 6 474 6 207 6 243 6 104 6 003 5 775
Industrial 3 689 3 723 3 816 3 790 3 899 3 960
Other 369 389 383 382 388 393
Sales to customers 17 515 16 887 17 199 16 773 16 905 16 766
Sales to other utilities 1 126 1 999 1 433 1 326 935 410
Total 18 641 18 886 18 632 18 099 17 840 17 176
Operating Revenues (in thousands):
Residential $ 835 242 $ 735 003 $ 750 408 $ 665 259 $ 651 015 $ 628 830
Commercial 698 641 629 884 619 516 558 833 528 547 483 347
Industrial 320 455 305 836 308 423 281 474 278 812 264 898
Other 40 415 39 918 39 313 36 651 38 165 37 287
Revenues from customers 1 894 753 1 710 641 1 717 660 1 542 217 1 496 539 1 414 362
Sales to other utilities 30 775 53 292 45 647 53 593 43 276 19 763
Total electric revenues 1 925 528 1 763 933 1 763 307 1 595 810 1 539 815 1 434 125
Other revenues 10 381 10 138 9 912 9 152 9 273 7 956
Total $1 935 909 $1 774 071 $1 773 219 $1 604 962 $1 549 088 $1 442 081
Price per KWh (in cents):
Residential 11.90 11.15 11.11 10.24 9.84 9.47
Commercial 10.78 10.08 9.93 9.16 8.80 8.37
Industrial 8.70 8.20 8.08 7.43 7.15 6.69
Total sales to customers 10.80 10.09 9.99 9.19 8.85 8.44
Total sales 10.31 9.30 9.47 8.82 8.63 8.35
Kilowatt-hour Sales per Residential Customer 8 669 8 264 8 585 8 303 8 534 8 696
Customers at Year-End (in thousands) 911 897 887 881 871 860
<FN>
(a) Summer ratings at December 31, 1993 of owned and contracted capacity were 2,849 MW and 1,913 MW, respectively.
(b) The ratio of the average hourly load in kilowatts supplied during the year to the peak load occurring during the year.
Certain reclassifications of prior years' data have been made to conform with current presentation.
F-2
Jersey Central Power & Light Company
SELECTED FINANCIAL DATA
(In Thousands)
For the Years Ended December 31, 1993 1992 1991* 1990 1989 1988
Operating revenues $1 935 909 $1 774 071 $1 773 219 $1 604 962 $1 549 088 $1 442 081
Other operation and
maintenance expense 460 128 424 285 433 562 398 598 403 174 395 621
Net income 158 344 117 361 153 523 126 532 131 902 146 626
Earnings available
for common stock 141 534 96 757 134 083 110 219 121 027 135 751
Net utility plant
in service 2 558 160 2 429 756 2 365 987 2 234 243 2 082 104 1 902 617
Cash construction
expenditures 197 059 218 874 241 774 271 588 270 255 253 640
Total assets 4 269 155 3 886 904 3 695 645 3 531 898 3 290 650 3 041 815
Long-term debt 1 215 674 1 116 930 1 022 903 927 686 899 058 790 852
Long-term obligations
under capital leases 6 966 4 645 5 471 4 459 2 886 2 338
Cumulative preferred stock
with mandatory redemption 150 000 150 000 100 000 100 000 - -
Return on average
common equity 11.1% 8.0% 11.9% 10.5% 12.5% 14.6%
<FN>
* Results for 1991 reflect an increase in earnings available for common stock of $27.1 million for an
accounting change recognizing unbilled revenues and a decrease in earnings of $5.7 million for estimated
TMI-2 costs.
F-3
Jersey Central Power & Light Company
Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations
In 1993, earnings available for common stock increased $44.8 million to
$141.5 million principally due to additional revenues resulting from a
February 1993 retail base rate increase and higher customer sales due
primarily to the significantly warmer-than-normal summer temperatures as
compared with the mild weather in 1992. Also contributing to the increase in
earnings was reduced reserve capacity expense. The increase in earnings was
partially offset by increased other operation and maintenance expense, the
write-off of approximately $9 million of costs related to the cancellation of
proposed energy-related agreements, and higher depreciation expense and
financing costs associated with additions to utility plant. Financing costs
reflect benefits derived from the early redemption of first mortgage bonds and
preferred stock.
Earnings available for common stock decreased $37.3 million to
$96.8 million in 1992 principally due to a reduction in customer sales
resulting from the mild summer weather in 1992 as compared with 1991 when the
Company's service territory experienced significantly warmer-than-normal
temperatures. The earnings comparison also reflects the absence in 1992 of a
nonrecurring credit with respect to a change in accounting policy resulting in
the recognition of unbilled revenues in 1991 of $27.1 million. Also
contributing to the decrease in earnings were increased financing costs and
depreciation expense associated with additions to utility plant. These
decreases in earnings were partially offset by an increase in revenues from
new residential and commercial customers, a slight increase in nonweather-
related usage and lower reserve capacity expense. Results for 1991 also
include the recognition of certain Three Mile Island Unit 2 (TMI-2) costs.
The Company's return on average common equity was 11.1% for 1993 as
compared with 8.0% and 11.9% for 1992 and 1991, respectively.
REVENUES:
Total revenues increased 9.1% to $1.9 billion in 1993 after remaining
relatively flat at $1.8 billion in 1992. The components of these changes are
as follows:
(In Millions)
1993 1992
Kilowatt-hour (KWh) revenues increase
(decrease) (excluding energy portion) $ 37.5 $(27.1)
Rate increase 108.2 -
Energy revenues 13.4 28.6
Other revenues 2.7 (0.6)
Increase in revenues $161.8 $ 0.9
F-4
Kilowatt-hour revenues
KWh revenues increased in 1993 principally due to higher third quarter
sales resulting from the significantly warmer-than-normal summer temperatures
as compared with the milder weather during the same period in 1992. An
increase in nonweather-related usage in the residential and commercial
sectors, and a 1.4% increase in the average number of customers also
contributed to the increase in kWh revenues. New customer growth occurred
primarily in the residential sector, and was partially offset by a reduction
in the number of industrial customers.
In 1992, kWh revenues decreased primarily due to mild weather during the
third quarter of 1992 as compared with warmer-than-normal weather during the
same period in 1991. This decrease was partially offset by a 1.0% increase in
the average number of customers and a slight increase in nonweather-related
usage. New customer growth occurred in the residential and commercial
categories. The increase in nonweather-related usage was reflected primarily
in the residential and commercial sectors.
Rate increase
In February 1993, the New Jersey Board of Regulatory Commissioners
(NJBRC) authorized a $123 million increase in retail base rates, or
approximately 7% annually.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased in 1993 as a result of increased kWh
sales to ultimate customers partially offset by decreased sales to other
utilities.
In 1992, energy revenues increased as a result of the March 1992 increase
in the energy cost rates in effect and a significant increase in kWh sales to
other utilities. These increases were partially offset by a decrease in kWh
sales in all other customer categories. The increase in 1992 reflects a 24%
increase in energy revenues associated with electric sales to other utilities.
Other revenues
Generally, changes in other revenues do not affect earnings as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
F-5
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings as they are
substantially recovered through the Company's energy clause. Earnings in
1993, however, were favorably impacted by a reduction in reserve capacity
expense resulting from the expiration of a purchase contract with another
utility and a reduction in purchases from another utility. Power purchased
and interchanged also decreased in 1993 due to a decrease in nonutility
generation purchases.
In 1992, power purchased and interchanged increased due to an increase in
nonutility generation purchases offset partially by reductions in energy and
capacity purchases from other utilities and a decrease in interchange
received.
Other operation and maintenance
Other operation and maintenance expense increased in 1993 primarily due
to emergency and storm-related activities and higher-than-normal tree trimming
expense. Other operation and maintenance expense also increased due to the
recognition of current and previously deferred demand side management expenses
as directed in the Company's rate orders, an increase in the accrual of
nuclear outage maintenance costs and an increase in the amortization of
previously deferred nuclear expenses.
The decrease in 1992 is due to the absence of $6.8 million of estimated
costs recognized in 1991 for preparing the TMI-2 plant for long-term monitored
storage and $2.5 million of previously deferred cleanup costs. Excluding
these amounts, other operation and maintenance expense remained relatively
stable.
Depreciation and amortization
Depreciation and amortization expense increased in 1993 due to additions
to utility plant and the recognition of additional amortization expense for
deferred assets as a result of the rate case completed in 1993. The 1992
increase was due to additions to utility plant. These additions consist
primarily of additions to existing generating facilities to enhance system
reliability and additions to the transmission and distribution system related
to new customer growth.
Taxes, other than income taxes
Generally, changes in taxes other than income taxes do not significantly
affect earnings as they are substantially recovered in revenues.
F-6
OTHER INCOME AND DEDUCTIONS:
Other income, net
The reduction in other income, net in 1993 is principally due to the
write-off of approximately $9 million of costs related to the cancellation of
proposed energy-related agreements between the Company and its affiliates and
Duquesne Light Company (Duquesne). The decrease is also due to the absence of
carrying charges on certain tax payments made by the Company in 1992, which
are now being recovered through rates.
The increase in other income, net in 1992 is mainly attributable to an
increase in miscellaneous income related to the anticipated recovery of
carrying charges, offset partially by a reduction in interest income resulting
from the 1991 collection of federal income tax refunds.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt increased in 1993 and 1992 primarily due to
the issuance of additional long-term debt, offset partially by decreases
associated with the refinancing of higher cost debt at lower interest rates.
Other interest was favorably affected by lower short-term interest rates and a
reduction in the average levels of short-term borrowings outstanding in both
years. The decrease in other interest in 1992, however, was mainly the result
of a lower federal income tax deficiency accrual level as tax deficiency
payments relating to the 1983 and 1984 tax years were made in 1991.
Preferred dividends decreased in 1993 primarily due to the redemption of
an aggregate $50 million of preferred stock. Preferred dividends increased in
1992 primarily due to the issuance of preferred stock in mid-1992, partially
offset by the effect of a redemption in the latter part of 1992.
Liquidity and Capital Resources
CAPITAL NEEDS:
The Company's capital needs were $212 million in 1993, consisting of cash
construction expenditures of $197 million and amounts for maturing obligations
of $15 million. During 1993, construction funds were primarily used to
continue to maintain and improve existing generating facilities and add to the
transmission and distribution system. GPU System cash construction
expenditures are estimated to be $663 million in 1994, of which the Company's
share is $275 million. The expenditures consist mainly of $231 million for
ongoing system development and $19 million for clean air requirements.
Expenditures for maturing debt are expected to be $60 million for 1994 and
$47 million for 1995. In the mid-1990s, construction expenditures may include
substantial amounts for clean air requirements, the construction of new
generation facilities and other Company needs. Management estimates that
approximately one-half of the Company's 1994 capital needs will be satisfied
through internally generated funds.
F-7
The Company and its affiliates' capital leases consist primarily of
leases for nuclear fuel. These nuclear fuel leases are renewable annually,
subject to certain conditions. An aggregate of up to $250 million
($125 million each for Oyster Creek and Three Mile Island Unit 1) of nuclear
fuel costs may be outstanding at any one time. The Company's share of nuclear
fuel capital leases at December 31, 1993 totaled $86 million. When consumed,
portions of the currently leased material will be replaced by additional
leased material at a rate of approximately $36 million annually. In the event
this nuclear fuel cannot be leased, the associated capital requirements would
have to be met by other means.
