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, 1994
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-6047 General Public Utilities Corporation 13-5516989
(a Pennsylvania corporation)
100 Interpace Parkway
Parsippany, New Jersey 07054-1149
Telephone (201) 263-6500
1-3141 Jersey Central Power & Light Company 21-0485010
(a New Jersey corporation)
300 Madison Avenue
Morristown, New Jersey 07962-1911
Telephone (201) 455-8200
1-446 Metropolitan Edison Company 23-0870160
(a Pennsylvania corporation)
2800 Pottsville Pike
Reading, Pennsylvania 19605
Telephone (610) 929-3601
1-3522 Pennsylvania Electric Company 25-0718085
(a Pennsylvania corporation)
2800 Pottsville Pike
Reading, Pennsylvania 19605
Telephone (610) 929-3601
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Registrant Title of each class which registered
General Public Utilities Common Stock, par value
Corporation $2.50 per share New York Stock Exchange
Jersey Central Power & Cumulative Preferred
Company Stock, no par value
$100 stated value:
4% Series New York Stock Exchange
7.88% Series E New York Stock Exchange
First Mortgage Bonds:
7 1/8% Series due 2004 New York Stock Exchange
6 3/8% Series due 2003 New York Stock Exchange
7 1/2% Series due 2023 New York Stock Exchange
6 3/4% Series due 2025 New York Stock Exchange
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Name of each exchange
Registrant Title of each class which registered
Metropolitan Edison Cumulative Preferred
Company Stock, no par value
$100 stated value:
3.90% Series New York Stock Exchange
Note (a) Monthly Income Preferred
Securities, 9% Series A,
$25 stated value New York Stock Exchange
Pennsylvania Electric Cumulative Preferred
Company Stock, no par value
$100 stated value:
4.40% Series B Philadelphia Stock
Exchange
3.70% Series C Philadelphia Stock
Exchange
4.05% Series D Philadelphia Stock
Exchange
4.70% Series E Philadelphia Stock
Exchange
4.50% Series F Philadelphia Stock
Exchange
4.60% Series G Philadelphia Stock
Exchange
Note (b) Monthly Income Preferred
Securities, 8 3/4%
Series A, $25 stated
value New York Stock Exchange
(a) Issued by Met-Ed Capital, L.P., and unconditionally guaranteed by
Metropolitan Edison Company.
(b) Issued by Penelec Capital, L.P., and unconditionally guaranteed by
Pennsylvania Electric Company.
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether each 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 each 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]
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The aggregate market value of the registrants' voting stock held by
non-affiliates as of February 28, 1995 was:
Registrant Amount
General Public Utilities Corporation $3,483,968,881
The number of shares outstanding of each of the registrants' classes of
voting stock as of February 28, 1995 was as follows:
Shares
Registrant Title Outstanding
General Public Utilities Corporation Common Stock, $2.50 par value 115,260,671
Jersey Central Power & Light Company Common Stock, $10 par value 15,371,270
Metropolitan Edison Company Common Stock, no par value 859,500
Pennsylvania Electric Company Common Stock, $20 par value 5,290,596
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement for 1995 Annual Meeting of Stockholders of General Public
Utilities Corporation (Part III)
_____________________________________________________________________________
This combined Form 10-K is separately filed by General Public Utilities
Corporation, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating to
any individual company is filed by such company on its own behalf. Each
registrant makes no representation as to information relating to the other
registrants.
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TABLE OF CONTENTS
Page
Number
Part I
Item 1. Business 1
Item 2. Properties 36
Item 3. Legal Proceedings 39
Item 4. Submission of Matters to a Vote of Security Holders 39
Part II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 40
Item 6. Selected Financial Data 40
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 41
Item 8. Financial Statements and Supplementary Data 41
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 41
Part III
Item 10. Directors and Executive Officers of the Registrant 42
Item 11. Executive Compensation 47
Item 12. Security Ownership of Certain Beneficial Owners
and Management 52
Item 13. Certain Relationships and Related Transactions 53
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 54
Signatures 56
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PART I
ITEM 1. BUSINESS.
General Public Utilities Corporation (GPU or the Corporation), a
Pennsylvania corporation, organized in 1946, is a holding company registered
under the Public Utility Holding Company Act of 1935 (1935 Act). GPU does not
operate any utility properties directly, but owns all of the outstanding
common stock of three electric utilities serving customers in New Jersey -
Jersey Central Power & Light Company (JCP&L), incorporated under the laws of
New Jersey in 1925, - and in Pennsylvania - Metropolitan Edison Company
(Met-Ed), a Pennsylvania corporation incorporated in 1922, and Pennsylvania
Electric Company (Penelec), a Pennsylvania corporation incorporated in 1919.
The business of these subsidiaries (the Subsidiaries) consists predominantly
of the generation, transmission, distribution and sale of electricity. GPU
also owns all of the common stock of GPU Service Corporation (GPUSC), a
service company; GPU Nuclear Corporation (GPUN), which operates and maintains
the nuclear units of the Subsidiaries; and Energy Initiatives, Inc. (EI) and
EI Power, Inc., which develop, own and operate nonutility generating
facilities. Wholly owned subsidiaries of Met-Ed and Penelec are listed in
Exhibit 21. The Subsidiaries own all of the common stock of the Saxton
Nuclear Experimental Corporation (Saxton), which owns a small demonstration
nuclear reactor that has been partially decommissioned. All of these
companies together with their affiliates are referred to as the "GPU System."
The income of GPU consists almost exclusively of earnings on the common stock
of the Subsidiaries.
As a registered holding company, the GPU System is subject to regulation
by the Securities and Exchange Commission (SEC) under the 1935 Act. Retail
rates, conditions of service, issuance of securities and other matters are
subject to regulation in the state in which each Subsidiary operates - in New
Jersey by the New Jersey Board of Public Utilities (NJBPU) and in Pennsylvania
by the Pennsylvania Public Utility Commission (PaPUC). The Nuclear Regulatory
Commission (NRC) regulates the construction, ownership and operation of
nuclear generating stations. The Subsidiaries are also subject to wholesale
rate and other regulation by the Federal Energy Regulatory Commission (FERC)
under the Federal Power Act (see Regulation).
INDUSTRY DEVELOPMENTS
The electric power markets have for more than the past fifty years
generally been served by regulated monopolies. Over the last few years,
however, market forces combined with state and federal, legislative and
regulatory actions, have laid the foundation for the continued development of
competition in the electric utility industry. The electric utility industry
is 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 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, more recently, the Energy Policy Act of 1992 (EPAct).
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The EPAct 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.
Among its provisions, the EPAct allows the FERC, subject to certain criteria,
to order owners of electric transmission systems to provide third parties with
transmission access for wholesale power transactions. Although the
legislation did not give the FERC the authority to order retail transmission
access, movement toward opening the transmission network to retail customers
is currently under consideration in several states.
The EPAct, 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 places new pressures on utility
profit margins and credit quality. Utilities with significantly higher cost
structures than supportable in the marketplace will experience reduced
earnings as they attempt to meet their customers' demands for lower-priced
electricity. Competitive forces continue to influence some retail pricing.
In some cases, industrial customers have indicated their intention to pursue
competitively priced electricity from other providers, and in some instances
have leveraged price concessions from utilities. 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.
During 1994 and in early 1995, there have been a number of major federal
and state initiatives in the area of competition within the electric utility
industry:
- In June 1994, the FERC issued a Notice of Proposed Rulemaking regarding
the recovery by utilities of legitimate and verifiable stranded costs.
Costs incurred by a utility to provide integrated electric service to a
franchise customer become stranded when that customer subsequently
purchases power from another supplier using the utility's transmission
services. Among other things, the FERC proposed that utilities be
allowed under certain circumstances to recover such stranded costs
associated with existing wholesale customer contracts, but not under new
wholesale contracts unless expressly provided for in the contract. While
it stated a "strong" policy preference that state regulatory agencies
address recovery of stranded retail costs, the FERC also set forth
alternative proposals for how it would address the matter if the states
failed to do so. Subsequent to the FERC's Notice of Proposed Rulemaking,
however, the U.S. Court of Appeals for the District of Columbia, in an
unrelated case, questioned whether permitting stranded cost recovery was
so inherently anticompetitive that it violates antitrust laws. While
largely supported by the electric utility industry, the Proposed
Rulemaking has been strongly opposed by other groups.
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- In October 1994, the FERC issued a policy statement regarding pricing for
electric transmission services. The policy statement contains certain
principles that will provide the foundation for the FERC's analyses of
all subsequent transmission rate proposals. Recognizing the evolution of
a more competitive marketplace, the FERC contends that it is critical
that transmission services be priced in a manner that appropriately
compensates transmission owners and creates adequate incentives for
efficient system expansion. Separately, the FERC has also determined
that electric utilities providing transmission access must do so on a
"comparable basis."
- In November 1994, the SEC issued a Concept Release seeking public comment
on a series of issues regarding modernization of holding company
regulation under the 1935 Act. In its comments on the Concept Release,
GPU has urged that the 1935 Act be repealed because its purposes have
long since been fulfilled and the statute now represents a significant
impediment to competition. GPU also recommended, in the alternative,
that the SEC substantially relax its regulation of registered holding
company systems.
- In November 1994, the NJBPU issued a draft New Jersey Energy Master Plan
Phase I Report promoting regulatory policy changes intended to move the
state's electric and gas utilities into a competitive marketplace. In
the draft, the NJBPU recommends, among other things, the adoption of 1)
rate-flexibility legislation to allow utilities to compete in order to
retain and attract customers; 2) alternatives to rate base/rate-of-return
regulation; 3) consumer protection standards to ensure that captive
ratepayers do not subsidize competitive activities; and 4) an integrated
resource planning and competitive supply-side procurement process to
streamline the regulatory review process, lower costs, and ensure that
the state's environmental and energy conservation goals are met in a
competitive marketplace. Although the NJBPU proposes actions and
regulatory reforms that encourage competition, the draft Plan calls for
an evolutionary transition toward open markets. The recommendations are
largely intended to be interim measures while the NJBPU investigates
other issues, including retail wheeling and stranded costs, that are
likely to affect the future of the electric utility industry. The Plan
is being developed in three phases, with Phase I expected to be adopted
in March 1995 and the remaining phases expected to be concluded by year-
end 1995.