FINANCING:
In 1993, the Company refinanced higher cost long-term debt in the
principal amount of $394 million, resulting in an estimated annualized after-
tax savings of $4 million. Total long-term debt issued during 1993 amounted
to $555 million. In addition, the Company redeemed $50 million of high-
dividend preferred stock issues.
The Company has regulatory authority to issue and sell first mortgage
bonds, which may be issued as secured medium-term notes, and preferred stock
through June 1995. Under existing authorization, the Company may issue senior
securities in the amount of $275 million, of which $100 million may consist of
preferred stock. The Company also has regulatory authority to incur short-
term debt, a portion of which may be through the issuance of commercial paper.
The Company's cost of capital and ability to obtain external financing is
affected by its security ratings, which continue to remain above minimum
investment grade. The Company's first mortgage bonds are currently rated at
an equivalent of an A- rating by the three major credit rating agencies, while
an equivalent of a BBB+ rating is assigned to the preferred stock issues. In
addition, the Company's commercial paper is rated as having good to very good
credit quality.
During 1993, Standard & Poor's revised its financial benchmarking
standards for rating the debt of electric utilities to reflect the changing
risk profiles resulting primarily from the intensifying competitive pressures
in the industry. These guidelines now include an assessment of a company's
business risk. Standard & Poor's new rating structure changed the business
outlook for the debt ratings of approximately one-third of the industry,
including the Company, which moved from "A-stable" to "A-negative," meaning
their credit ratings may be lowered. The Company was classified as "below
average" in its business risk position due to the perceived credit risk
associated with large purchased power requirements, relatively high rates and
a sluggish local economy. Moody's announced that it expects to reduce its
average credit ratings for the electric utility industry within the next three
years to take into account the effects of the new competitive environment.
Duff & Phelps also indicated that it intends to introduce a forecast element
to its quantitative analysis to, among other things, "alert investors to the
possibility of equity value reduction and credit quality deterioration."
F-8
The Company's bond indenture and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and
short-term debt the Company can issue. The Company's interest and preferred
stock coverage ratios are currently in excess of indenture or charter
restrictions. The ability to issue securities in the future will depend on
coverages at that time. Current plans call for the Company to issue long-
term debt and preferred stock during the next three years to finance
construction activities and, depending on the level of interest rates,
refinance outstanding senior securities.
CAPITALIZATION:
The Company supports its credit quality rating by maintaining
capitalization ratios that permit access to capital markets at a competitive
cost. The targets and actual capitalization ratios are as follows:
Capitalization
Target Range 1993 1992 1991
Common equity 47-50% 47% 47% 47%
Preferred stock 7-10 7 9 9
Notes payable and
long-term debt 46-40 46 44 44
100% 100% 100% 100%
Recent evaluations of the industry by credit rating agencies indicate
that the Company may have to increase its equity ratio to maintain its
current credit ratings.
COMPETITIVE ENVIRONMENT:
The Push Toward Competition
The electric utility industry appears to be undergoing a major transition
as it proceeds from a traditional rate regulated environment based on cost
recovery to some combination of competitive marketplace and modified
regulation of certain market segments. The industry challenges resulting
from various instances of competition, deregulation and restructuring thus
far have been minor compared with the impact that is expected in the future.
The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the
entry of competitors into the electric generation business. Since then, more
competition has been introduced through various state actions to encourage
cogeneration and, most recently, through the federal Energy Policy Act of
1992 (Energy Act). The Energy Act is intended to promote competition among
utility and nonutility generators in the wholesale electric generation
market, accelerating the industry restructuring that has been underway since
the enactment of PURPA. This legislation, coupled with increasing customer
demands for lower-priced electricity, is generally expected to stimulate even
greater competition in both the wholesale and retail electricity markets.
These competitive pressures may create opportunities to compete for new
customers and revenues, as well as increase risk that could lead to the loss
of customers.
F-9
Operating in a competitive environment will place added pressures on
utility profit margins and credit quality. Utilities with significantly
higher cost structures than supportable in the marketplace may experience
reduced earnings as they attempt to meet their customers' demands for lower-
priced electricity. This prospect of increasing competition in the electric
utility industry has already led the credit rating agencies to address and
apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the Federal Energy Regulatory
Commission (FERC), subject to certain criteria, to order owners of electric
transmission systems, such as the Company and its affiliates, to provide third
parties transmission access for wholesale power transactions. The Energy Act
did not give the FERC the authority, however, to order retail transmission
access. That authority lies with the individual states, and movement toward
opening the transmission network to retail customers is currently under
consideration in several states.
Recent Events
Competition in the electric utility industry has already played a
significant role in wholesale transactions, affecting the pricing of energy
sales to electric cooperatives and municipal customers. During 1993, Penelec
successfully negotiated power supply agreements with the Company's wholesale
customers in response to offers made by other utilities seeking to provide
electric service at rates lower than those of the Company. The Company will
continue its efforts to retain and add customers by offering competitive
rates.
The competitive forces have also begun to influence some retail pricing
in the industry. In a few instances, industrial customers, threatening to
pursue cogeneration, self-generation or relocation to other service
territories, have leveraged price concessions from utilities. Recent state
regulatory actions, such as in New Jersey, suggest that utilities may have
limited success with attempting to shift costs associated with such discounts
to other customers. Utilities may have to absorb, in whole or part, the
effects of price reductions designed to retain large retail customers. State
regulators may put a limit or cap on prices, especially for those customers
unable to pursue alternative supply options.
In December 1993, the Company filed a proposal with the NJBRC seeking
approval to implement a new rate initiative designed to retain and expand the
economic base in New Jersey. Under the proposed contract rate service, large
retail customers could enter into contracts for existing electric service at
prevailing rates, with limitations on their exposure to future rate increases.
With this rate initiative, the Company will have to absorb any differential in
price resulting from changes in costs not provided for in the contracts. This
matter is pending before the NJBRC.
Proposed legislation has been introduced in New Jersey that is intended
to allow the NJBRC, at the request of an electric or gas utility, to adopt a
plan of regulation other than traditional ratemaking methods to encourage
economic development and job creation. This flexible ratemaking would allow
electric utilities to be more competitive with nonutility generators, who are
F-10
not subject to NJBRC regulation. Combined with other economic development
initiatives, this legislation, if enacted, would provide more flexibility in
responding to competitive pressures, but may also serve to accelerate the
growth of competitive pressures.
Financial Exposure
In the transition from a regulated to competitive environment, there can
be a significant change in the economic value of a utility's assets.
Traditional utility regulation provides an opportunity for recovery of the
cost of plant assets, along with a return on investment, through ratemaking.
In a competitive market, the value of an asset may be determined by the market
price of the services derived from that asset. If the cost of operating
existing assets results in above-market prices, a utility may be unable to
recover all of its costs, resulting in "stranded assets" and other
unrecoverable costs. This may result in write-downs to remove stranded assets
from a utility's balance sheet in recognition of their reduced economic value
and the recognition of other losses.
Unrecovered costs will most likely be related to generation investment,
purchased power contracts, and "regulatory assets," which are deferred
accounting transactions whose value rests on the strength of a state
regulatory decision to allow future recovery from ratepayers. In markets
where there is excess capacity (as there currently is in the region including
New Jersey) and many available sources of power supply, the market price of
electricity may be too low to support full recovery of capital costs of
certain existing power plants, primarily the capital intensive plants such as
nuclear units. Another significant exposure in the transition to a
competitive market results if the prices of a utility's existing purchase
power contracts, consisting primarily of contractual obligations with
nonutility generators, are higher than future market prices. Utilities locked
into expensive purchase power arrangements may be forced to value the
contracts at market prices and recognize certain losses. A third source of
exposure is regulatory assets, that if not supported by regulators, would have
no value in a competitive market. Financial Accounting Standard No. 71
(FAS 71), "Accounting for the Effects of Certain Types of Regulation," applies
to regulated utilities that have the ability to recover their costs through
rates established by regulators and charged to customers. If a portion of the
Company's operations continues to be regulated, FAS 71 accounting may be
applied only to that portion. Write-offs of utility plant and regulatory
assets may result for those operations that no longer meet the requirements of
FAS 71. In addition, under deregulation, the uneconomical costs of certain
contractual commitments for purchased power and/or fuel supplies may have to
be expensed. Management believes that to the extent that the Company no
longer qualifies for FAS 71 accounting treatment, a material adverse effect on
its results of operations and financial position may result. At this time, it
is difficult for management to project the future level of stranded assets or
other unrecoverable costs, if any, without knowing what the market price of
electricity will be, or if regulators will allow recovery of industry
transition costs from customers.
F-11
Positioning the GPU System
The typical electric utility today is vertically integrated, operating
its plant assets to serve all customers within a franchised service territory.
In the future, franchised service territories may be replaced by markets whose
boundaries are defined by price, available capacity and transmission access.
This may result in changes to the organizational structure of utilities and an
emphasis on certain segments of the business among generation, transmission
and distribution.
In order to achieve a strong competitive position in a less regulated
future, the GPU System has in place a strategic planning process. In the
initial phases of the program, task forces are defining the principal
challenges facing the GPU System, exploring opportunities and risks, and
defining and evaluating strategic alternatives.
Management is now analyzing issues associated with various competitive
and regulatory scenarios to determine how best to position the GPU System for
a competitive environment. An initial outcome of the GPU System ongoing
strategic planning process was a realignment proposed in February 1994, of
certain system operations. Subject to necessary regulatory approval, a new
subsidiary, GPU Generation Corporation, will be formed to operate and maintain
the GPU System's fossil-fueled and hydroelectric generating stations, which
are now owned and operated by the Company and its affiliates. It is also
intended to combine the remaining Met-Ed and Penelec operations without
merging the two companies. The GPU System is also developing a performance
improvement and cost reduction program to help assure ongoing competitiveness,
and, among other matters, will also address workforce issues in terms of
compensation, size and skill mix.
MEETING ENERGY DEMANDS:
In response to the increasingly competitive business climate and excess
capacity of nearby utilities, the GPU System's supply plan places an emphasis
on maintaining flexibility. Supply planning focuses increasingly on short-
term to intermediate-term commitments, reliance on "spot" markets, and
avoidance of long-term firm commitments. The Company is expected to experience
an average growth rate in sales to customers (exclusive of the loss of its
wholesale customers) through 1998 of about 1.6% annually. The Company also
expects to experience peak load growth although at a somewhat lesser rate.
Through 1998, the Company's plan consists of the continued utilization of
existing generating facilities combined with present commitments for power
purchases and new power purchases (of short-term or intermediate-term
duration), the construction of a new facility, and the utilization of capacity
of its affiliates. The plan also includes the continued promotion of
economical energy conservation and load management programs. Given the future
direction of the industry, the Company's present strategy includes minimizing
the financial exposure associated with new long-term purchase commitments and
the construction of new facilities by including projected market prices in the
evaluation of these options. The Company will resist efforts to compel it to
add new capacity at costs that may exceed future market prices. In addition,
the Company will seek regulatory support to renegotiate or buy out contracts
with nonutility generators where the pricing is in excess of projected avoided
costs.