- In April 1994, the PaPUC initiated an investigation into the role of
competition in the electric utility industry. Met-Ed and Penelec filed
responses suggesting, among other things, that the PaPUC provide for the
equitable recovery of stranded investment, enable utilities to offer
flexible pricing to customers with competitive alternatives, and address
regulatory requirements that impose costs unequally on utilities as
compared with unregulated or out-of-state suppliers. The investigation
is expected to be concluded in 1995, at which time the PaPUC will decide
whether to conduct a rulemaking proceeding.
- In a January 1995 order, the FERC determined that a power purchase
agreement between Connecticut Power & Light Co. and a nonutility
generator was invalid since state law mandating the agreement provided
for the utility to pay rates in excess of its "avoided costs", contrary
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to PURPA and the FERC's implementing regulations. Then, in February
1995, the FERC found that the California Public Utilities Commission's
(CPUC) capacity procurement program also violated PURPA because, as
designed, it necessarily resulted in contract rates above the state
utilities' avoided costs. The FERC further expressed concerns that the
CPUC had based its finding of capacity requirements on stale data.
Following these two decisions, other utilities have sought to have the
FERC determine that categories of their nonutility generation power
purchase agreements are void on the same or similar grounds. The
Subsidiaries are reviewing these FERC decisions and various of their
nonutility generation agreements in this light. In addition, the GPU
System is, together with other electric utilities, currently engaged in
efforts to repeal PURPA.
Insofar as the Subsidiaries are concerned, potentially unrecoverable
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 Subsidiaries' ability to recover such assets from
their respective ratepayers in the future. In markets where there is excess
capacity (as there currently is in the Mid-Atlantic and surrounding regions
which include New Jersey and Pennsylvania) and many available sources of power
supply, the market price of electricity is expected to be lower than what
would be necessary to support full recovery of the investment in the
generating facilities. Another significant exposure in the transition to a
competitive market results if the prices of a utility's existing purchased
power contracts, consisting primarily of contractual obligations with
nonutility generators, are higher than future market prices (see NONUTILITY
AND OTHER POWER PURCHASES). Utilities locked into expensive purchased power
arrangements may be forced to value the contracts at market prices and
recognize certain losses. A third source of exposure is regulatory assets
which, if not supported by regulators, would have no value in a competitive
market. Statement of 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 GPU
System'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 currently. The GPU System believes that to the extent that it 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 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 from customers of
such costs during the industry's transition period.
As discussed below, in response to this situation the Subsidiaries, among
other things, intend to avoid, to the maximum extent practicable, entering
into any new nonutility generation agreements that are not needed or
inconsistent with competitive market pricing. The Subsidiaries are also
seeking to renegotiate and wherever practicable buy out existing high cost
long-term agreements, and will continue to pursue legal, regulatory and
legislative initiatives to this end.
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Also in 1994, EI acquired North Canadian Power, Inc. (NCP) and ownership
interests in NCP's five operating cogeneration facilities for approximately
$54 million. EI is actively engaged in a number of domestic and international
energy development projects, including as a joint venture participant in a 750
MW combined-cycle project in Barranquilla, Colombia (see NONUTILITY
BUSINESSES).
Corporate Realignment
GPU intends to organize a new subsidiary, GPU Generation Corporation
(GPUGC), to operate, maintain and repair the non-nuclear generation facilities
owned by the Subsidiaries as well as undertake responsibility to construct any
new non-nuclear generation facilities which the Subsidiaries may need in the
future. GPUGC will consolidate and streamline the management of these
generation facilities. During 1994, the Subsidiaries received regulatory
approvals from the PaPUC and NJBPU to enter into an operating agreement with
GPUGC. An application for SEC authorization is pending.
The management of GPU's two Pennsylvania operating subsidiaries has also
been combined. This action is intended to increase effectiveness and lower
costs of Pennsylvania customer operations and service functions. In addition,
employee participation in incentive compensation programs has been expanded to
tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System
workforce accepted the Voluntary Enhanced Retirement Programs (VERP) resulting
in a pre-tax charge to earnings of $127 million of which JCP&L's, Met-Ed's and
Penelec's shares were $47 million, $35 million and $45 million, respectively.
Future payroll and benefits savings, which are estimated to be $75 million
annually (JCP&L's, Met-Ed's and Penelec's shares of these savings are
$31 million, $18 million and $26 million, respectively), began in the third
quarter and reflect limiting the replacement of employees up to ten percent of
those retired. Retirement benefits will be substantially paid from pension
and postretirement plan trusts.
THE SUBSIDIARIES
The electric generating and transmission facilities of the Subsidiaries
are physically interconnected and are operated as a single integrated and
coordinated system serving a population of approximately 5 million in
New Jersey and Pennsylvania. For the year 1994, the Subsidiaries' revenues
were about equally divided between Pennsylvania customers and New Jersey
customers. During 1994, the proportional breakdown of sales to customers by
customer class was as follows:
% Operating Revenues % KWH Sales
GPU JCP&L Met-Ed Penelec GPU JCP&L Met-Ed Penelec
Residential 42 44 43 36 36 41 36 29
Commercial 34 38 28 32 32 38 27 29
Industrial 22 17 28 27 29 21 35 34
Other* 2 1 1 5 3 - 2 8
100 100 100 100 100 100 100 100
* Rural electric cooperatives, municipalities (primarily street and highway
lighting) and others.
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The Subsidiaries also make interchange and spot market sales of
electricity to other utilities. Reference is made to System Statistics and
Company Statistics on pages F-3, F-57, F-105, and F-151, for additional
information concerning the GPU System's sales and revenues. Revenues of
JCP&L, Met-Ed and Penelec derived from their largest single customer accounted
for less than 3%, 2% and 1%, respectively, of their electric operating
revenues for the year and their 25 largest customers, in the aggregate,
accounted for approximately 10%, 11% and 11%, respectively, of such revenues.
The area served by the Subsidiaries extends from the Atlantic Ocean to
Lake Erie, is generally comprised of small communities, rural and suburban
areas and includes a wide diversity of industrial enterprises, as well as
substantial farming areas. JCP&L provides retail service in northern, western
and east central New Jersey having an estimated population of approximately
2.6 million. Met-Ed provides retail electric service in all or portions of 14
counties, in the eastern and south central parts of Pennsylvania, having an
estimated population of almost one million. Met-Ed also sells electricity at
wholesale to four municipalities having an estimated population of over
11,000. Penelec provides retail and wholesale electric service within a
territory located in western, northern and south central Pennsylvania
extending from the Maryland state line northerly to the New York state line,
with a population of about 1.5 million, approximately 24% of which is
concentrated in ten cities and twelve boroughs, all with populations over
5,000. Penelec also provides wholesale service to five municipalities in New
Jersey, and, as lessee of the property of the Waverly Electric Light & Power
Company, also serves a population of about 13,700 in Waverly, New York and
vicinity.
The Subsidiaries' transmission facilities are physically interconnected
with neighboring nonaffiliated utilities in Pennsylvania, New Jersey,
Maryland, New York and Ohio. The Subsidiaries 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.
NONUTILITY BUSINESSES
EI and EI Power, Inc. are in the business of developing, owning,
operating and investing in cogeneration and other nonutility power production
facilities.
As of December 31, 1994, EI had twelve combined-cycle cogeneration plants
in-service located in the United States and Canada with a total capacity of
932 MW and a 24 MW facility under construction expected to be completed in
1996. EI has operating responsibility for nine of these plants. In 1994, EI
acquired NCP along with partnership interests in NCP's five domestic operating
projects. In addition, EI is a participant in a joint venture developing a
750 MW combined-cycle plant in Barranquilla, Colombia.
In 1994, GPU contributed $75 million in cash to EI for the purpose of
investing in nonutility generation projects and partnerships. Total EI
investments for the year consisted of approximately $54 million for the NCP
acquisition and $20 million for other capital expenditures. At December 31,
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1994, GPU's net investment in EI was $111 million. The SEC has authorized GPU
to invest up to an additional $200 million in EI through 1997.
The EPAct created two new categories of nonutility entities - exempt
wholesale generators (EWG) and foreign utility companies which are largely
free from rate regulation (other than with respect to an EWG's wholesale
rates), as well as regulation under the 1935 Act. EI has expanded its
business activities to include the development of additional capacity through
EWGs in the United States and is pursuing development projects in Latin
America and Asia, while investigating other international opportunities.
NUCLEAR FACILITIES
The Subsidiaries have 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 TMI-2, which was damaged during a 1979
accident. At December 31, 1994, the Subsidiaries' net investment, including
nuclear fuel, in TMI-1 was $627 million (JCP&L's, Met-Ed's and Penelec's
shares are $162 million, $311 million and $154 million, respectively) and
$817 million for Oyster Creek. TMI-1 and TMI-2 are jointly owned by JCP&L,
Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively.
Oyster Creek is owned by JCP&L.
Costs associated with the operation, maintenance and retirement of
nuclear plants have continued to be significant and less predictable than
costs associated with other sources of generation, in large part due to
changing regulatory requirements and safety standards and experience gained in
the construction and operation of nuclear facilities. The GPU System may also
incur costs and experience reduced output at its nuclear plants because of the
prevailing design criteria 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 lives (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 1994, TMI-1 operated at a capacity factor of
approximately 96%. No refueling outages occurred in 1994; the next refueling
outage is scheduled to begin in September 1995.
Oyster Creek
The Oyster Creek station, a 610 MW boiling water reactor (effective
January 17, 1995 the Oyster Creek station was rerated at 619 MW), received a
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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. During the 65-day scheduled refueling outage which began
in September 1994, inspections revealed unscheduled, necessary repairs that
extended the outage to 97 days. Taking this into account the plant operated
at a capacity factor of approximately 68% during 1994. The next refueling
outage is scheduled to begin in September 1996.
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 the Corporation and the
Subsidiaries. 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. If, notwithstanding the developments noted
below, punitive damages are not covered by insurance and are not subject to
the liability limitations of the federal Price-Anderson Act ($560 million at
the time of the accident), punitive damage awards could have a material
adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Subsidiaries had (a) primary financial protection in the form of
insurance policies with groups of insurance companies providing an aggregate
of $140 million of primary coverage, (b) secondary financial protection in the
form of private liability insurance under an industry retrospective rating
plan providing for premium charges deferred in whole or in major part under
such plan, and (c) an indemnity agreement with the NRC, bringing their total
primary and secondary insurance financial protection and indemnity agreement
with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against the Corporation and the Subsidiaries and their
suppliers under a reservation of rights with respect to any award of punitive
damages. However, in March 1994, the defendants in the TMI-2 litigation and
the insurers agreed that the insurers would withdraw their reservation of
rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is likely to begin in 1996. 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
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cannot be resolved on a motion for summary judgement. In July 1994, the Court
granted defendants' motion for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals.
In an order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against the Corporation
and the Subsidiaries; and (2) stated in part that the Court is of the opinion
that any punitive damages owed must be paid out of and limited to the amount
of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
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 GPU's consolidated financial statements for further information regarding
nuclear fuel disposal costs.
In 1990, the Subsidiaries 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 Subsidiaries 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 targets (in 1994 dollars) for TMI-1 are $157 million
(JCP&L's, Met-Ed's and Penelec's shares are $39 million, $79 million and $39
million, respectively) and for Oyster Creek, $189 million. Based on NRC
studies, a comparable funding target for TMI-2 has been developed which takes
into account the accident (see TMI-2 Future Costs). The NRC continues to
study 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 considered 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
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the cost of the radiological portions of decommissioning each plant (adjusted
to 1994 dollars) to range from approximately $225 to $309 million for TMI-1
while Met-Ed's share of the range is from $113 million to $155 million, and
$239 to $350 million for Oyster Creek. In addition, the studies estimated the
cost of removal of nonradiological structures and materials (adjusted to 1994
dollars) at $74 million for TMI-1 (JCP&L's, Met-Ed's and Penelec's shares are
$18 million, $37 million and $19 million, respectively) and $48 million for
Oyster Creek.
The ultimate cost of retiring the GPU System's 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
Subsidiaries charge to expense and contribute to external trusts amounts
collected from customers for nuclear plant decommissioning and nonradiological
costs. In addition, the Subsidiaries have contributed amounts written off for
TMI-2 nuclear plant decommissioning in 1990 and 1991 to an external trust and
will await resolution of the case pending before the Pennsylvania Supreme
Court (see TMI-2 Future Costs) before making any further contributions for
amounts written off by Met-Ed and Penelec in 1994.
TMI-1 and Oyster Creek
JCP&L is collecting revenues for decommissioning, which are expected to
result in the accumulation of its share of the NRC funding target for each
plant. JCP&L is also collecting revenues based on estimates of $15 million
for TMI-1 and $32 million for Oyster Creek, adopted in 1991 and 1993 rate
orders issued by the NJBPU, for its share of the cost of removal of
nonradiological structures and materials. In January 1993, the PaPUC granted
Met-Ed revenues for decommissioning costs of TMI-1 based on its share of the
NRC funding target and nonradiological cost of removal as estimated in the
site-specific study. Effective October 1993, the PaPUC approved a rate change
for Penelec which increased the collection of revenues for decommissioning
costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections
from customers for decommissioning expenditures are deposited in external
trusts. Provision for the future expenditure of these funds has been made in
accumulated depreciation, amounting to $46 million for TMI-1 (JCP&L's,
Met-Ed's and Penelec's shares are $17 million, $21 million and $8 million,
respectively) and $100 million for Oyster Creek at December 31, 1994.
TMI-2 Future Costs
The Corporation and its Subsidiaries have recorded a liability amounting
to $250 million (JCP&L's, Met-Ed's and Penelec's shares are $63 million,
$125 million and $62 million, respectively) as of December 31, 1994, for the
radiological decommissioning of TMI-2, reflecting the NRC funding target. The
Subsidiaries record escalations, when applicable, in the liability based upon
changes in the NRC funding target. The Subsidiaries have also recorded a
liability in the amount of $19 million (JCP&L's, Met-Ed's and Penelec's shares
are $5 million, $9 million and $5 million, respectively) for incremental costs
specifically attributable to monitored storage. In addition, the Subsidiaries
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have recorded a liability in the amount of $72 million (JCP&L's, Met-Ed's and
Penelec's shares are $18 million, $36 million and $18 million, respectively)
for nonradiological cost of removal. In 1990, JCP&L made a contribution of
$15 million to an external decommissioning trust. In 1991, Met-Ed and Penelec
made contributions of $40 million and $20 million, respectively, to external
decommissioning trusts relating to their shares of the accident-related
portion of the decommissioning liability. These contributions were not
recovered from customers and have been written off. Met-Ed and Penelec will
await resolution of the appeal pending before the Pennsylvania Supreme Court
(discussed below) before making any further contributions of amounts written
off.
In 1993, the Pennsylvania Office of Consumer Advocate (Consumer
Advocate) filed a petition for review of a Met-Ed rate order with the
Pennsylvania Commonwealth Court seeking to set aside a March 1993 PaPUC rate
order which allowed Met-Ed to recover in the future certain TMI-2 retirement
costs (radiological decommissioning and nonradiological cost of removal). In
1994, the Commonwealth Court reversed that rate order and, as a consequence,
Met-Ed and Penelec recorded pre-tax charges totalling $128 million and
$56 million, respectively. In December 1994, the Pennsylvania Supreme Court
granted Met-Ed's request to review the decision. Met-Ed and Penelec will be
required to charge to expense their share of future increases in the estimate
of the costs of retiring TMI-2 if the Supreme Court does not reverse the
Commonwealth Court decision.
The NJBPU has granted JCP&L decommissioning revenues for the remainder
of the NRC funding target and allowances for the cost of removal of
nonradiological structures and materials. JCP&L, which is not affected by the
Commonwealth Court's ruling, intends to seek recovery for any increases in
TMI-2 retirement costs, but recognizes that recovery cannot be assured.
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 GPU System.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station 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 for stabilization of
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 that
station.
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The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial 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 two operating reactors (TMI-2 being excluded
under an exemption received from the NRC in 1994), subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, under insurance policies
applicable to nuclear operations and facilities, the GPU System is also
subject to retrospective premium assessments of up to $69 million in any one
year (JCP&L's, Met-Ed's and Penelec's shares being $41 million, $19 million
and $9 million, respectively).
The GPU System has insurance coverage for incremental replacement power
costs resulting from an accident-related outage at its nuclear plants.
Coverage commences after the first 21 weeks of the outage and continues for
three years beginning at $1.8 million for Oyster Creek and $2.6 million for
TMI-1 per week for the first year, decreasing by 20 percent for years two and
three.
NONUTILITY AND OTHER POWER PURCHASES
The Subsidiaries have entered into power purchase agreements with
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
Subsidiaries to purchase at the contract price the net output up to the
contract limits. As of December 31, 1994, facilities covered by these
agreements having 1,416 MW (JCP&L 882 MW, Met-Ed 239 MW and Penelec 295 MW) of
capacity were in service and 130 MW were scheduled to commence operation in
1995. Actual payments from 1992 through 1994, and estimated payments to
nonutility generators (including those scheduled to enter service thereafter)
through 1999 are as follows:
Payments Under Nonutility Agreements
(Millions)
Total JCP&L Met-Ed Penelec
1992 $ 471 $ 316 $ 78 $ 77
1993 491 292 95 104
1994 528 304 101 123
*1995 694 395 114 185
*1996 918 556 170 192
*1997 1,088 571 280 237
*1998 1,304 587 415 302
*1999 1,337 607 418 312
* Estimated
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These agreements, in the aggregate, provide for the purchase of
approximately 2,596 MW (JCP&L 1,176 MW, Met-Ed 846 MW and Penelec 574 MW) of
capacity and energy by the GPU System by the mid-to-late 1990s.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the System's energy supply needs which has caused
the Subsidiaries to change their supply strategy to now seek shorter-term
agreements offering more flexibility. Due to the current availability of
excess capacity in the market place, the cost of near- to intermediate-term
(i.e., one to eight years) energy supply from existing generation facilities
is currently competitively priced. The projected cost of energy from new
generation supply sources has also decreased due to improvements in power
plant technologies and reduced forecasted fuel prices. As a result of these
developments, the rates under virtually all of the Subsidiaries' nonutility
generation agreements are substantially in excess of current and projected
prices from alternative sources.
These agreements have been entered into pursuant to the requirements of
PURPA and state regulatory directives. Given these circumstances, the
Subsidiaries have initiated a number of programs to attempt to substantially
reduce these above market payments. In addition, the Subsidiaries intend to
avoid, to the maximum extent practicable, entering into any new nonutility
generation agreements that are not needed or not consistent with current
market pricing. The Subsidiaries are also attempting to renegotiate, and in
some cases buyout, high cost long-term nonutility generation agreements.
While the Subsidiaries thus far have been granted recovery of their
nonutility generation costs from customers by the PaPUC and NJBPU, there can
be no assurance that the Subsidiaries will continue to be able to recover
these costs throughout the term of the related agreements (see INDUSTRY
DEVELOPMENTS). GPU currently estimates that in 1998, when substantially all
of the these nonutility generation projects are scheduled to be in service,
above market payments (benchmarked against the expected cost of electricity
produced by a new gas-fired combined cycle facility) will range from
$300 million to $450 million annually (for JCP&L, $120 million to
$190 million; for Met-Ed, $90 million to $140 million; and for Penelec,
$90 million to $120 million). Moreover, efforts to lower these costs have led
to disputes before both the NJBPU and the PaPUC, as well as to litigation, and
may result in claims against the Subsidiaries for substantial damages. There
can be no assurance as to the outcome of these matters.
A 1993 NJBPU order directed all New Jersey utilities to identify
nonutility generation contracts which were uneconomic and, therefore,
candidates for buyout or other remedial measures. JCP&L identified the
proposed 100 MW Freehold generation project as one such candidate, but was
unable to negotiate a buyout or contract repricing to a level consistent with
prices of replacement power. The NJBPU therefore ordered that hearings be
held to determine whether its order approving the agreement should be modified
or revoked. After hearings commenced in early 1994, the nonutility generator
filed a complaint with the U.S. District Court seeking to enjoin the NJBPU
proceedings on the grounds they were preempted by PURPA. The District Court
dismissed the complaint on jurisdictional grounds. In January 1995, however,
the U.S. Court of Appeals for the Third Circuit overturned the District Court
decision. The Court of Appeals held, among other things, that once the NJBPU
approves a power purchase agreement under PURPA and approves the utility's
collection of costs from its customers, PURPA preempts the NJBPU from altering
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its order approving the contract and JCP&L's recovery from customers of its
payment to the nonutility generator. The Court of Appeals reached its
decision despite the contract provision that if the NJBPU at any time in the
future disallowed any such rate recovery, JCP&L's payments to the nonutility
generator would be equally reduced. JCP&L, the NJBPU and the New Jersey
Division of Ratepayer Advocate (Ratepayer Advocate) have each filed motions
for in banc rehearing with the Court of Appeals before which the matter is
pending.