F-12
New Energy Supplies
The Company's supply plan includes the addition of 533 MW of currently
contracted capacity by 1998 from nonutility generation suppliers, and reflects
the construction of a new peaking unit. The Company currently has uncommitted
capacity needs by 1998 of approximately 500 MW, which represents essentially
all the uncommitted needs of the GPU System. These capacity needs may be
filled by a combination of utility and nonutility purchases (of short-term or
intermediate-term duration) as well as company-owned facilities. Additions
are principally to replace expiring purchase arrangements rather than to serve
new customer load.
In July 1993, an NJBRC Advisory Council recommended in a report that
all New Jersey electric utilities be required to submit integrated resource
plans for review and approval by the NJBRC.
The NJBRC has asked all electric utilities in the state to assess the
economics of their purchase power contracts with nonutility generators to
determine whether there are any candidates for potential buy-out or other
remedial measures. The Company identified a 100-MW project now under
development, which it believes is economically undesirable based on current
cost projections. In November 1993, the NJBRC directed the Company and the
developer to negotiate contract repricing to a level more consistent with the
Company's current avoided cost projections or a contract buy-out. The
developer has filed a federal court action contesting the NJBRC's jurisdiction
in this matter.
In November 1993, the NJBRC granted two nonutility generators, having a
total of 200 MW under contract with the Company, a one-year extension in the
in-service date for projects originally scheduled to be operational in 1997.
The Company is awaiting a final written NJBRC order.
Also in November 1993, the Company received approval from the NJBRC to
withdraw the Company's request for proposals for the purchase of 150 MW from
nonutility generators. In its petition, the Company cited, among other
reasons, that solicitations for long-term contracts would have limited its
ability to compete in a deregulated environment.
The Company has entered into an arrangement for a peaking generation
project whereby it plans to install a gas-fired combustion turbine at its
Gilbert Generating station and retire two steam units for an 88-MW net
increase in capacity at an expected cost of $50 million. The Company expects
to complete the project by 1996.
F-13
In December 1993, the NJBRC denied the Company's petition to
participate in the proposed power supply and transmission facilities
agreements between the Company and its affiliates and Duquesne. As a result
of this action and other developments, the Company and its affiliates notified
Duquesne that they were exercising their rights under the agreements to
withdraw from and thereby terminate the agreements. The capital costs of the
GPU System's share of these transactions would have totaled approximately $500
million, of which the Company's share would have been $215 million.
In January 1994, the Company issued an all source solicitation for the
short-term supply of energy and/or capacity to determine and evaluate the
availability of competitively priced power supply options. The Company is
seeking proposals from utility and nonutility generation suppliers, for
periods of one to eight years in length, that are capable of delivering
electric power beginning in 1996. This solicitation is expected to fulfill a
significant part of the uncommitted sources identified in the Company's supply
plan.
Conservation and Load Management
The regulatory environment in New Jersey encourages the development of
new conservation and load management programs. This is evidenced by demand-
side management (DSM) incentive regulations adopted in New Jersey in 1992.
DSM includes utility-sponsored activities designed to improve energy
efficiency in customer end-use, and includes load management programs (i.e.,
peak reduction) and conservation programs (i.e., energy and peak reduction).
The NJBRC approved the Company's DSM plan in 1992 reflecting DSM
initiatives of 67 MW of summer peak reduction by the end of 1994. Under the
approved regulation, qualified Performance Program DSM investments are
recovered over a six-year period with a return earned on the unrecovered
amounts. Lost revenues will be recovered on an annual basis, and the Company
can also earn a performance-based incentive for successfully implementing
cost-effective programs. In addition, the Company will continue to make
certain NJBRC-mandated Core Program DSM investments, which are recovered
annually.
ENVIRONMENTAL ISSUES:
The Company is committed to complying with all applicable environmental
regulations in a responsible manner. Compliance with the federal Clean Air
Act Amendments of 1990 (Clean Air Act) and other environmental needs will
present a major challenge to the Company through the late 1990s.
The Clean Air Act will require substantial reductions in sulfur dioxide
and nitrogen oxide emissions by the year 2000. The Company's current plan
includes installing and operating emission control equipment at the Keystone
station in which the Company has a 16.67% ownership interest. To comply with
F-14
the Clean Air Act, the Company expects to expend up to $145 million by the
year 2000 for air pollution control equipment. The GPU System reviews its
plans and alternatives to comply with the Clean Air Act on a least-cost basis
taking into account advances in technology and the emission allowance market,
and assesses the risk of recovering capital investments in a competitive
environment. The GPU System may be able to defer substantial capital
investments while attaining the required level of compliance if an alternative
such as increased participation in the emission allowance market is determined
to result in the least-cost plan. This and other compliance alternatives may
result in the substitution of increased operating expenses for capital costs.
At this time, costs associated with the capital invested in this pollution
control equipment and the increased operating costs of the affected station
are expected to be recoverable through the ratemaking process, but management
recognizes that recovery is not assured.
For more information, see the Environmental Matters section of Note 1
to the Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, individual claims
for alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against the Company and its affiliates
and GPU and are still pending. For more information, see Note 1 to the
Financial Statements.
EFFECTS OF INFLATION:
The Company is affected by inflation since the regulatory process
results in a time lag during which increased operating expenses are not fully
recovered in rates. Inflation may have an even greater effect in a period of
increasing competition and deregulation as the Company and the utility
industry attempt to keep rates competitive.
Inflation also affects the Company in the form of higher replacement
costs of utility plant. In the past, the Company anticipated the recovery of
these cost increases through the ratemaking process. However, as competition
and deregulation accelerate throughout the industry, there can be no assurance
of the recovery of these increased costs.
The Company is committed to long-term cost control and is continuing to
seek measures to reduce or limit the growth in operating expenses. The
prudent expenditure of capital and debt refinancing programs have kept down
increases in capital costs and debt levels.
ACCOUNTING ISSUES:
In May 1993, the Financial Accounting Standards Board issued FAS 115,
"Accounting for Certain Investments in Debt and Equity Securities," which is
effective for fiscal years beginning after December 15, 1993. FAS 115
requires the recording of unrealized gains and losses with a corresponding
offsetting entry to earnings or shareholder's equity. The impact on the
Company's financial position is expected to be immaterial, and there will be
no impact on the results of operations. FAS 115 will be implemented in 1994.
F-15
Jersey Central Power & Light Company
QUARTERLY FINANCIAL DATA (Unaudited)
(In Thousands)
First Quarter Second Quarter Third Quarter Fourth Quarter
1993 1992 1993 1992 1993 1992 1993* 1992
Operating revenues $448 634 $442 937 $463 354 $420 925 $576 268 $489 445 $447 653 $420 764
Operating income 51 411 52 393 57 053 41 365 98 552 61 141 49 914 38 955
Net income 30 830 32 987 31 551 23 000 75 239 42 765 20 724 18 609
Earnings available
for common stock 26 124 28 127 26 845 17 762 71 540 36 965 17 025 13 903
<FN>
* Results for the fourth quarter of 1993 reflect a decrease in earnings of $6.0 million (net of income
taxes of $3.3 million) for the write-off of the Duquesne transactions.
F-16
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors
Jersey Central Power & Light Company
Morristown, New Jersey
We have audited the financial statements and financial statement schedules of
Jersey Central Power & Light Company as listed in the index on page F-1 of
this Form 10-K. These financial statements and financial statement schedules
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedules 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 Jersey Central Power & Light
Company as of December 31, 1993 and 1992, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting principles.
In addition, in our opinion, the financial statement schedules referred to
above, when considered in relation to the basic financial statements taken as
a whole, present fairly, in all material respects, the information required to
be included therein.
F-17
As more fully discussed in Note 1 to financial statements, the Company is
unable to determine the ultimate consequences of the contingency which has
resulted from the accident at Unit 2 of the Three Mile Island Nuclear
Generating Station. The matter which remains uncertain is the excess, if any,
of amounts which might be paid in connection with claims for damages resulting
from the accident over available insurance proceeds.
As discussed in Notes 5 and 7 to the financial statements, the Company was
required to adopt the provisions of the Financial Accounting Standards Board's
Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for
Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" in 1993. Also, as discussed in
Note 2 to the financial statements, the Company changed its method of
accounting for unbilled revenues in 1991.
Parsippany, New Jersey COOPERS & LYBRAND
February 2, 1994
F-18
Jersey Central Power & Light Company
STATEMENTS OF INCOME
(In Thousands)
For the Years Ended December 31, 1993 1992 1991
Operating Revenues $1 935 909 $1 774 071 $1 773 219
Operating Expenses:
Fuel 98 683 84 851 100 758
Power purchased and interchanged:
Affiliates 23 681 24 281 30 040
Others 578 131 616 418 576 217
Deferral of energy and capacity
costs, net 28 726 4 232 (27)
Other operation and maintenance 460 128 424 285 433 562
Depreciation and amortization 182 945 167 022 159 747
Taxes, other than income taxes 228 690 215 507 219 611
Total operating expenses 1 600 984 1 536 596 1 519 908
Operating Income Before Income Taxes 334 925 237 475 253 311
Income taxes 77 995 43 621 50 779
Operating Income 256 930 193 854 202 532
Other Income and Deductions:
Allowance for other funds
used during construction 2 471 4 015 3 136
Other income, net 6 281 21 519 20 664
Income taxes (2 847) (8 268) (8 459)
Total other income and deductions 5 905 17 266 15 341
Income Before Interest Charges 262 835 211 120 217 873
Interest Charges:
Interest on long-term debt 100 246 92 942 85 420
Other interest 6 530 4 873 11 540
Allowance for borrowed funds
used during construction (2 285) (4 056) (5 547)
Total interest charges 104 491 93 759 91 413
Income Before Cumulative Effect of
Accounting Change 158 344 117 361 126 460
Cumulative effect as of January 1,
1991 of accounting change for
unbilled revenues, net of
income taxes of $13,942 - - 27 063
Net Income 158 344 117 361 153 523
Preferred stock dividends 16 810 20 604 19 440
Earnings Available for Common Stock $ 141 534 $ 96 757 $ 134 083
The accompanying notes are an integral part of the financial statements.
F-19
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands)
December 31, 1993 1992
ASSETS
Utility Plant:
In service, at original cost $3 938 700 $3 692 318
Less, accumulated depreciation 1 380 540 1 262 562
Net utility plant in service 2 558 160 2 429 756
Construction work in progress 102 178 178 902
Other, net 116 751 130 307
Net utility plant 2 777 089 2 738 965
Current Assets:
Cash and temporary cash investments 17 301 140
Special deposits 7 124 8 190
Accounts receivable:
Customers, net 133 407 117 755
Other 31 912 26 401
Unbilled revenues 57 943 53 588
Materials and supplies, at average cost or less:
Construction and maintenance 102 659 101 187
Fuel 11 886 23 576
Deferred income taxes 28 650 57 327
Prepayments 58 057 29 727
Total current assets 448 939 417 891
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 146 284 153 912
Unamortized property losses 109 478 108 825
Deferred income taxes 110 794 59 599
Income taxes recoverable through
future rates 121 509 -
Decommissioning funds 139 279 114 650
Special deposits 82 103 76 807
Other 333 680 216 255
Total deferred debits and other assets 1 043 127 730 048
Total Assets $4 269 155 $3 886 904
The accompanying notes are an integral part of the financial statements.