In 1994, a nonutility generator requested that the NJBPU and the PaPUC
order JCP&L and Met-Ed to enter into long-term agreements to buy capacity and
energy from the nonutility generator's proposed 322 MW facility. On February
14, 1995, the NJBPU Administrative Law Judge (ALJ) hearing the matter issued a
recommended decision finding that while the developer had established a right
to an agreement under PURPA, the rates payable by JCP&L were to be based upon
JCP&L's 1993 avoided energy costs and not 1992 costs as the developer
requested. JCP&L has appealed aspects of the ALJ's decision to the NJBPU.
Met-Ed sought to dismiss a similar request based on a May 1994 PaPUC order,
which granted a Met-Ed and Penelec petition to obtain additional nonutility
purchases through competitive bidding until new PaPUC regulations have been
adopted. In September 1994, the Commonwealth Court granted the PaPUC's
application to revise its May 1994 order for the purpose of reevaluating the
nonutility generator's right to sell power to Met-Ed. The PaPUC has referred
the matter to an ALJ for hearings.
In November 1994, Penelec requested the Pennsylvania Supreme Court to
review a Commonwealth Court decision upholding a PaPUC order requiring Penelec
to purchase a total of 160 MW from two nonutility generators. The PaPUC had
ordered Penelec in 1993 to enter into power purchase agreements with the
nonutility generators for 80 MW of power each under long-term contracts
commencing in 1997 or later. In August 1994, the Commonwealth Court denied
Penelec's appeal of the PaPUC order. Penelec is seeking review by the
Pennsylvania Supreme Court on the grounds that the contracts would impose
unnecessary and excessive costs on Penelec customers and, in any case, that
the nonutility generators did not incur a legal obligation entitling them to a
payment under PURPA.
In May 1994, the NJBPU granted two nonutility developers of a proposed
200 MW coal project final in-service date extensions for projects originally
scheduled to be operational in 1997. JCP&L has appealed the NJBPU's decision
to the Appellate Division of the New Jersey Superior Court on the grounds,
among others, that the NJBPU exceeded its authority by unilaterally amending
the power purchase agreements. Oral argument was held on March 1, 1995. The
NJBPU order extends the in-service date for one year plus the period until
JCP&L's appeals are decided.
As part of the effort to reduce above-market payments under nonutility
generation agreements, the Subsidiaries are also seeking to implement a
program under which the natural gas fuel procurement and transportation for
the Subsidiaries' gas-fired facilities, as well as up to approximately 1,100
MW of nonutility generation capacity, would be pooled and managed by a
nonaffiliated fuel manager. The Subsidiaries believe the plan has the
potential to provide substantial savings for their customers. The
Subsidiaries have begun initial discussions with the nonutility generators who
would be eligible to participate and are negotiating a proposed fuel
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management agreement. Requirements for approval of the plan by state and
federal regulatory agencies are being reviewed.
Met-Ed has entered into an agreement and JCP&L is completing contract
negotiations with three other utilities to purchase capacity and energy for
various periods through 2004. These agreements, including contracts under
negotiation, will provide for up to 1,308 MW in 1995, declining to 1,096 MW in
1997 and 696 MW by 2004. For the years 1995, 1996, 1997, 1998, and 1999,
payments pursuant to these agreements are estimated as follows:
Payments Under Other Utility Agreements
(Millions)
Total JCP&L Met-Ed Penelec
1995 $ 208 $ 202 $ 6 $ -
1996 175 175 - -
1997 162 162 - -
1998 145 145 - -
1999 128 128 - -
JCP&L's contract negotiations are the result of its all-source
solicitation for short- to intermediate-term energy and capacity (see the New
Energy Supplies section of MANAGEMENT'S DISCUSSION AND ANALYSIS).
RATE PROCEEDINGS
Pennsylvania
In December 1994, the Pennsylvania Supreme Court granted Met-Ed's
request to review a Commonwealth Court decision reversing a 1993 PaPUC rate
order allowing for the future recovery of certain TMI-2 retirement costs (see
TMI-2 Future Costs in the Nuclear Plant Retirement Costs section above).
In 1993, Penelec began deferring FAS 106 incremental expense in
accordance with the PaPUC's generic policy statement permitting the deferral
of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the
PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of
such costs, stating that FAS 106 expense incurred after January 1, 1993 (the
effective date for the accounting change) but prior to its next base rate case
could not be deferred for future recovery, and that to assure such future
recovery constituted retroactive ratemaking (see page F-50, Note 9 of GPU's
Consolidated Financial Statements). As a result of the Court's decision,
Penelec wrote off $14.6 million deferred since January 1993. Penelec
anticipates it will take additional charges to income of approximately
$9 million annually, beginning in 1995. The Corporation believes the
Commonwealth Court ruling does not affect Met-Ed because it received PaPUC
authorization as part of its 1993 retail base rate order to defer incremental
FAS 106 expense. JCP&L received similar authorization in a 1993 NJBPU retail
base rate order.
At the request of the PaPUC, the affected Pennsylvania electric
utilities have submitted to the PaPUC proposals for the establishment of a
nuclear performance standard. The PaPUC will adopt a generic nuclear
performance standard as a part of Met-Ed's and Penelec's energy cost rate
clauses in 1995.
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New Jersey
In December 1994, JCP&L filed a petition with the NJBPU requesting an
increase in its levelized energy adjustment clause charges (LEAC) and demand
side factors of approximately $68 million annually effective March 1, 1995.
The proposed increase is based on additional costs of nonutility generation
and demand-side management (DSM).
In May 1994, the NJBPU approved JCP&L's request to implement a new rate
initiative designed to retain and expand the economic base in its service
territory. Under the contract rate service, JCP&L may enter into individual
contracts to provide electric service to large commercial and industrial
customers. This initiative will allow JCP&L more flexibility in responding to
competitive pressures.
JCP&L's two operating nuclear units are subject to the NJBPU'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 of the performance standard charge at a 40% capacity factor
would be approximately $11 million before tax. While a capacity factor below
40% would generate no specific monetary charge, it would require the issue to
be brought before the NJBPU for review. The annual measurement period, which
begins in March of each year, coincides with that used for the LEAC.
The NJBPU 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 Ratepayer Advocate, 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 1993, JCP&L and the
other New Jersey electric utilities filed motions for summary judgment with
the NJBPU. The Ratepayer Advocate 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 JCP&L for the 1988-92 LEAC periods
would be approximately $102 million. In 1994, the NJBPU ruled that the 1991
LEAC period was considered closed but subsequent LEACs remain open for further
investigation. This matter is pending before an ALJ. JCP&L estimates that
the potential exposure for LEAC periods subsequent to 1991 is approximately
$67 million through February 1996, the end of the next LEAC period. There can
be no assurance as to the outcome of this proceeding.
CAPITAL PROGRAMS
General
During 1994, the GPU System had gross plant additions of approximately
$588 million (JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are
$249 million, $171 million, $164 million and $4 million, respectively)
attributable principally to improvements and modifications to existing
generating stations, new combustion turbines, additions to the transmission
and distribution system and clean air requirements. GPU also contributed
$75 million in cash to EI during 1994 (see NONUTILITY BUSINESSES). The
principal categories of the 1995 anticipated subsidiary construction
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expenditures, which include an allowance for other funds used during
construction, are as follows:
(In Millions)
1995
GPU JCP&L Met-Ed Penelec
Generation - Nuclear $ 51 $ 30 $ 14 $ 7
Nonnuclear 148 50 31 67
Total Generation 199 80 45 74
Transmission & Distribution 249 124 58 67
Other 34* 16 12 3
Total $482 $220 $115 $144
* Includes $3 million for GPUSC.
The GPU System's gross plant additions are expected to be approximately
$466 million in 1996 (JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are
$217 million, $101 million, $145 million, and $3 million, respectively). The
anticipated decrease in construction expenditures during 1996 is principally
attributable to an anticipated reduction in the level of expenditures
associated with clean air requirements. GPU will continue to contribute cash,
from time to time, to EI during 1995 and 1996 as project investment
opportunities arise. In addition, expenditures for maturing debt are expected
to be $91 million for 1995 (JCP&L's, Met-Ed's and GPUSC's shares are $47
million, $41 million and $3 million, respectively) and $129 million for 1996
(JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are $36 million, $15 million,
$75 million and $3 million, respectively) including mandatory redemptions of
preferred stock. Subject to market conditions, the Subsidiaries intend to
refinance during these periods outstanding senior securities, should it prove
economical to do so.
GPU estimates that two-thirds of the GPU System's total capital needs in
each of 1995 and 1996 will be satisfied through internally generated funds.
The Subsidiaries estimate that their respective capital needs will be met
through internally generated funds in the following proportions:
JCP&L Met-Ed Penelec
1995 2/3 1/2 3/4
1996 3/4 3/4 1/2
The Subsidiaries expect to obtain the remainder of these funds
principally through the sale of first mortgage bonds and preferred stock,
subject to market conditions. The Subsidiaries' bond indentures and articles
of incorporation include provisions that limit the amount of long-term debt,
preferred stock and short-term debt the Subsidiaries may issue (see
LIMITATIONS ON ISSUING ADDITIONAL SECURITIES). Present plans call for the
Subsidiaries 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.
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The GPU System's 1995 construction program includes $57 million (JCP&L's,
Met-Ed's and Penelec's shares are $20 million, $18 million and $19 million,
respectively) in connection with the federal Clean Air Act Amendments of 1990
(Clean Air Act) requirements (see Environmental Matters-Air). The 1996
construction program currently includes approximately $12 million (JCP&L's,
Met-Ed's and Penelec's shares are $2 million, $1 million and $9 million,
respectively) for Clean Air Act compliance.
The GPU System's gross plant additions exclude nuclear fuel requirements
provided under capital leases that amounted to $41 million (JCP&L's, Met-Ed's
and Penelec's shares are $37 million, $3 million and $1 million, respectively)
in 1994. When consumed, the presently leased material, which amounted to
$148 million (JCP&L's, Met-Ed's and Penelec's shares are $99 million, $33
million and $16 million, respectively) at December 31, 1994, is expected to be
replaced by additional leased material at an average rate of approximately $65
million (JCP&L's, Met-Ed's and Penelec's shares are $41 million, $16 million
and $8 million, respectively) annually. In the event the replacement nuclear
fuel needs cannot be leased, the associated capital requirements would have to
be met by other means.
Over the next five years, each of the Subsidiaries is expected to
experience an average growth in sales to customers of about 2% annually.
These increases are expected to result from continued economic growth in the
service territories and a slight increase in customers. The Subsidiaries
intend to provide for these increased energy needs through a mix of economic
supply sources.
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. Through 1999, the GPU System's plan consists of
the continued utilization of existing generating facilities, combined with
power purchases, construction of new facilities, and the continued promotion
of economic energy conservation and load-management programs. Given the
future direction of the industry, the GPU System's present strategy includes
minimizing the financial exposure associated with new long-term purchase
commitments and the construction of new facilities by evaluating these options
in terms of an unregulated market. The GPU System will take necessary actions
to avoid adding new capacity at costs that may exceed future market prices.
In addition, the Subsidiaries will seek regulatory support to renegotiate or
buyout contracts with nonutility generators where the pricing is in excess of
projected prices of alternative sources.
Conservation and Load Management
The NJBPU and PaPUC continue to encourage the development of new
conservation and load-management programs. The benefits of some of these
programs may not, however, offset program costs and the Subsidiaries are
working to mitigate the impacts these programs can have on their competitive
position in the marketplace.
In New Jersey, JCP&L continues to conduct DSM programs approved in 1992
by the NJBPU. DSM includes utility-sponsored activities designed to improve
energy efficiency in customer electricity use and load-management programs
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that reduce peak demand. These JCP&L programs have resulted in summer peak
demand reductions of over 43 MW through 1994.
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of DSM costs and directed utilities to implement DSM programs. Met-Ed and
Penelec subsequently filed DSM programs that were expected to be approved by
the PaPUC in the first quarter of 1995. However, an industrial intervenor
contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court
reversed the PaPUC order. As a result, the nature and scope of Met-Ed and
Penelec's DSM programs is uncertain at this time.
FINANCING ARRANGEMENTS
The Corporation and the Subsidiaries expect to have short-term debt
outstanding from time to time throughout 1995. The peak in short-term debt
outstanding is expected to occur in the spring, coinciding with normal cash
requirements for revenue tax payments.
The GPU System has $528 million of credit facilities, which includes a
Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1,
1999, are limited to $250 million in total borrowings outstanding at any time
and are subject to various covenants and acceleration under certain
conditions. The Credit Agreement borrowing rates and facility fee are
dependent on the long-term debt ratings of the Subsidiaries.
In 1994, Penelec and Met-Ed issued $205 million (Met-Ed $100 million and
Penelec $105 million) of Monthly Income Preferred Securities through special-
purpose finance subsidiaries, and an aggregate of $180 million (Met-Ed
$50 million and Penelec $130 million) principal amount of long-term debt. A
portion of the proceeds from these sales was used to refinance long-term debt
amounting to $64 million (Met-Ed $26 million and Penelec $38 million) and
redeem $60 million of more costly preferred stock (Met-Ed $35 million and
Penelec $25 million). During the first quarter of 1995, Penelec and Met-Ed
issued $60 million and $30 million, respectively, of long-term debt. The net
proceeds from these sales were used to reduce short-term debt.
JCP&L anticipates receiving regulatory approval in the first quarter of
1995 to issue, through a special-purpose finance subsidiary, up to
$125 million of Monthly Income Preferred Securities. A portion of these
securities is expected to be issued in 1995 to reduce short-term debt.
The Subsidiaries have regulatory authority to issue and sell first
mortgage bonds (FMBs), which may be issued as secured medium-term notes, and
preferred stock for various periods through 1995. Under existing
authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the
amount of $275 million, $220 million and $230 million, respectively, of which
$100 million for each Subsidiary may consist of preferred stock. Met-Ed and
Penelec, through their special-purpose finance subsidiaries, have remaining
regulatory authority to issue an additional $25 million and $20 million,
respectively, of Monthly Income Preferred Securities. The Subsidiaries also
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have regulatory authority to incur short-term debt, a portion of which may be
through the issuance of commercial paper.
Present plans call for GPU to issue common stock and the Subsidiaries to
issue long-term debt and Monthly Income Preferred Securities during the next
three years to finance construction activities, make additional investments in
GPU's nonregulated businesses, fund the redemption of maturing senior
securities, make contributions to decommissioning trust funds and, depending
on the level of interest rates, refinance outstanding senior securities.
Under the Subsidiaries 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 Subsidiaries are
responsible for the disposal costs of nuclear fuel leased under these
agreements.
LIMITATIONS ON ISSUING ADDITIONAL SECURITIES
The Subsidiaries' first mortgage bond indentures and/or articles of
incorporation contain provisions which limit the total amount of securities
evidencing secured indebtedness and/or unsecured indebtedness which the
Subsidiaries may issue, the more restrictive of which are discussed below.
The Subsidiaries' first mortgage bond indentures require that, for a
period of any twelve consecutive months out of the fifteen calendar months
immediately preceding the issuance of additional bonds, net earnings (before
income taxes, with other income limited to 5% of operating income before
income taxes for JCP&L and Met-Ed and 10% for Penelec) available for interest
on bonds shall have been at least twice the annual interest requirements on
all bonds to be outstanding immediately after such issuance. Moreover, the
Subsidiaries' first mortgage bond indentures restrict the ratio of the
principal amount of first mortgage bonds which may be issued to not more than
60% of bondable value of property additions. In addition, the indentures, in
general, permit the Subsidiaries to issue additional first mortgage bonds
against a like principal amount of previously retired bonds.
Among other restrictions, the Subsidiaries' charters provide that without
the consent of the holders of two-thirds of the outstanding preferred stock,
no additional shares of preferred stock may be issued unless, for any period
of any twelve consecutive months out of the fifteen calendar months
immediately preceding such issuance, the after-tax net 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, and for Penelec, net earnings
available for the payment of dividends on preferred stock shall have been at
least three times the annual dividend requirements on all shares of preferred
stock to be outstanding immediately after such issuance.
The Subsidiaries' charters also provide that, without the consent of the
holders of a majority of the total voting power of the Subsidiaries'
outstanding preferred stock, the Subsidiaries may not issue or assume any
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securities representing short-term unsecured indebtedness (except to refund
certain outstanding unsecured securities issued or assumed by the Subsidiaries
or to redeem all outstanding preferred stock, if immediately thereafter the
total principal amount of all outstanding unsecured debt securities having an
initial maturity of less than ten years (or within 3 years of maturity for
JCP&L) would exceed 10% of the aggregate of (a) the total principal amount of
all outstanding secured indebtedness issued or assumed by the Subsidiaries and
(b) the capital and surplus of the Subsidiaries. At December 31, 1994, these
restrictions would have permitted JCP&L, Met-Ed and Penelec to have
approximately $277 million, $119 million and $131 million, respectively, of
unsecured indebtedness outstanding.
The Subsidiaries have obtained authorization from the SEC to incur short-
term debt (including indebtedness under the Credit Agreement and commercial
paper) up to the Subsidiaries' charter limitations.
As of December 31, 1994, JCP&L's, Met-Ed's and Penelec's bondable value
of property additions were $418 million, $659 million and $549 million,
respectively. However, as a result of the TMI-2 retirement costs write-offs,
together with certain other costs recognized in the second quarter of 1994
(see TMI-2 Future Costs), Met-Ed will be unable to meet the interest and
preferred dividend coverage requirements of its indenture and charter,
respectively, until the third quarter of 1995. Therefore, Met-Ed's ability to
issue senior securities through June 1995 will be limited to the issuance of
FMBs on the basis of $35 million of previously issued and retired bonds. For
similar reasons, Penelec has sufficient coverage to issue only approximately
$20 million of FMBs through June 1995, depending on interest rates at the time
of issuance, plus $8 million of FMBs on the basis of previously issued and
retired bonds. Penelec will be unable to meet dividend coverage requirements
for issuing preferred stock until the third quarter of 1995. JCP&L currently
has the ability to issue $319 million of FMBs on the basis of previously
issued and retired bonds. JCP&L has sufficient interest coverage at
December 31, 1994 to issue approximately $900 million of FMBs, depending on
interest rates at the time of issuance; however, the issuances of FMBs on this
basis would be limited to 60% of JCP&L's bondable property additions, or
approximately $250 million. In addition, at December 31, 1994 JCP&L has
sufficient dividend coverage to issue approximately $730 million of preferred
stock, depending on interest rates at the time of issuance.
REGULATION
As a registered holding company, GPU is subject to regulation by the SEC
under the 1935 Act. The GPU System companies are 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 Subsidiaries constitute a single
integrated public utility system under the standards of the 1935 Act. The
1935 Act also limits the extent to which the GPU System may engage in
nonutility businesses. Each Subsidiary's retail rates, conditions of service,
issuance of securities and other matters are subject to regulation in the
state in which such Subsidiary operates - in New Jersey by the NJBPU and in
Pennsylvania by the PaPUC. Additionally, Penelec, as lessee, operates the
facilities serving the village of Waverly, New York. Penelec's retail rates
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for New York customers, as well as Penelec's New York operations and property,
are subject to regulation by the New York Public Service Commission (NYPSC).
Although Penelec does not render electric service in Maryland, the Public
Service Commission of Maryland has jurisdiction over the portion of Penelec's
property located in that state. Moreover, with respect to wholesale rates,
the transmission of electric energy, accounting, the construction and
maintenance of hydroelectric projects and certain other matters, the
Subsidiaries are 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. JCP&L is also subject, in
certain respects, to regulation by the PaPUC in connection with its
participation in the ownership and operation of certain facilities located in
Pennsylvania. (See ELECTRIC GENERATION AND THE ENVIRONMENT - Environmental
Matters for additional regulation to which the Subsidiaries are or may be
subject.)
ELECTRIC GENERATION AND THE ENVIRONMENT
Fuel
Of the portion of their energy requirements supplied by their own
generation, the Subsidiaries utilized fuels in the generation of electric
energy during 1994 in approximately the following percentages:
Total JCP&L Met-Ed Penelec
Coal 59% 22% 57% 85%
Nuclear 37% 68% 41% 14%
Gas 2% 6% - -
Oil 2% 6% - -
Other* - (2)% 2% 1%
* Represents hydro and pumped storage (which is a net user of electricity).
Approximately 41% (JCP&L's, Met-Ed's and Penelec's percentages are 60%,
33% and 28%, respectively) of the Subsidiaries' total energy requirements in
1994 was supplied by purchases and interchange from other utilities and
nonutility generators. For 1995, the Subsidiaries estimate that their
generation of electric energy will be in the following proportions:
Total JCP&L Met-Ed Penelec
Coal 63% 23% 64% 89%
Nuclear 34% 70% 33% 10%
Gas 2% 5% 1% -
Oil 1% 3% - -
Other* - (1)% 2% 1%
* Represents hydro and pumped storage.