F-20
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands)
December 31, 1993 1992
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 435 715 435 715
Retained earnings 724 194 644 899
Total common stockholder's equity 1 313 622 1 234 327
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 37 741 87 877
Long-term debt 1 215 674 1 116 930
Total capitalization 2 717 037 2 589 134
Current Liabilities:
Debt due within one year 60 008 14 485
Notes payable - 5 700
Obligations under capital leases 89 631 107 331
Accounts payable:
Affiliates 34 538 54 618
Other 95 509 99 666
Taxes accrued 119 337 127 406
Deferred energy credits 23 633 1 257
Interest accrued 33 804 33 294
Other 50 950 53 967
Total current liabilities 507 410 497 724
Deferred Credits and Other Liabilities:
Deferred income taxes 569 966 425 157
Unamortized investment tax credits 79 902 86 021
Three Mile Island Unit 2 future costs 79 967 80 000
Other 314 873 208 868
Total deferred credits and
other liabilities 1 044 708 800 046
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 269 155 $3 886 904
The accompanying notes are an integral part of the financial statements.
F-21
Jersey Central Power & Light Company
STATEMENTS OF RETAINED EARNINGS
(In Thousands)
For the Years Ended December 31, 1993 1992 1991
Balance, beginning of year $644 899 $580 523 $486 440
Add, net income 158 344 117 361 153 523
Total 803 243 697 884 639 963
Deduct,
Cash dividends on capital stock:
Cumulative preferred stock (at the annual rates
indicated below):
4% Series ($4.00 a share) 500 500 500
8.12% Series ($8.12 a share) 1 015 2 030 2 030
8% Series ($8.00 a share) 1 000 2 000 2 000
7.88% Series E ($7.88 a share) 1 970 1 970 1 970
8.75% Series H ($2.19 a share) - 3 281 4 375
8.48% Series I ($8.48 a share) 4 240 4 240 4 240
8.65% Series J ($8.65 a share) 4 325 4 325 4 325
7.52% Series K ($7.52 a share) 3 760 2 258 -
Common stock (not declared on a per share basis) 60 000 30 000 40 000
Other adjustments 2 239 2 381 -
Total 79 049 52 985 59 440
Balance, end of year $724 194 $644 899 $580 523
Jersey Central Power & Light Company
STATEMENT OF CAPITAL STOCK
December 31, 1993 (In Thousands)
Cumulative preferred stock, without par value, 15,600,000 shares authorized
(1,875,000 shares issued and outstanding) (a), (b) & (c):
Cumulative preferred stock - no mandatory redemption:
125,000 shares, 4% Series, callable at $106.50 a share $ 12 500
250,000 shares, 7.88% Series E, callable at $103.65 a share 25 000
Premium on cumulative preferred stock 241
Total cumulative preferred stock - no mandatory redemption,
including premium $ 37 741
Cumulative preferred stock - with mandatory redemption (d):
500,000 shares, 8.48% Series I $ 50 000
500,000 shares, 8.65% Series J 50 000
500,000 shares, 7.52% Series K 50 000
Total cumulative preferred stock - with mandatory redemption $150 000
Common stock, par value $10 a share, 16,000,000 shares authorized,
15,371,270 shares issued and outstanding $153 713
<FN>
(a) During 1992, the Company issued a 7.52% series of cumulative preferred stock with mandatory redemption
provisions. The 7.52% series is callable beginning in the year 2002 at various prices above its stated
value and is to be redeemed ratably over 20 years beginning in the year 1998. The Company also has
outstanding an 8.48% and an 8.65% series of cumulative preferred stock with mandatory redemption
provisions. The 8.48% series is not callable. The 8.65% series is callable beginning in the year 2000
at various prices above its stated value. The 8.48% series is to be redeemed ratably over five years
beginning in 1996 and the 8.65% series ratably over six years beginning in the year 2000. Each issue of
cumulative preferred stock with mandatory redemption provisions provides that the Company may, at its
option, redeem an amount of shares equal to its mandatory sinking fund requirement at such time as the
mandatory sinking fund redemption is made. Expenses of $.5 million incurred in connection with the
issuance of the 7.52% cumulative preferred stock were charged to Capital Surplus on the balance sheet.
No shares of preferred stock other than the 7.52% series were issued in the three years ended
December 31, 1993.
(b) During 1993, the Company redeemed all of its outstanding 8.12% series of cumulative preferred stock
(aggregate stated value of $25 million), at a total cost of $26.1 million. Also during 1993, the
Company redeemed all of its outstanding 8% series of cumulative preferred stock (aggregate stated value
of $25 million), at a total cost of $26.3 million. These redemptions resulted in a net $2.2 million
charge to retained earnings. During 1992, the Company redeemed all of its outstanding 8.75% series of
cumulative preferred stock (aggregate stated value of $50 million), at a total cost of $51.6 million.
This resulted in a $1.6 million charge to retained earnings. Additional preferred stock expenses of
$.8 million were charged to retained earnings. No other shares of preferred stock were redeemed in the
three years ended December 31, 1993.
(c) If dividends on any of the preferred stock are in arrears for four quarters, the holders of preferred
stock, voting as a class, are entitled to elect a majority of the board of directors until all dividends
in arrears have been paid. No redemptions of preferred stock may be made unless dividends on all
preferred stock for all past quarterly dividend periods have been paid or declared and set aside for
payment. Stated value of the Company's cumulative preferred stock is $100 per share.
(d) The Company's aggregate liability with regard to redemption provisions on its cumulative preferred stock
for the years 1994 through 1998, based on issues outstanding at December 31, 1993, is $32.5 million.
All redemptions are at stated value of the shares, plus accrued dividends.
The accompanying notes are an integral part of the financial statements.
F-22
Jersey Central Power & Light Company
STATEMENTS OF CASH FLOWS
(In Thousands)
For the Years Ended December 31, 1993 1992 1991
Operating Activities:
Income before preferred dividends $ 158 344 $ 117 361 $ 153 523
Adjustments to reconcile income to cash provided:
Depreciation and amortization 199 201 177 245 173 503
Amortization of property under capital leases 34 333 35 137 26 341
Cumulative effect of accounting change - - (27 063)
Nuclear outage maintenance costs, net 1 323 9 144 (15 237)
Deferred income taxes and investment tax credits, net 39 139 14 630 3 426
Deferred energy and capacity costs, net 29 305 4 135 192
Accretion income (14 500) (15 400) (16 200)
Allowance for other funds used during construction (2 471) (4 015) (3 136)
Changes in working capital:
Receivables (25 579) 934 41 352
Materials and supplies 10 218 (2 737) (7 223)
Special deposits and prepayments (24 672) (12 818) 3 331
Payables and accrued liabilities (111 061) (3 687) (14 492)
Other, net (26 938) (22 682) 2 067
Net cash provided by operating activities 266 642 297 247 320 384
Investing Activities:
Cash construction expenditures (197 059) (218 874) (241 774)
Contributions to decommissioning trust (18 896) (19 008) (18 019)
Other, net (7 695) (15 660) (20 487)
Net cash used for investing activities (223 650) (253 542) (280 280)
Financing Activities:
Issuance of long-term debt 548 600 367 396 148 963
Decrease in notes payable, net (5 700) (38 100) (70 542)
Retirement of long-term debt (408 527) (282 717) (34 488)
Capital lease principal payments (30 011) (38 029) (25 906)
Issuance of preferred stock - 50 000 -
Redemption of preferred stock (52 375) (51 635) -
Dividends paid on common stock (60 000) (30 000) (40 000)
Dividends paid on preferred stock (17 818) (20 758) (19 440)
Net cash required by financing activities (25 831) (43 843) (41 413)
Net increase (decrease) in cash and temporary
cash investments from above activities 17 161 (138) (1 309)
Cash and temporary cash investments, beginning of year 140 278 1 587
Cash and temporary cash investments, end of year $ 17 301 $ 140 $ 278
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 129 868 $ 103 845 $ 112 382
Income taxes paid $ 42 605 $ 51 714 $ 89 284
New capital lease obligations incurred $ 18 919 $ 35 617 $ 18 839
The accompanying notes are an integral part of the financial statements.
F-23
Jersey Central Power & Light Company
STATEMENT OF LONG-TERM DEBT
December 31, 1993 (In Thousands)
First Mortgage Bonds - Series as noted (a), (b) & (c):
8.85% Series due 1994 $20 000 7 1/8% Series due 2004 160 000
8.70% Series due 1994 20 000 6.78% Series due 2005 50 000
8.65% Series due 1994 20 000 8.25% Series due 2006 50 000
4 7/8% Series due 1995 17 430 7.90% Series due 2007 40 000
8.64% Series due 1995 5 000 7 1/8% Series due 2009 6 300
8.70% Series due 1995 25 000 7.10% Series due 2015 12 200
6 1/8% Series due 1996 25 701 9.20% Series due 2021 50 000
6.90% Series due 1997 30 000 8.55% Series due 2022 30 000
6 5/8% Series due 1997 25 874 8.82% Series due 2022 12 000
6.70% Series due 1997 20 000 8.85% Series due 2022 38 000
7 1/4% Series due 1998 24 191 8.32% Series due 2022 40 000
6.04% Series due 2000 40 000 7.98% Series due 2023 40 000
9% Series due 2002 50 000 7 1/2% Series due 2023 125 000
6 3/8% Series due 2003 150 000 6 3/4% Series due 2025 150 000
Subtotal 1 276 696
Amount due
within one year (60 000) $1 216 696
Other long-term debt, net (b) 3 076
Unamortized net discount on long-term debt (4 098)
Total long-term debt $1 215 674
<FN>
(a) These amounts do not include $125 million of 10 1/8% First Mortgage Bonds as a result of depositing
with the trustee, in 1993, an amount needed for their early redemption in April 1994.
(b) For the years 1994, 1995, 1996, 1997 and 1998 the Company has long-term debt maturities of
$60.0 million, $47.4 million, $25.7 million, $75.9 million and $24.2 million, respectively.
(c) Substantially all of the utility plant owned by the Company is subject to the lien of its mortgage.
The accompanying notes are an integral part of the financial statements.
F-24
NOTES TO FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was
incorporated under the laws of New Jersey in 1925, is a wholly owned
subsidiary of General Public Utilities Corporation (GPU), a holding company
registered under the Public Utility Holding Company Act of 1935. The Company
is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania
Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to
herein as the "Company and its affiliates." The Company is also associated
with GPU Service Corporation (GPUSC), a service company; GPU Nuclear
Corporation (GPUN), which operates and maintains the nuclear units of the
Company and its affiliates; and General Portfolios Corporation (GPC), parent
of Energy Initiatives, Inc., which develops, owns and operates nonutility
generating facilities. All of the Company's affiliates are wholly owned
subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN and GPC are
referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in three major nuclear projects -- Three
Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational
generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged
during a 1979 accident. At December 31, 1993, the Company's net investment in
TMI-1 and Oyster Creek, including nuclear fuel, was $173 million and
$784 million, respectively. TMI-1 and TMI-2 are jointly owned by the Company,
Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively.
Oyster Creek is owned by the Company.
Costs associated with the operation, maintenance and retirement of
nuclear plants have continued to increase and become less predictable, in
large part due to changing regulatory requirements and safety standards and
experience gained in the construction and operation of nuclear facilities.
The Company and its affiliates may also incur costs and experience reduced
output at their nuclear plants because of the design criteria prevailing at
the time of construction and the age of the plants' systems and equipment. In
addition, for economic or other reasons, operation of these plants for the
full term of their now assumed lives cannot be assured. Also, not all risks
associated with ownership or operation of nuclear facilities may be adequately
insured or insurable. Consequently, the ability of electric utilities to
obtain adequate and timely recovery of costs associated with nuclear projects,
including replacement power, any unamortized investment at the end of the
plants' useful life (whether scheduled or premature), the carrying costs of
that investment and retirement costs, is not assured. Management intends, in
general, to seek recovery of any such costs described above through the
ratemaking process, but recognizes that recovery is not assured.
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990. After receiving Nuclear Regulatory
Commission (NRC) approval, TMI-2 entered into long-term monitored storage in
December 1993.
F-25
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the U. S.
District Court for the Middle District of Pennsylvania. Some of the claims
also seek recovery for injuries from alleged emissions of radioactivity before
and after the accident. Questions have not yet been resolved as to whether
the punitive damage claims are (a) subject to the overall limitation of
liability set by the Price-Anderson Act ($560 million at the time of the
accident) and (b) outside the primary insurance coverage provided pursuant to
that Act (remaining primary coverage of approximately $80 million as of
December 31, 1993). If punitive damages are not covered by insurance or are
not subject to the Price-Anderson liability limitation, punitive damage awards
could have a material adverse effect on the financial position of the Company.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of twelve allegedly representative
cases is scheduled to begin in October 1994. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable Federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. As described in the Nuclear Fuel Disposal Fee
section of Note 2, the disposal of spent nuclear fuel is covered separately by
contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance
with NRC regulations, setting forth a funding plan (employing the external
sinking fund method) for the decommissioning of their nuclear reactors. Under
this plan, the Company and its affiliates intend to complete the funding for
Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014,
respectively. The TMI-2 funding completion date is 2014, consistent with
TMI-2 remaining in long-term storage and being decommissioned at the same time
as TMI-1. Under the NRC regulations, the funding target (in 1993 dollars) for
TMI-1 is $143 million, of which the Company's share is $36 million, and for
Oyster Creek is $175 million. Based on NRC studies, a comparable funding
target for TMI-2 (in 1993 dollars), which takes into account the accident, is
$228 million, of which the Company's share is $57 million. The NRC is
currently studying the levels of these funding targets. Management cannot
predict the effect that the results of this review will have on the funding
targets. NRC regulations and a regulatory guide provide mechanisms, including
exemptions, to adjust the funding targets over their collection periods to
reflect increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not actual cost
estimates, are reference levels designed to assure that licensees demonstrate
F-26
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $205 to $285 million, of which the Company's share is $51
to $71 million, and $220 to $320 million, respectively (adjusted to 1993
dollars). In addition, the studies estimated the cost of removal of
nonradiological structures and materials for TMI-1 and Oyster Creek at
$72 million, of which the Company's share is $18 million, and $47 million,
respectively.
The ultimate cost of retiring the Company and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies and cannot now be more
reasonably estimated than the level of the NRC funding target because such
costs are subject to (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time
of decommissioning. The Company charges to expense and contributes to
external trusts amounts collected from customers for nuclear plant
decommissioning and nonradiological costs. In addition, in 1990 the Company
contributed to an external trust an amount not recoverable from customers for
nuclear plant decommissioning.
TMI-1 and Oyster Creek:
The Company is collecting revenues for decommissioning, which are
expected to result in the accumulation of its share of the NRC funding target
for each plant. The Company is also collecting revenues for the cost of
removal of nonradiological structures and materials at each plant based on its
share ($3.83 million) of an estimated $15.3 million for TMI-1 and
$31.6 million for Oyster Creek. Collections from customers for
decommissioning expenditures are deposited in external trusts and are
classified as Decommissioning Funds on the balance sheet, which includes the
interest earned on these funds. Provision for the future expenditure of these
funds has been made in accumulated depreciation, amounting to $13 million for
TMI-1 and $80 million for Oyster Creek at December 31, 1993.
Management believes that any TMI-1 and Oyster Creek retirement costs, in
excess of those currently recognized for ratemaking purposes, should be
recoverable through the ratemaking process.
TMI-2:
The Company and its affiliates have recorded a liability, amounting to
$229 million, of which the Company's share is $57 million as of December 31,
F-27
1993, for the radiological decommissioning of TMI-2, reflecting the NRC
funding target (unadjusted for an immaterial decrease in 1993). The Company
and its affiliates record escalations, when applicable, in the liability based
upon changes in the NRC funding target. The Company and its affiliates have
also recorded a liability in the amount of $20 million, of which the Company's
share is $5 million, for incremental costs specifically attributable to
monitored storage. Such costs are expected to be incurred between 1994 and
2014, when decommissioning is forecast to begin. In addition, the Company and
its affiliates have recorded a liability in the amount of $71 million, of
which the Company's share is $18 million, for nonradiological cost of removal.
The Company's share of the above amounts for retirement costs and monitored
storage are reflected as Three Mile Island Unit 2 Future Costs on the balance
sheet. The Company has made a nonrecoverable contribution of $15 million to
an external decommissioning trust.
The New Jersey Board of Regulatory Commissioners (NJBRC) has granted the
Company decommissioning revenues for the remainder of the NRC funding target
and allowances for the cost of removal of nonradiological structures and
materials. Management intends to seek recovery for any increases in TMI-2
retirement costs, but recognizes that recovery cannot be assured.
Upon TMI-2's entering long-term monitored storage, the Company and its
affiliates will incur currently estimated incremental annual storage costs of
$1 million, of which the Company's share is $.25 million. The Company and its
affiliates have deferred the $20 million, of which the Company's share is
$5 million, for the total estimated incremental costs attributable to
monitored storage. The Company's share of these costs has been recognized in
rates by the NJBRC.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the Company.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered
one site for insurance purposes) and for Oyster Creek totals $2.7 billion per
site. In accordance with NRC regulations, these insurance policies generally
require that proceeds first be used to stabilize the reactors and then to pay
for decontamination and debris removal expenses. Any remaining amounts
available under the policies may then be used for repair and restoration costs
and decommissioning costs. Consequently, there can be no assurance that, in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of the stations.
The Price-Anderson Act limits the GPU System's liability to third parties
for a nuclear incident at one of its sites to approximately $9.4 billion.
Coverage for the first $200 million of such liability is provided by private
F-28
insurance. The remaining coverage, or secondary protection, is provided by
retrospective premiums payable by all nuclear reactor owners. Under secondary
protection, a nuclear incident at any licensed nuclear power reactor in the
country, including those owned by the GPU System, could result in assessments
of up to $79 million per incident for each of the GPU System's three reactors,
subject to an annual maximum payment of $10 million per incident per reactor.
In 1993, GPUN requested an exemption from the NRC to eliminate the secondary
protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at their
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years at decreasing levels beginning at $1.8 million for
Oyster Creek and $2.6 million for TMI-1, per week.
Under their insurance policies applicable to nuclear operations and
facilities, the Company and its affiliates are subject to retrospective
premium assessments of up to $52 million in any one year, of which the
Company's share is $31 million, in addition to those payable under the
Price-Anderson Act.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including, but
not limited to, acid rain, water quality, air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, the Company may be required to incur substantial additional costs to
construct new equipment, modify or replace existing and proposed equipment,
remediate or clean up waste disposal and other sites currently or formerly
used by it, including formerly owned manufactured gas plants, and with regard
to electromagnetic fields, postpone or cancel the installation of, or replace
or modify, utility plant, the cost of which could be material. Management
intends to seek recovery through the ratemaking process for any additional
costs, but recognizes that recovery cannot be assured.
To comply with the federal Clean Air Act Amendments of 1990, the Company
and its affiliates expect to expend up to $590 million for air pollution
control equipment by the year 2000, of which the Company's share is
approximately $145 million. Costs associated with the capital invested in
this equipment and the increased operating costs of the Company's affected
station should be recoverable through the ratemaking process.
The Company has been notified by the Environmental Protection Agency
(EPA) and a state environmental authority that it is among the potentially
responsible parties (PRPs) who may be jointly and severally liable to pay for
the costs associated with the investigation and remediation at six hazardous
and/or toxic waste sites. In addition, the Company has been requested to
supply information to the EPA and state environmental authorities on several
other sites for which it has not yet been named as a PRP. The ultimate cost
of remediation will depend upon changing circumstances as site investigations
continue, including (a) the existing technology required for site cleanup,
(b) the remedial action plan chosen and (c) the extent of site contamination
and the portion attributed to the Company.
F-29
The Company has entered into agreements with the New Jersey Department of
Environmental Protection and Energy for the investigation and remediation of
17 formerly owned manufactured gas plant sites. One of these sites has been
repurchased by the Company. The Company has also entered into various cost
sharing agreements with other utilities for some of the sites. At December 31,
1993, the Company has an estimated environmental liability of $35 million
recorded on its balance sheet relating to these sites. The estimated
liability is based upon ongoing site investigations and remediation efforts,
including capping the sites and pumping and treatment of ground water. If the
periods over which the remediation is currently expected to be performed are
lengthened, the Company believes that it is reasonably possible that the
ultimate costs may range as high as $60 million. Estimates of these costs are
subject to significant uncertainties as the Company does not presently own or
control most of these sites; the environmental standards have changed in the
past and are subject to future change; the accepted technologies are subject
to further development; and the related costs for these technologies are
uncertain. If the Company is required to utilize different remediation
methods, the costs could be materially in excess of $60 million.
In June 1993, the NJBRC approved a mechanism for the recovery of future
manufactured gas plant remediation costs through the Company's Levelized
Energy Adjustment Clause (LEAC) when expenditures exceed prior collections.
The NJBRC decision provides for interest to be credited to customers until the
overrecovery is eliminated and for future costs to be amortized over seven
years with interest. At December 31, 1993, the Company has collected from
customers $5.2 million in excess of expenditures of $12.8 million. The
Company is currently awaiting a final NJBRC order. The Company is pursuing
reimbursement of the above costs from its insurance carriers, and will seek to
recover costs to the extent not covered by insurance through this mechanism.
The Company is unable to estimate the extent of possible remediation and
associated costs of additional environmental matters. Also unknown are the
consequences of environmental issues, which could cause the postponement or
cancellation of either the installation or replacement of utility plant.
Management believes the costs described above should be recoverable through
the ratemaking process.