The anticipated changes in 1995 fuel utilization percentages are
principally attributable to the refueling outage for TMI-1 scheduled during
1995. Approximately 41% (JCP&L's, Met-Ed's and Penelec's percentages are 60%,
37% and 26%, respectively) of the Subsidiaries' 1995 energy requirements are
expected to be supplied by purchases and interchange from other utilities and
nonutility generators.
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Fossil: The Subsidiaries have entered into long-term contracts with
nonaffiliated mining companies for the purchase of coal for certain generating
stations in which they have ownership interests (JCP&L 16.67% - ownership
interest in Keystone; Met-Ed - 16.45% ownership interest in Conemaugh; and
Penelec - 50% ownership in Homer City). The contracts, which expire between
1995 and the end of the expected service lives of the generating stations
(2004 for Keystone, between 1995 and 1997 for Conemaugh and between 1995 and
2003 for Homer City), require the purchase of fixed amounts of coal. The
price of the coal under the contracts is generally based on adjustments of
indexed cost components. One of Penelec's contracts for Homer City also
includes a provision for the payment of environmental and postretirement
benefits costs. The Subsidiaries' share of the cost of coal purchased under
these agreements is expected to aggregate $98 million for 1995 (JCP&L's, Met-
Ed's and Penelec's shares are $21 million, $27 million and $50 million,
respectively).
The Subsidiaries' coal-fired generating stations now in service are
estimated to require an aggregate of 147 million tons (JCP&L's, Met-Ed's and
Penelec's shares are 15 million tons, 38 million tons and 94 million tons,
respectively) of coal over the next twenty years. Of this total requirement,
approximately 11 million tons (JCP&L's and Penelec's shares are 4 million tons
and 7 million tons, respectively) are expected to be supplied by nonaffiliated
mine-mouth coal companies with the balance supplied through short- and
long-term contracts and spot market purchases.
At the present time, adequate supplies of fossil fuels are readily
available to the Subsidiaries, but this situation could change rapidly as a
result of actions over which they have no control.
Nuclear: Preparation of nuclear fuel for generating station use involves
various manufacturing stages for which the GPU System contracts 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. In March 1994, the Lacey Township Zoning Board of Adjustment issued a
use variance for the facility. In May 1994, however, Berkeley Township and
other parties appealed to the New Jersey Superior Court to overturn the
decision. The court has scheduled a trial for March 30, 1995. Construction
of the facility is scheduled for completion in September 1995.
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Environmental Matters
The GPU System 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 Subsidiaries are 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 Subsidiaries
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 GPU System may be required to incur substantial additional costs
to construct new equipment, modify or replace existing and proposed equipment,
remediate, decommission or clean up waste disposal and other sites currently
or formerly used by it, including formerly owned manufactured gas plants and
mine refuse piles and generating facilities, 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. The GPU
System 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. Additionally, water quality-based effluent limits (more stringent
than "technology" limits) may be applied to utility waste water discharges
based on receiving stream quality. With respect to future plants, the Clean
Water Act requires the application of the "best available demonstrated control
technology, processes, operating methods or other alternatives".
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 are required for all of the Subsidiaries' steam
generating stations. JCP&L's discharge permits have expired, and timely
reapplications have been filed as required by regulations. Until new permits
are issued, JCP&L's currently expired permits remain in effect. JCP&L has
also filed an application with the EPA for a discharge permit for its Yards
Creek pumped storage facility. Met-Ed and Penelec have obtained all required
discharge permits.
The discharge permit received by JCP&L 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
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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
(NJDEP) 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 October 1994, following six years of studies, the
NJDEP issued a new Discharge to Surface Water Permit for the Oyster Creek
station. The new permit grants JCP&L a variance from the New Jersey Surface
Water Quality Standards. The variance allows the continued operation of the
existing once-through cooling system without modifications such as cooling
towers. The variance is effective through October 1999. The NJDEP could
revoke the variance at any time upon failure to comply with the permit
conditions.
The NJDEP has proposed thermal and other conditions for inclusion in the
discharge permits for JCP&L's Gilbert and Sayreville generating stations
which, among other things, could require JCP&L to install cooling towers
and/or modify the water intake/discharge systems at these facilities. JCP&L
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 JCP&L's hearing request. JCP&L has made filings with
the NJDEP that, JCP&L 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 present once-through cooling system. Based on the
NJDEP's review of these demonstrations, substantial modifications may be
required at these stations, which may result in material capital expenditures.
The Subsidiaries are 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 NJDEP.
During 1993, Met-Ed entered into an agreement with various agencies to
construct a fish passage facility at its York Haven hydroelectric project by
the year 2000. The present estimated installed cost of the facility is
$6.7 million. Through 1994, less than $.5 million has been spent on pre-
construction. Construction is expected to begin in late 1998.
Nuclear: Reference is made to NUCLEAR FACILITIES for information
regarding the TMI-2 accident, its aftermath and the GPU System's other nuclear
facilities.
In June 1994, the Barnwell, South Carolina low level radioactive waste
(radwaste) disposal site closed. GPUN had been using this facility for
disposal of low-level radioactive waste from the Oyster Creek and TMI-1
nuclear generating stations. In July 1994, GPUN began on-site storage of low-
level radwaste at Oyster Creek and TMI-1 and will continue on-site storage
until June 1999, when both the Northeast Compact and Appalachian Compact
disposal facilities are currently scheduled to open. If the disposal
facilities are delayed beyond June 1999, GPUN will be required to perform an
evaluation as to its ability to safely store radwaste beyond that date.
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New Jersey and Connecticut have established the Northeast Compact, a low
level radwaste disposal facility in New Jersey. The estimated cost to license
and build the facility is $74 million. GPUN's minimum expected $29.5 million
share of the cost for this facility is to be paid annually over a six-year
period from 1992 to 1997. In a February 1993 rate order, the NJBPU authorized
JCP&L to recover these amounts currently from customers. Through December
1994, $6 million has been paid. The development of the facility is expected
to continue after 1997 which will most likely result in additional fees in
excess of $29.5 million.
Pennsylvania, Delaware, Maryland and West Virginia have established the
Appalachian Compact (which includes eleven nuclear power plants - 9 in
Pennsylvania and 2 in Maryland) for the disposal of low level radwaste in
those states, including low level radwaste from TMI-1. To date $33 million,
of a minimum estimated $88 million, of pre-construction costs has been paid.
The eleven plants have so far shared equally in the pre-construction cost,
including GPUN which has contributed $3 million. All contributors, including
nonutility radwaste producers within the compact that make voluntary
contributions, will receive certain credits from surcharges paid by all
depositors of waste over a ten-year period. The methodology for the
allocation of these credits has yet to be determined. In addition,
$50 million of estimated construction costs will be funded by an independent
contractor and recovered by the contractor through waste disposal fees
collected during the first five years of the facility's operation.
The Subsidiaries have provided for future contributions to the
Decontamination and Decommissioning Fund (part of the EPAct) for the cleanup
of enrichment plants operated by the Federal government. The GPU System's
total liability at December 31, 1994 amounted to $40 million (JCP&L's, Met-
Ed's and Penelec's shares are $25 million, $10 million and $5 million,
respectively). The Subsidiaries made their initial payment in 1993. The
remaining amount recoverable from ratepayers at December 31, 1994 is
$46 million (JCP&L's, Met-Ed's and Penelec's shares are $27 million,
$13 million and $6 million, respectively).
Air: The Subsidiaries are subject to certain state environmental
regulations of the NJDEP and the PaDER. The Subsidiaries are also subject to
certain federal environmental regulations of the EPA.
The PaDER, NJDEP 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
Penelec's generating stations constructed before 1972 and stations constructed
after 1971 but before 1978, to 3.7 pounds and 1.2 pounds per million BTU of
heat input, respectively. In the case of Met-Ed's facilities, the sulfur
dioxide content of stack gas emissions is limited to 2.8 pounds or 3.7 pounds
per million BTU of heat input depending on location. On a weighted average
basis, the Subsidiaries have been able to obtain coal having a sulfur content
meeting these criteria. If, and to the extent that, the Subsidiaries 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 would take approximately five years.
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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 will
be necessary for the GPU System to install and operate emission control
equipment as well as switch to slightly lower sulfur coal at some of the GPU
System's coal-fired plants in order to achieve compliance. To comply with
Title IV of the Clean Air Act, the GPU System expects to spend up to
$380 million (JCP&L - $58 million; Met-Ed - $145 million; and Penelec -
$177 million) by the year 2000 for air pollution control equipment, of which
approximately $179 million (JCP&L's Met-Ed's and Penelec's shares are
$16 million, $88 million and $75 million, respectively) has been spent as of
December 31, 1994. The capital costs of equipment are for the installation of
scrubbers, low Nox burner technology and particulate removal upgrades. The
capital costs of this equipment and the increased operating costs of the
affected stations are expected to be recoverable through the ratemaking
process but recovery is not assured. The first of two scrubbers was completed
at the Conemaugh station during 1994. The second scrubber is expected to be
installed by the end of November 1995. This action is part of the GPU
System's plans to comply with Phase I sulfur dioxide emission limitations. In
its January 1993 rate order, the PaPUC approved Met-Ed's request for
$24.5 million of current expenditures to be included in rate base representing
certain costs associated with the installation of scrubbers at the Conemaugh
station and other environmental compliance projects. The plan for the
Portland station is to meet its Phase I compliance obligation through the use
of sulfur dioxide emission allowances, including allowances allocated directly
to Portland station by the EPA and allowances resulting from the installation
of scrubbers at the Conemaugh station. Shawville station will require lower
sulfur coal and/or the purchase of emission allowances to meet its Phase I
requirements.
The GPU System's current strategy for Phase II compliance under Title IV
of the Clean Air Act is to evaluate the installation of scrubbers, the use of
fuel switching and allowances at the Keystone station and at the Homer City
Unit 3 station. Switching to lower sulfur coal and/or the purchasing of
allowances is currently planned for the Titus, Seward, Portland, Shawville and
Warren stations. Homer City Units 1 and 2 will use existing coal cleaning
technology. Additional control modifications are not expected to be necessary
for compliance with Title IV in Phase II at Conemaugh, Gilbert, Sayreville and
Werner stations.