OTHER COMMITMENTS AND CONTINGENCIES
The NJBRC has instituted a generic proceeding to address the appropriate
recovery of capacity costs associated with electric utility power purchases
from nonutility generation projects. The proceeding was initiated, in part,
to respond to contentions of the New Jersey Public Advocate, Division of Rate
Counsel (Rate Counsel), that by permitting utilities to recover such costs
through the LEAC, an excess or "double recovery" may result when combined with
the recovery of the utilities' embedded capacity costs through their base
rates. In September 1993, the Company and the other New Jersey electric
utilities filed motions for summary judgment with the NJBRC requesting that
the NJBRC dismiss contentions being made by Rate Counsel that adjustments for
alleged "double recovery" in prior periods are warranted. Rate Counsel has
filed a brief in opposition to the utilities' summary judgment motions
including a statement from its consultant that in his view, the "double
recovery" for the Company for the 1988-92 period would be approximately
F-30
$102 million. Management believes that the position of Rate Counsel is
without merit. This matter is pending before the NJBRC.
The Company's two operating nuclear units are subject to the NJBRC's
annual nuclear performance standard. Operation of these units at an aggregate
annual generating capacity factor below 65% or above 75% would trigger a
charge or credit based on replacement energy costs. At current cost levels,
the maximum annual effect on net income of the performance standard charge at
a 40% capacity factor would be approximately $10 million. While a capacity
factor below 40% would generate no specific monetary charge, it would require
the issue to be brought before the NJBRC for review. The annual measurement
period, which begins in March of each year, coincides with that used for the
LEAC.
In December 1993, the NJBRC denied the Company's request to participate
in the proposed power supply and transmission facilities agreements between
the Company and its affiliates and Duquesne Light Company (Duquesne). As a
result of this action and other developments, the Company and its affiliates
notified Duquesne that they were exercising their rights under the agreements
to withdraw from and thereby terminate the agreements. Consequently, the
Company and its affiliates wrote off the $25 million, of which the Company's
share was $9 million, they had invested in the project.
The Company's construction programs, for which substantial commitments
have been incurred and which extend over several years, contemplate
expenditures of $275 million during 1994. As a consequence of reliability,
licensing, environmental and other requirements, substantial additions to
utility plant may be required relatively late in their expected service lives.
If such additions are made, current depreciation allowance methodology may not
make adequate provision for the recovery of such investments during their
remaining lives. Management intends to seek recovery of any such costs
through the ratemaking process, but recognizes that recovery is not assured.
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of
regulatory commissions, the electric utility industry appears to be moving
toward a combination of competition and a modified regulatory environment. In
accordance with Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (FAS 71), the
Company's financial statements reflect assets and costs based on current cost-
based ratemaking regulations. Continued accounting under FAS 71 requires that
the following criteria be met:
a) A utility's rates for regulated services provided to its customers
are established by, or are subject to approval by, an independent
third-party regulator;
b) The regulated rates are designed to recover specific costs of
providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of
competition, direct and indirect, it is reasonable to assume that
rates set at levels that will recover a utility's costs can be
charged to and collected from customers. This criteria requires
consideration of anticipated changes in levels of demand or
competition during the recovery period for any capitalized costs.
F-31
A utility's operations can cease to meet those criteria for various
reasons, including deregulation, a change in the method of regulation, or a
change in the competitive environment for the utility's regulated services.
Regardless of the reason, a utility whose operations cease to meet those
criteria should discontinue application of FAS 71 and report that
discontinuation by eliminating from its balance sheet the effects of certain
actions of regulators that had been recognized as assets and liabilities
pursuant to FAS 71 but which would not have been recognized as assets and
liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and
meets the above criteria, FAS 71 accounting may only be applied to that
portion. Write-offs of utility plant and regulatory assets may result for
those operations that no longer meet the requirements of FAS 71. In addition,
under deregulation, the uneconomical costs of certain contractual commitments
for purchased power and/or fuel supplies may have to be expensed. Management
believes that to the extent that the Company no longer qualifies for FAS 71
accounting treatment, a material adverse effect on its results of operations
and financial position may result.
The Company has entered into a long-term contract with a nonaffiliated
mining company for the purchase of coal for the Keystone generating station of
which the Company owns a one-sixth undivided interest. This contract, which
expires in 2004, requires the purchase of minimum amounts of the station's
coal requirements. The price of the coal is determined by a formula providing
for the recovery by the mining company of its costs of production. The
Company's share of the cost of coal purchased under this agreement is expected
to aggregate $21 million for 1994.
The Company and its affiliates have entered into agreements with other
utilities for the purchase of capacity and energy for various periods through
1999. These agreements provide for up to 2130 MW in 1994, declining to
1307 MW by 1995 and 183 MW by 1999. Payments pursuant to these agreements are
estimated to aggregate $244 million in 1994. The price of the energy
purchased under these agreements is determined by contracts providing
generally for the recovery by the sellers of their costs.
The Company has also entered into power purchase agreements with
independently owned power production facilities (nonutility generators) for
the purchase of energy and capacity for periods up to 25 years. The majority
of these agreements are subject to penalties for nonperformance and other
contract limitations. While a few of these facilities are dispatchable, most
are must-run and generally obligate the Company to purchase all of the power
produced up to the contract limits. The agreements have been approved by the
NJBRC and permit the Company to recover energy and demand costs from customers
through its energy clause. These agreements provide for the sale of
approximately 1,194 MW of capacity and energy to the Company by the mid-to-
late 1990s. As of December 31, 1993, facilities covered by these agreements
having 661 MW of capacity were in service, and 215 MW were scheduled to
commence operation in 1994. Payments made pursuant to these agreements were
$292 million, $316 million and $216 million for 1993, 1992 and 1991,
F-32
respectively, and are estimated to aggregate $325 million for 1994. The price
of the energy and capacity to be purchased under these agreements is
determined by the terms of the contracts. The rates payable under a number of
these agreements are substantially in excess of current market prices. While
the Company has been granted full recovery of these costs from customers by
the NJBRC, there can be no assurance that the Company will continue to be able
to recover these costs throughout the terms of the related contracts. The
emerging competitive market has created additional uncertainty regarding the
forecasting of the GPU System's energy supply needs which, in turn, has caused
the Company and its affiliates to change their supply strategy to seek shorter
term agreements offering more flexibility. At the same time, the Company and
its affiliates are attempting to renegotiate, and in some cases buy out, high
cost long-term nonutility generation contracts where opportunities arise. The
extent to which the Company and its affiliates may be able to do so, however,
or recover associated costs through rates, is uncertain. Moreover, these
efforts have led to disputes before the NJBRC, as well as to litigation, and
may result in claims against the Company for substantial damages. There can
be no assurance as to the outcome of these matters.
During the normal course of the operation of its business, in addition to
the matters described above, the Company is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by customers, contractors,
vendors and other suppliers of equipment and services and by both current and
former employees alleging unlawful employment practices. It is not expected
that the outcome of these matters will have a material effect on the Company's
financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The Company's accounting records are maintained in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission and adopted by the NJBRC. Certain reclassifications of prior
years' data have been made to conform with current presentation.
REVENUES
The Company recognizes electric operating revenues for services rendered
and, beginning in 1991, an estimate of unbilled revenues to record services
provided to the end of the respective accounting period.
F-33
DEFERRED ENERGY COSTS
Energy costs are recognized in the period in which the related energy
clause revenues are billed.
UTILITY PLANT
It is the policy of the Company to record additions to utility plant
(material, labor, overhead and an allowance for funds used during
construction) at cost. The cost of current repairs and minor replacements is
charged to appropriate operating and maintenance expense and clearing
accounts, and the cost of renewals is capitalized. The original cost of
utility plant retired or otherwise disposed of is charged to accumulated
depreciation.
DEPRECIATION
The Company provides for depreciation at annual rates determined and
revised periodically, on the basis of studies, to be sufficient to depreciate
the original cost of depreciable property over estimated remaining service
lives, which are generally longer than those employed for tax purposes. The
Company used depreciation rates that, on an aggregate composite basis,
resulted in annual rates of 3.59%, 3.51% and 3.51% for the years 1993, 1992
and 1991, respectively.
ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION (AFUDC)
The Uniform System of Accounts defines AFUDC as "the net cost for the
period of construction of borrowed funds used for construction purposes and a
reasonable rate on other funds when so used." AFUDC is recorded as a charge
to construction work in progress, and the equivalent credits are to interest
charges for the pretax cost of borrowed funds and to other income for the
allowance for other funds. While AFUDC results in an increase in utility
plant and represents current earnings, it is realized in cash through
depreciation or amortization allowances only when the related plant is
recognized in rates. On an aggregate composite basis, the annual rates
utilized were 7.80%, 8.19% and 8.64% for the years 1993, 1992 and 1991,
respectively.
AMORTIZATION POLICIES
Accounting for TMI-2 and Forked River Investments:
The Company is collecting annual revenues for the amortization of TMI-2
of $9.6 million. This level of revenue will be sufficient to recover the
remaining investment by the year 2008. At December 31, 1993, $97 million is
included in Unamortized property losses on the balance sheet for the Forked
River project. The Company is collecting annual revenues for the amortization
of this project of $11.2 million, which will be sufficient to recover its
remaining investment by the year 2006. Because the Company has not been
provided revenues for a return on the unamortized balances of its share of the
damaged TMI-2 facility and the cancelled Forked River project, these
F-34
investments are being carried at their discounted present values. The related
annual accretion, which represents the carrying charges that are accrued as
the asset is written up from its discounted value, is recorded in Other
income, net.
Nuclear Fuel:
Nuclear fuel is amortized on a unit of production basis. Rates are
determined and periodically revised to amortize the cost over the useful life.
The Company has provided for future contributions to the Decontamination
and Decommissioning Fund (part of the Energy Act) for the cleanup of
enrichment plants operated by the federal government. The total liability at
December 31, 1993 amounted to $29 million, and is primarily reflected in
Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants
will contribute a total of $150 million annually, based on an assessment
computed on prior enrichment purchases, over a 15-year period up to a total of
$2.3 billion (in 1993 dollars). The Company made its initial payment to this
fund in 1993. The Company has recorded an asset for remaining amounts
recoverable from ratepayers of $28 million at December 31, 1993 in Deferred
Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS
The Company accrues incremental nuclear outage maintenance costs
anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE
The Company is providing for estimated future disposal costs for spent
nuclear fuel at Oyster Creek and TMI-1 in accordance with the Nuclear Waste
Policy Act of 1982. The Company entered into contracts in 1983 with the DOE
for the disposal of spent nuclear fuel. The total liability under these
contracts, including interest, at December 31, 1993, all of which relates to
spent nuclear fuel from nuclear generation through April 1983, amounted to
$110 million, and is reflected in Deferred Credits and Other Liabilities -
Other. As the actual liability is substantially in excess of the amount
recovered to date from ratepayers, the Company has reflected such excess of
$25 million at December 31, 1993 in Deferred Debits and Other Assets - Other.
The rates currently charged to customers provide for the collection of these
costs, plus interest, over a remaining period of 13 years.
The Company is collecting 1 mill per kilowatt-hour from its customers for
spent nuclear fuel disposal costs resulting from nuclear generation subsequent
to April 1983. These amounts are remitted quarterly to the DOE.
F-35
INCOME TAXES
The GPU System files a consolidated federal income tax return, and all
participants are jointly and severally liable for the full amount of any tax,
including penalties and interest, that may be assessed against the group.