The GPU System continues to reassess its options for compliance with the
Clean Air Act including those that may result from the continued development
of the emission trading allowance market. The GPU System'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 12 northeast states and the District of Columbia
identified as the Ozone Transport Region (OTR). Pennsylvania and New Jersey
are part of the OTR, 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 nitrogen oxide will be required to
implement Reasonably Available Control Technology (RACT) by May 31, 1995.
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This will affect the GPU System's generating stations. PaDER's RACT
regulations became effective in January 1994. Large coal-fired combustion
units are required to comply with a NOx emission limitation based on federal
RACT emission limitation requirements, or may elect to use a case-by-case
analysis to establish RACT requirements. In order to comply with these RACT
regulations, low NOx burners with separate overfire air are being installed at
the Titus, Portland and Conemaugh stations. NJDEP's RACT regulations became
effective in December 1993 and 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 NJDEP. A Memorandum of Understanding
(MOU) has been signed by the members of the Ozone Transport Commission (OTC).
This calls for inner and outer zones with seasonal nitrogen oxides emission
reductions of 65% and 55%, respectively by May 1, 1999. Met-Ed and Penelec
will spend an estimated $10 million and $50 million, respectively, to meet the
reductions set by the OTC. The MOU also calls for a 75% reduction by May
2003, unless modeling can be performed which shows this level of reduction is
unnecessary to achieve the Clean Air Act's 2005 National Ambient Air Quality
Standard (NAAQS) for ozone.
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
whether it is appropriate to regulate emissions of hazardous air pollutants
from electric utility steam generating units. However, the Homer City Coal
Processing Plant is being studied to determine if it is a major source of air
toxics.
Both the EPA and PaDER are questioning the attainment of NAAQS for sulfur
dioxide in the vicinity of the Chestnut Ridge Energy Complex (Homer City,
Conemaugh, Keystone and Seward generating stations). The Homer City,
Conemaugh and Keystone stations are jointly owned with nonaffiliated
utilities. 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 station,
which could result in material capital and additional operating expenditures.
The area around the Warren station has been designated as nonattainment
for sulfur dioxide. In early 1993, Penelec began a model evaluation study of
the area. The PaDER and EPA have approved the use of a nonguideline model
which is more representative than guideline models. A model evaluation study
is also being conducted at Shawville station. The results of this study will
be available in 1995.
The attainment issue has been taken into account as part of the design of
the Conemaugh station scrubbers. Met-Ed has initiated ambient air quality
modeling studies for its Portland and Titus stations that will take several
years to complete. While the results are uncertain, these studies may result
in a revised Pennsylvania State Implementation Plan (PaSIP) in order to attain
NAAQS for sulfur dioxide. If sulfur dioxide emissions need to be reduced to
meet the new PaSIP, Met-Ed will reevaluate its options available for Portland
and Titus stations.
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Based on the results of the studies pursuant to NAAQS, significant sulfur
dioxide reductions may be required at one or more of these stations which
could result in significant capital and additional operating expenditures.
Certain other environmental regulations limit the amount of particulate
matter emitted into the environment. The Subsidiaries 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 intended to reduce greenhouse gas emissions to 1990 levels
by the year 2000. The climate action plan relies heavily on voluntary action
by industry. On February 3, 1995, GPU joined 30 other electric utility
companies by signing an accord that is part of the Department of Energy
Climate Challenge Program. The GPU System's program is expected to avoid or
reduce the equivalent of 8 million tons of carbon dioxide emissions between
1995 and 2000.
Title IV of the Clean Air Act requires Phase I and Phase II affected
units to install a continuous emission monitoring system (CEMS) and quality
assure the data for sulfur dioxide, nitrogen oxides, opacity and volumetric
flow. In addition, Title VIII requires all affected sources to monitor carbon
dioxide emissions. Monitoring systems have been installed and certified on
JCP&L's, Met-Ed's and Penelec's Phase I and Phase II affected units as
required by EPA, NJDEP and PaDER regulations.
The PaDER has a CEMS enforcement policy to ensure consistent compliance
with air quality regulations under federal and state statutes. The CEMS
enforcement policy includes matters such as visible emissions, sulfur dioxide
emission standards, nitrogen oxide emissions and a requirement to maintain
certified continuous emission monitoring equipment. In addition, this policy
provides a mechanism for the payment of certain prescribed amounts to the
Pennsylvania Clean Air Fund (Clean Air Fund) for air pollutant emission
excesses or monitoring failures. With respect to the operation of Met-Ed's
and Penelec's generating stations for 1995, it is not anticipated that
payments to be made to the Clean Air Fund will be material in amount.
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.
The EPA has established Best Available Retrofit Technology (BART) sulfur
dioxide emission standards to be used for Penelec's Shawville and Seward
stations under the applicable stack height regulations. Dependent upon the
Chestnut Ridge Compliance Strategy and the results of the Shawville model
evaluation study mentioned above, lower sulfur coal purchases may be necessary
for compliance. Discussions with the EPA and PaDER regarding this matter are
continuing.
In 1988, the Environmental Defense Fund (EDF), the New Jersey
Conservation Foundation, the Sierra Club and Pennsylvanians for Acid Rain
Control requested that the NJDEP and the NJBPU seek to reduce sulfur
deposition in New Jersey, either by reducing emissions from both in-state and
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out-of-state sources, or by requiring that certain electricity imported into
New Jersey be generated from facilities meeting minimum emission standards.
JCP&L 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 in which it owns a 16.67% interest. In addition, coal-fired
generating facilities owned by Met-Ed and Penelec supply electric energy to
JCP&L and other New Jersey members of PJM. Hearings on the EDF petition were
held during 1989 and 1990, and the matter is pending before the NJDEP and the
NJBPU.
In New Jersey, where the bulk of the GPU System's oil-fired generating
capacity is located, NJDEP regulations establish that the maximum sulfur
content of No. 6 fuel oil may not exceed .3% for most of JCP&L's generating
stations and 1% for the balance. For No. 2 fuel oil, the sulfur content may
not exceed .2% for most of JCP&L's generating stations and .3% for the
balance.
In 1994, the Subsidiaries made capital expenditures of approximately
$91 million (JCP&L's, Met-Ed's and Penelec's shares are $9 million,
$36 million and $46 million, respectively) in response to environmental
considerations and have budgeted approximately $68 million (JCP&L's, Met-Ed's
and Penelec's shares are $24 million, $19 million and $25 million,
respectively) for this purpose in 1995. The incremental annual operating and
maintenance costs for such equipment is expected to be immaterial.
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." And, in 1994, results of a large-scale
epidemiology study of electric utility workers suggested a statistical
relationship between brain cancer and the class of workers who received the
highest exposure. However, these findings conflict with two earlier large-
scale studies that found no such relationship. Additional studies, which may
foster a better understanding of the subject, are presently underway.
Certain parties have alleged that the exposure to EMF associated with the
operation of transmission and distribution facilities will produce adverse
impacts upon public health and safety and upon property values. Furthermore,
regulatory actions under consideration by the NJDEP 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.
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The Subsidiaries cannot determine at this time what effect, if any, this
matter will have on their respective results of operation's and financial
position.
Residual Waste: PaDER residual waste regulations became effective in
July 1992. These regulations impose additional restrictions on operating
existing ash disposal sites and for siting future disposal sites and will
increase the costs of establishing and operating these facilities. The main
objective of these regulations is to prevent degradation of groundwater and to
abate any existing degradation.
The regulations requires, among other things, groundwater assessments of
landfills if existing groundwater monitoring indicates the possibility of
degradation. The assessments require the installation of additional
monitoring wells and the evaluation of one year's data. All of Penelec's
active landfills require assessments. If the assessments show degradation of
the groundwater, Penelec would be required to develop abatement plans.
Penelec's and Met-Ed's landfills had preliminary permit modification
applications submitted to the PaDER by July 1994, and complete permit
applications must be under evaluation by July 1997. Met-Ed's Portland and
Titus landfills have had preliminary assessments conducted which are currently
under review by the PaDER. Additional data will be collected and evaluated to
determine if degradation has occurred and if development of abatement plans is
necessary. The Titus station ash disposal site was upgraded in 1991 and now
meets all lined facility requirements. The Portland station ash disposal site
will require significant modifications under the new regulations. Various
alternatives for upgrading the site are being evaluated, including beneficial
uses of coal ash.
Other compliance requirements at Penelec that will be implemented in the
future include the lining of currently unlined disposal sites and storage
impoundments. Impoundments also will eventually require groundwater
monitoring systems and assessments of impact on groundwater. Groundwater
abatement may be necessary at locations where pollution problems are
identified. The removal of all the residual waste or "clean closed" will be
done at some impoundments to eliminate the need for future monitoring and
abatement requirements. Storage impoundments must have implemented
groundwater monitoring plans by 2002, but PaDER can require this at any time
prior to this date or defer full compliance beyond 2002 for some storage
impoundments at its discretion. Also being evaluated are the exercising of
beneficial use options authorized by the regulations and source reductions.
Preliminary groundwater assessment plans have also been conducted at
Met-Ed's Portland and Titus stations' industrial waste treatment impoundments
and are currently under review by the PaDER. Additional data will be
collected and evaluated to determine if abatement will be required. The
Portland station impoundments were upgraded in 1987 and meet the requirements
for lined impoundments. The Titus station impoundments will require
significant modifications by 2002.
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There are also a number of issues still to be resolved regarding certain
waivers related to Penelec's existing landfill and storage impoundment
compliance requirements. These waivers could significantly reduce the cost of
many of Penelec's facility compliance upgrades.
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 Subsidiaries have met all requirements of the TSCA
necessary to allow the continued use of equipment containing PCBs and have
taken substantive voluntary actions to reduce the amount of PCB containing
electrical equipment in the System.
Prior to 1953, the Subsidiaries owned and operated manufactured gas
plants in New Jersey and Pennsylvania. Wastes associated with the operation
and dismantlement of these gas manufacturing plants were disposed of both
on-site and off-site. Claims have been asserted against the Subsidiaries 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. JCP&L has identified 17 such sites to date. JCP&L
has entered into cost sharing agreements with New Jersey Natural Gas Company
and Elizabethtown Gas Company under which JCP&L is responsible for 60% of all
costs incurred in connection with the remediation of 12 of these sites. JCP&L
has entered into Administrative Consent Orders (ACOs) with the NJDEP for seven
of these sites and has entered into Memoranda of Agreement (MOAs) with the
NJDEP for eight of these sites. JCP&L anticipates entering into MOAs for the
remaining sites. The ACOs specify the agreed upon obligations of both JCP&L
and the NJDEP for remediation of the sites. The MOAs afford JCP&L greater
flexibility in the schedule for investigation and remediation of sites.