Each subsidiary is allocated the tax reduction attributable to GPU expenses,
in proportion to the average common stock equity investment of GPU in such
subsidiary, during the year. In addition, each subsidiary will receive in
current cash payments the benefit of its own net operating loss carrybacks to
the extent that the other subsidiaries can utilize such net operating loss
carrybacks to offset the tax liability they would otherwise have on a separate
return basis (after taking into account any investment tax credits they could
utilize on a separate return basis). This method of allocation does not allow
any subsidiary to pay more than its separate return liability.
Deferred income taxes, which result primarily from New Jersey unit tax,
liberalized depreciation methods, deferred energy costs, discounted Forked
River and TMI-2 investments, and unbilled revenues, are provided for
differences between book and taxable income. Investment tax credits (ITC) are
amortized over the estimated service lives of the related facilities.
Effective January 1, 1993, the Company implemented Statement of Financial
Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes," which
requires the use of the liability method of financial accounting and reporting
for income taxes. Under FAS 109, deferred income taxes reflect the impact of
temporary differences between the amount of assets and liabilities recognized
for financial reporting purposes and the amounts recognized for tax purposes.
STATEMENTS OF CASH FLOWS
For the purpose of the statements of cash flows, temporary investments
include all unrestricted liquid assets, such as cash deposits and debt
securities, with maturities generally of three months or less.
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1993, the Company had no short-term notes outstanding
issued under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $398 million of credit
facilities, which includes a Revolving Credit Agreement (Credit Agreement)
with a consortium of banks that permits total borrowing of $150 million
outstanding at any one time. The credit facilities generally provide for the
payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually.
Borrowings under these credit facilities generally bear interest based on the
prime rate or money market rates. Notes issued under the Credit Agreement,
which expires April 1, 1995, are subject to various covenants and acceleration
under certain conditions.
F-36
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
December 31, 1993 and 1992, are as follows:
(In Millions)
Carrying Fair
Amount Value
December 31, 1993:
Cumulative preferred stock
with mandatory redemption $ 150 $ 161
Long-term debt 1 216 1 276
December 31, 1992:
Cumulative preferred stock
with mandatory redemption 150 148
Long-term debt 1 117 1 158
The fair values of the Company's cumulative preferred stock with
mandatory redemption provisions and long-term debt are estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to the Company for instruments of the same remaining maturities.
5. INCOME TAXES
Effective January 1, 1993, the Company implemented FAS 109 "Accounting
for Income Taxes". In 1993, the cumulative effect on net income of this
accounting change was immaterial. Also in 1993, the federal income tax rate
changed from 34% to 35%, retroactive to January 1, 1993, resulting in an
increase in the deferred tax assets of $5 million and an increase in the
deferred tax liabilities of $20 million. The tax rate change did not have a
material effect on net income as the changes in deferred taxes were
substantially offset by the recording of regulatory assets and liabilities.
The balance sheet effect as of December 31, 1993 of implementing FAS 109
resulted in a regulatory asset for income taxes recoverable through future
rates of $122 million (related to liberalized depreciation), and a regulatory
liability for income taxes refundable through future rates of $43 million
(related to unamortized ITC), substantially due to the recognition of amounts
not previously recorded.
F-37
A summary of the components of deferred taxes as of December 31, 1993
follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
Current: Noncurrent:
New Jersey unit tax $ 12 Liberalized
Unbilled revenue 9 depreciation:
Deferred energy 8 previously flowed
Total $ 29 through $80
future revenue
requirements 42 $122
Noncurrent:
Unamortized ITC $ 43
Decommissioning 19 Liberalized
Contribution in aid depreciation 364
of construction 17 Forked River 30
Other 32 Other 54
Total $111 Total $570
The reconciliations from net income to book income subject to tax and
from the federal statutory rate to combined federal and state effective tax
rates are as follows:
(In Millions)
1993 1992 1991
Net income $158 $117 $153
Income tax expense 81 52 73
Book income subject to tax $239 $169 $226
Federal statutory rate 35% 34% 34%
Effect of difference between tax
and book depreciation for which
deferred taxes were not provided 2 2 2
Amortization of ITC (3) (4) (3)
Other - (1) (1)
Effective income tax rate 34% 31% 32%
F-38
Federal and state income tax expense is comprised of the following:
(In Millions)
1993 1992 1991
Provisions for taxes currently payable $42 $37 $56
Deferred income taxes:
Liberalized depreciation 19 24 23
Gain/loss on reacquired debt 9 4 -
Deferral of energy costs (8) - 2
Abandonment loss - Forked River (4) (4) (4)
Nuclear outage maintenance costs - (3) 5
Accretion income 6 6 7
Unbilled revenues 5 (2) 8
Information system costs capitalized - 6 -
New Jersey unit tax 32 3 (7)
Other (14) (12) (10)
Deferred income taxes, net 45 22 24
Amortization of ITC (6) (7) (7)
Income tax expense $81 $52 $73
The Internal Revenue Service (IRS) has completed its examinations of the
GPU System's federal income tax returns through 1986. The GPU System and the
IRS have reached an agreement to settle the GPU System's claim that TMI-2 has
been retired for tax purposes. When approved by the Joint Congressional
Committee on Taxation, this settlement will provide refunds for previously
paid taxes. The GPU System estimates that the Company and its affiliates
would receive net refunds totaling $17 million, of which the Company's share
is approximately $4 million, which would be credited to the Company's
customers. The Company and its affiliates would also be entitled to receive
net interest estimated to total $45 million (before income taxes), of which
the Company's share is approximately $11 million, through December 31, 1993,
which the Company would credit to income. The years 1987, 1988 and 1989 are
currently under audit.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses
consisted of the following:
(In Millions)
1993 1992 1991
Maintenance $135 $125 $117
Other taxes:
New Jersey unit tax $202 $197 $201
Real estate and personal property 6 7 7
Other 21 12 12
Total $229 $216 $220
F-39
For the years 1993, 1992 and 1991, the cost to the Company of services
rendered to it by GPUSC amounted to approximately $39 million, $37 million and
$36 million, respectively, of which approximately $29 million, $28 million and
$27 million, respectively, was charged to income. For the years 1993, 1992
and 1991, the cost to the Company of services rendered to it by GPUN amounted
to approximately $227 million, $247 million and $274 million, respectively, of
which approximately $184 million, $170 million and $181 million, respectively,
was charged to income. For the years 1993, 1992 and 1991, the Company
purchased $23 million, $22 million and $21 million, respectively, in energy
from a cogeneration project in which an affiliate has a 50 percent partnership
interest.
7. EMPLOYMENT BENEFITS
Pension Plans:
The Company maintains defined benefit pension plans covering
substantially all employees. The Company's policy is to currently fund net
pension costs within the deduction limits permitted by the Internal Revenue
Code.
A summary of the components of net periodic pension cost follows:
(In Millions)
1993 1992 1991
Service cost-benefits earned during
the period $ 8.7 $ 8.1 $ 8.1
Interest cost on projected benefit
obligation 29.4 27.6 25.7
Expected return on plan assets (32.1) (29.1) (27.9)
Amortization (.4) (.6) (.6)
Net periodic pension cost $ 5.6 $ 6.0 $ 5.3
The actual returns on the plans' assets for the years 1993, 1992 and 1991
were gains of $48.0 million, $17.5 million and $62.7 million, respectively.
F-40
The funded status of the plans and related assumptions at December 31,
1993 and 1992 were as follows:
(In Millions)
1993 1992
Accumulated benefit obligation (ABO):
Vested benefits $ 310.7 $ 260.3
Nonvested benefits 36.2 28.2
Total ABO 346.9 288.5
Effect of future compensation levels 61.8 65.1
Projected benefit obligation (PBO) $ 408.7 $ 353.6
PBO $(408.7) $(353.6)
Plan assets at fair value 425.2 384.6
PBO less than plan assets 16.5 31.0
Unrecognized net gain (10.1) (28.6)
Unrecognized prior service cost 4.0 4.1
Unrecognized net transition asset (4.3) (4.8)
Prepaid pension costs $ 6.1 $ 1.7
Principal actuarial assumptions(%):
Annual long-term rate of return
on plan assets 8.5 8.5
Discount rate 7.5 8.5
Annual increase in compensation levels 5.0 6.0
Changes in assumptions in 1993 primarily due to reducing the discount
rate assumption from 8.5% to 7.5% resulted in a $36 million change in the PBO
as of December 31, 1993. The assets of the plans are held in a Master Trust
and generally invested in common stocks, fixed income securities and real
estate equity investments. The unrecognized net gain represents actual
experience different from that assumed, which is deferred and not included in
the determination of pension cost until it exceeds certain levels. The
unrecognized prior service cost resulting from retroactive changes in benefits
is being amortized as a charge to pension cost, while the unrecognized net
transition asset arising out of the adoption of Statement of Financial
Accounting Standards No. 87 is being amortized as a credit to pension cost
over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees.
These plans provide for employee contributions up to specified limits. The
Company's savings plans provide for various levels of matching contributions.
The matching contributions for the Company for 1993, 1992 and 1991 were
$2.4 million, $2.1 million and $1.4 million, respectively.
Postretirement Benefits Other than Pensions:
The Company provides certain retiree health care and life insurance
benefits for substantially all employees who reach retirement age while
working for the Company. Health care benefits are administered by various
organizations. A portion of the costs are borne by the participants. For
1992 and 1991, the annual premium costs associated with providing these
benefits totaled approximately $4.5 million and $4.4 million, respectively.
F-41
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 (FAS 106), "Employers' Accounting for
Postretirement Benefits Other Than Pensions." FAS 106 requires that the
estimated cost of these benefits, which are primarily for health care, be
accrued during the employee's active working career. The Company has elected
to amortize the unfunded transition obligation existing at January 1, 1993,
over a period of 20 years.
A summary of the components of the net periodic postretirement benefit
cost for 1993 follows:
(In Millions)
Service cost-benefits attributed to service
during the period $ 3.4
Interest cost on the accumulated postretirement
benefit obligation 10.4
Expected return on plan assets (.7)
Amortization of transition obligation 5.7
Net periodic postretirement benefit cost 18.8
Deferred for future recovery (9.6)
Postretirement benefit cost, net of deferrals $ 9.2
The actual return on the plans' assets for the year 1993 was a gain of
$.9 million. The funded status of the plans at December 31, 1993, was as
follows:
Accumulated Postretirement Benefit Obligation (APBO):
Retirees $ 52.7
Fully eligible active plan participants 28.8
Other active plan participants 58.2
Total accumulated postretirement benefit obligation $ 139.7
APBO $(139.7)
Plan assets at fair value 10.3
APBO in excess of plan assets (129.4)
Unrecognized net loss 7.5
Unrecognized transition obligation 108.3
Accrued postretirement benefit liability $ (13.6)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5
Discount rate 7.5
The Company intends to continue funding amounts for postretirement
benefits collected from customers and other amounts with an independent
trustee, as deemed appropriate from time to time. The plan assets include
equities and fixed income securities.
F-42
In the Company's most recent base rate proceeding, the NJBRC allowed the
Company to collect $3 million annually of the incremental postretirement
benefit costs, charged to expense, recognized as a result of FAS 106. Based
on the final order and in accordance with Emerging Issues Task Force Issue
Number 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," the
Company is deferring the amounts above that level. A portion of the increase
in annual costs recognized under FAS 106 of approximately $9.6 million is
being deferred and should be recoverable through the ratemaking process.
The accumulated postretirement benefits obligation was determined by
application of the terms of the medical and life insurance plans, including
the effects of established maximums on covered costs, together with relevant
actuarial assumptions and health-care cost trend rates of 14% for those not
eligible for Medicare and 11% for those eligible for Medicare for 1994,
decreasing gradually to 7% in 2000 and thereafter. These costs also reflect
the implementation of a cost cap of 6% for individuals who retire after
December 1, 1995. The effect of a 1% annual increase in these assumed cost
trend rates would increase the accumulated postretirement benefit obligation
by approximately $14 million and the aggregate of the service and interest
cost components of net postretirement health-care cost for 1994 by
approximately $1 million.
Postemployment Benefits:
In November 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 112, "Employers' Accounting
for Postemployment Benefits" (FAS 112) which addresses accounting by employers
who provide benefits to former or inactive employees after employment but
before retirement, which is effective for fiscal years beginning after
December 15, 1993. The Company adopted the accrual method required under FAS
112 during 1993, which did not have a material impact on the financial
position or results of operations of the Company.
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the
investment and charges its share of operating expenses to the appropriate
expense accounts. The Company participated with affiliated and nonaffiliated
utilities in the following jointly owned stations at December 31, 1993:
Balance (In Millions)
% Accumulated
Station Ownership Investment Depreciation
Three Mile Island 25 $207.2 $57.5
Keystone 16.67 77.9 20.8
Yards Creek 50 24.3 6.3
F-43
9. LEASES
The Company's capital leases consist primarily of leases for nuclear
fuel. Nuclear fuel capital leases at December 31, 1993 and 1992 totaled
$86 million and $105 million, respectively (net of amortization of
$137 million and $108 million, respectively). The recording of capital leases
has no effect on net income because all leases, for ratemaking purposes, are
considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with
nonaffiliated fuel trusts. An aggregate of up to $250 million ($125 million
each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at
any one time. It is contemplated that when consumed, portions of the
currently leased material will be replaced by additional leased material. The
Company and its affiliates are responsible for the disposal costs of nuclear
fuel leased under these agreements. These nuclear fuel leases are renewable
annually. Lease expense consists of an amount designed to amortize the cost
of the nuclear fuel as consumed plus interest costs. For the years ended
December 31, 1993, 1992 and 1991 these amounts were $34 million, $36 million
and $29 million, respectively. The leases may be terminated at any time with
at least five months notice by either party prior to the end of the current
period. Subject to certain conditions of termination, the Company and its
affiliates are required to purchase all nuclear fuel then under lease at a
price that will allow the lessor to recover its net investment.
The Company has sold and leased back substantially all of its ownership
interest in the Merrill Creek Reservoir project. The minimum lease payments
under this operating lease, which has a remaining term of 39 years, average
approximately $3 million annually.
F-44
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
(In Thousands)
For the Years Ended
December 31,
1991 1992(a) 1993
Column A Column F
Classification Balance at end of period
Utility Plant (at original cost):
Electric:
Plant in service:
Intangibles $ 13 070 $ 20 013 $ 23 502
Production:
Steam 194 468 199 034 202 547
Nuclear 971 618 992 215 1 108 692
Pumped Storage 19 926 19 930 19 940
Combustion 253 889 259 616 259 402
Total Production 1 439 901 1 470 795 1 590 581
Transmission 561 141 591 786 604 961
Distribution 1 361 949 1 447 543 1 542 272
General 151 769 162 181 177 384
Construction work in progress 146 992 178 902 102 178
Held for future use 15 510 15 517 15 685
Total Electric Utility Plant 3 690 332 3 886 737 4 056 563
Nuclear fuel, at original cost 2 456 2 814 4 503
Property under capital leases, net 111 496 111 976 96 597
Total Utility Plant 3 804 284 4 001 527 4 157 663
Other physical property, at original cost 937 818 818
Total Property, Plant and Equipment $3 805 221 $4 002 345 $4 158 481
The information required by Columns B, C, D and E are omitted since neither the total
additions nor the total deductions during the period amount to more than 10% of the closing
balance of total property, plant and equipment.
Total Total Total
Column C, Additions, at cost.... $ 240 009 $ 226 079 $ 203 217
Column D, Retirements........... $ 20 500 $ 35 565 $ 26 271
Column E, Other Changes......... $ (5 418)(b)$ 6 610(c) $ (20 810)(d)
F-45
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (continued)
(In Thousands)
<FN>
See Note 2 to Financial Statements contained in Item 8 for information
concerning the cost of property, plant and equipment and the depreciation and
amortization methods used during the three years ended December 31, 1993.
Also, see Note 9 to Financial Statements contained in Item 8 for information
concerning capital lease agreements.
(a) Reflects a reclassification of $26,925 of nuclear fuel costs
associated with decontamination of the government's enrichment plants
to Deferred Debits and Other Assets - Other to conform with current
presentation.
(b) Includes a reduction in property under capital leases of $7,502,
which is comprised of additions and amortization of $18,839 and
$26,341, respectively.
(c) Includes an increase in property under capital leases of $480, which
is comprised of additions and amortization of $35,617 and $35,137,
respectively.
(d) Includes a reduction in property under capital leases of $15,379,
which is comprised of additions and amortization of $18,919 and
$34,298, respectively, and a decrease of $6,160 due to the write-off
of prior years' expenditures related to the Duquesne project.
F-46
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
for the Year Ended December 31, 1991
(In Thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions
at Charged to Other Balance
Beginning Costs and Changes- at End
Description of Period Expenses Retirements Add(Deduct) of Period
ACCUMULATED DEPRECIATION
AND AMORTIZATION OF
UTILITY PLANT $1 059 829 $134 155(a) $ 34 825(b)$ 2 684(c) $1 161 843
ACCUMULATED DEPRECIATION
OF OTHER PHYSICAL PROPERTY $ 57 $ 6 $ - $ - $ 63
<FN>
(a) Reconciliation to depreciation and amortization expense in statement of income:
Total additions charged to depreciation $134 155
Amortization of property losses 22 131
Decommissioning expense 3 046
Other 415
Total $159 747
(b) Includes net cost of removal.
(c) Other Changes:
Decommissioning trust funding$ 2 448
Charged to clearing accounts 645
Adjustment to reserve (573)
Amortization of leasehold improvements 354
Decommissioning expenditures - Saxton (190)
Total $ 2 684
F-47
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
for the Year Ended December 31, 1992
(In Thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions
at Charged to Other Balance
Beginning Costs and Changes- at End
Description of Period Expenses Retirements Add(Deduct) of Period
ACCUMULATED DEPRECIATION
AND AMORTIZATION OF
UTILITY PLANT $1 161 843 $141 295(a) $ 45 304(b) $ 4 728(c) $1 262 562
ACCUMULATED DEPRECIATION
OF OTHER PHYSICAL PROPERTY $ 63 $ 9 $ - $ - $ 72
<FN>
(a) Reconciliation to depreciation and amortization expense in statement of income:
Total additions charged to depreciation $141 295
Amortization of property losses 22 061
Decommissioning expense 3 240
Other 426
Total $167 022
(b) Includes net cost of removal.
(c) Other Changes:
Decommissioning trust funding$ 3 147
Charged to clearing accounts 747
Adjustment to reserve 792
Amortization of leasehold improvements 355
Decommissioning expenditures - Saxton (313)
Total $ 4 728
F-48
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
for the Year Ended December 31, 1993
(In Thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions
at Charged to Other Balance
Beginning Costs and Changes- at End
Description of Period Expenses Retirements Add(Deduct) of Period
ACCUMULATED DEPRECIATION
AND AMORTIZATION OF
UTILITY PLANT $1 262 562 $152 217(a) $39 260(b) $ 5 021(c) $1 380 540
ACCUMULATED AMORTIZATION
OF NUCLEAR FUEL $ - $ 34 $ - $ - $ 34
ACCUMULATED DEPRECIATION
OF OTHER PHYSICAL PROPERTY $ 72 $ 10 $ - $ - $ 82
<FN>
(a) Reconciliation to depreciation and amortization expense in statement of income:
Total additions charged to depreciation $152 217
Amortization of property losses 22 639
Decommissioning expense 3 224
Amortization of unit tax carrying costs 6 070
Other (1 205)
Total $182 945
(b) Includes net cost of removal.
(c) Other Changes:
Decommissioning trust funding $ 3 864
Charged to clearing accounts 793
Adjustment to reserve 9
Amortization of leasehold improvements 355
Total $ 5 021
F-49
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
Column A Column B Column C Column D Column E
Additions
Balance (1) (2)
at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Period Expenses Accounts Deductions of Period
Year Ended December 31, 1993
Allowance for Doubtful
Accounts $1 320 $5 274 $1 748(a) $7 199(b) $1 143
Allowance for Inventory
Obsolescence 857 - 32(c) 889(d) -
Year Ended December 31, 1992
Allowance for Doubtful
Accounts 918 5 745 1 720(a) 7 063(b) 1 320
Allowance for Inventory
Obsolescence 2 220 - 163(c) 1 526(d) 857
Year Ended December 31, 1991
Allowance for Doubtful
Accounts 852 5 797 1 180(a) 6 911(b) 918
Allowance for Inventory
Obsolescence 4 220 98 83(c) 2 181(d) 2 220
<FN>
(a) Recovery of accounts previously written off.
(b) Accounts receivable written off.
(c) Sale of inventory previously written off.
(d) Inventory written off.
F-50
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
(In Thousands)
Column A Column B Column C Column D Column E Column F
Maximum Average Weighted
Balance Weighted Amount Amount Average
at End Average Outstanding Outstanding Interest
Category of Aggregate of Interest During the During the Rate During
Short-Term Borrowings(a) Period Rate(d) Period(b) Period(c) the Period(d)
Year ended December 31, 1993
Notes payable to banks - - $78 400 $27 457 3.3%
Commercial paper - - 59 751 16 760 3.4
Year ended December 31, 1992
Notes payable to banks $ 5 700 3.3% 57 300 30 400 4.1
Commercial paper - - 99 343 34 722 4.4
Year Ended December 31, 1991
Notes payable to banks 11 800 4.8 64 800 41 458 6.4
Commercial paper 31 828 5.1 86 716 46 683 6.5
<FN>
(a) See Note 3 to Financial Statements contained in Item 8.
(b) Maximum amount outstanding at any month-end.
(c) Computed by dividing the total of the daily outstanding balances for the year by the
number of days in the year.
(d) Column C is computed by dividing the annualized interest expense on the year-end balance
by the outstanding year-end balance. Column F is computed by dividing total interest
expense for the year by the average daily balance outstanding. Rate excludes the
commitment fees on the Revolving Credit Agreement, which were $107,000, $101,000 and
$115,000 for the years 1993, 1992 and 1991, respectively. Rate also excludes the
commitment fees on bank lines of credit, which were $108,000, $151,000 and $119,000 for
the years 1993, 1992 and 1991, respectively.
F-51