At December 31, 1994, JCP&L has an estimated environmental liability of
$32 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, JCP&L 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: JCP&L 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 JCP&L is required to utilize different remediation methods, the
costs could be materially in excess of $60 million.
In December 1994, the NJBPU issued an order approving the recovery of
future manufactured gas plant remediation costs through a Remediation
Adjustment Clause which will be filed simultaneously with JCP&L's LEAC when
remediation expenditures exceed prior collections. The NJBPU decision
provides for interest to be credited to customers retroactive to June 1993,
until the overrecovery is eliminated and for future costs to be amortized over
seven years with interest. At December 31, 1994, JCP&L has collected from
customers $3.3 million in excess of expenditures of $13.6 million. JCP&L is
pursuing reimbursement of these remediation costs from its insurance carriers.
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In November 1994, JCP&L filed a complaint with the New Jersey Superior
Court against several of its insurance carriers, relative to these
manufactured gas plant sites. JCP&L has requested the Court to order the
insurance carriers to reimburse JCP&L for all amounts it has paid, or may be
required to pay, in connection with the remediation of the sites.
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. Pennsylvania and New
Jersey have enacted legislation giving similar authority to the PaDER and the
NJDEP, respectively. Because of the nature of the Subsidiaries' business,
various by-products and substances are produced and/or handled that are
classified as hazardous under one or more of these statutes. The Subsidiaries
generally provide 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 GPU System companies have been notified by the EPA and state
environmental authorities that they are 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 13 hazardous and/or toxic
waste sites (including those described below).
JCP&L MET-ED PENELEC GPUN GPU TOTAL
PRPs 7 5 3 1 1 13*
* In some cases, the Subsidiaries are named separately for the same site.
In addition, the GPU System companies have been requested to supply
information to the EPA and state environmental authorities on several other
sites for which the GPU System companies have not as yet been named as PRPs.
Met-Ed and Penelec have also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
In January 1995, the EPA informed GPU that it has been identified as a
PRP at the Dover Gas Light Superfund Site in Dover, Delaware. This site was
formerly owned by Associated Gas & Electric (AGE), a corporate predecessor of
GPU. GPU is currently investigating this matter to determine what, if any,
liability exists. The EPA identified GPU along with four other previously
named PRPs in this matter.
The Subsidiaries received notification in 1986 from the EPA that they are
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. JCP&L, Met-Ed, Penelec
and Saxton are alleged to have contributed, in the aggregate, approximately
2.7% (JCP&L's, Met-Ed's, Penelec's and Saxton's shares are 1.81%, .60%, .08%
and .23%, respectively) 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
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in the ROD at approximately $63 million, for which all responsible parties
would be jointly and severally liable. A tentative agreement among all
parties has been reached. Final documents are being prepared by the EPA.
The EPA has initiated a suit under CERCLA and other laws for the initial
cleanup of hazardous materials deposited at a waste disposal site at Harper
Drive, Millcreek Township, Pennsylvania (Millcreek site). Penelec is one of
over 50 PRPs at this site. Penelec does not know whether its insurance
carriers will assume the responsibility to defend and indemnify it in
connection with this matter.
Two lawsuits involving property owners at or near the Millcreek site have
been filed against Penelec and other PRPs. Penelec's insurance carriers are
defending these actions but may not provide coverage in the event compensatory
damages are awarded. In addition, claims have also been made for punitive
damages which may not be covered by insurance.
Penelec has been named as a PRP along with over 1,000 other PRPS at the
Jack's Creek/Sitken site in Mifflin County, Pennsylvania. A PRP group has
been formed and is working on the issues presented at the site.
Penelec, together with 24 others, has been named as a third party
defendant in an action commenced under the CERCLA by the EPA in the
U.S. District Court in Ohio. The EPA is seeking to recover costs for the
cleanup of hazardous and toxic materials disposed at the New Lyme landfill
site in Ashtabula, Ohio. Penelec, together with 22 others, has also been
named as a third party defendant in an action under CERCLA by the State of
Ohio seeking to recover costs it has incurred and will incur in the future at
the New Lyme landfill site.
Met-Ed, together with 35 others, has been named as a third party
defendant in an action commenced under CERCLA by the EPA in the U.S. District
Court for the Eastern District of Pennsylvania. The EPA is seeking to recover
response costs for hazardous materials disposed at the Mabry/Oswald Site in
Upper Macungie and Longswamp Townships, Pennsylvania. Met-Ed is awaiting
Court approval of a buyout settlement offer.
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 GPU System
companies.
The Corporation and the Subsidiaries are 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 but realizes recovery is not assured.
FRANCHISES AND CONCESSIONS
JCP&L 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
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with its conduits, cables and equipment, where necessary, for its electric
operation. JCP&L 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. JCP&L holds a FERC license
expiring in 2013 authorizing it to operate and maintain the Yards Creek pumped
storage hydroelectric station in which JCP&L has a 50% ownership interest.
Met-Ed has the necessary nonexclusive primary franchise (charter rights
granted by the state) and with minor and unimportant exceptions, the necessary
secondary franchises (consents by municipalities to occupy the streets), free
from unduly burdensome restrictions and perpetual as to time, to enable it to
maintain and operate its existing facilities for the transmission and supply
of electricity in the various municipalities in which these services are now
supplied, except that (a) the right to maintain and operate these facilities
in the streets of certain of the municipalities, although good, rests as
against those municipalities on estoppel and not on a grant of a secondary
franchise and (b) the secondary franchise granted by the Borough of Boyertown
contains a provision that the Borough shall have the right at any time to
purchase the electric system in the Borough at a valuation to be fixed by
appraisers. Met-Ed holds a FERC license expiring in 2014 for the continued
operation and maintenance of the York Haven hydroelectric project.
The electric franchise rights of Penelec which are generally
nonexclusive, consist generally of (a) charter rights to furnish electric
service, and (b) certificates of public convenience and/or "grandfather
rights," which allow Penelec to furnish electric service in a specified city,
borough, town or township or part thereof. Such electric franchises are
unlimited as to time, except in a few relatively minor cases concerning the
rights mentioned above. Penelec holds a license from the FERC, which expires
in 2002, for the continued operation and maintenance of the Piney
hydroelectric project. In addition, Penelec and the Cleveland Electric
Illuminating Company hold a license expiring in 2015 for the Seneca Pumped
Storage Hydroelectric station in which Penelec has a 20% undivided interest.
For the same station, Penelec and the Cleveland Electric Illuminating Company
hold a Limited Power Permit issued by the Pennsylvania Water and Power
Resources Board which is unlimited as to time. For purposes of the Homer city
station, Penelec and NYSEG hold a Limited Power Permit issued by the
Pennsylvania Water and Power Resources Board which expires in 2017, but is
renewable by the permittees until they have recovered all capital invested by
them in the project. Penelec also holds a Limited Power Permit issued by the
Pennsylvania Water and Power Resources Board for its Shawville station which
expires in 2003, but is renewable by Penelec until it has recovered all
capital invested in the project.
EMPLOYEE RELATIONS
At February 28, 1995, the GPU System had 10,534 full-time employees
(JCP&L's, Met-Ed's, Penelec's and all other companies' shares are 3,050,
2,028, 2,993 and 2,463, respectively). The nonsupervisory production and
maintenance employees of the Subsidiaries and certain of their nonsupervisory
clerical employees are represented for collective bargaining purposes by local
unions of the International Brotherhood of Electrical Workers (IBEW) at JCP&L,
Met-Ed and Penelec and the Utility Workers Union of America (UWUA) at Penelec.
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Penelec's five-year contracts with the IBEW and UWUA expire on May 14,
1998 and June 30, 1998, respectively. Met-Ed's three-year contract with the
IBEW expires on April 30, 1997. JCP&L's two-year contract with the IBEW
expires on October 31, 1996.
ITEM 2. PROPERTIES.
Generating Stations
At December 31, 1994, the generating stations of the GPU System had an
aggregate effective capability of 6,651,000 net kilowatts (KW), as follows:
Name of Year of Net KW
Station Subsidiary Installation (Summer)
COAL-FIRED:
Homer City(a) Penelec 1969-1977 942,000
Shawville Penelec 1954-1960 597,000
Portland Met-Ed 1958-1962 401,000
Keystone(b) JCP&L 1967-1968 283,000
Conemaugh(c) Met-Ed 1970-1971 280,000
Titus Met-Ed 1951-1953 241,000
Seward Penelec 1950-1957 196,000
Warren Penelec 1948-1949 82,000
NUCLEAR:
TMI-1(d) All 1974 786,000
Oyster Creek(e) JCP&L 1969 610,000
GAS/OIL-FIRED:
(gas or oil)
Sayreville(f) JCP&L 1930-1958 229,000
Gilbert JCP&L 1930-1949 117,000
Combustion
(gas or oil)
Turbines(g) ALL 1960-1989 1,160,000
Werner (oil) JCP&L 1953 58,000
Other(h) ALL 1968-1977 328,000
Hydroelectric(i) Met-Ed/Penelec 1905-1969 64,000
PUMPED STORAGE:(j)
Yards Creek JCP&L 1965 190,000
Seneca Penelec 1969 87,000
TOTAL 6,651,000
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Aggregate Effective Capability by Subsidiary
Net KW
(Summer) (Winter)
JCP&L 2,765,000 3,130,000
Met-Ed 1,602,000 1,703,000
Penelec 2,284,000 2,365,000
TOTAL 6,651,000 7,198,000
(a) Represents Penelec's undivided 50% interest in the station.
(b) Represents JCP&L's undivided 16.67% interest in the station.
(c) Represents Met-Ed's undivided 16.45% interest in the station.
(d) Jointly owned by JCP&L, Met-Ed and Penelec in percentages of 25%, 50% and
25%, respectively.
(e) Effective January 17, 1995, the Oyster Creek station was rerated at
619 MW.
(f) Effective February 1, 1994, 84,000 KW of capability were retired.
(g) JCP&L - 762,000 KW, Met-Ed - 266,000 KW and Penelec 132,000 KW.
(h) Consists of internal combustion and combined cycle units (JCP&L - 320,000
KW, Met-Ed - 2,000 KW and Penelec - 6,000 KW). Effective January 1,
1995, JCP&L retired 30,000 KW at its Gilbert station.
(i) Consists of Met-Ed's York Haven facility (19,000 KW) and Penelec's Piney
(27,000 KW) and Deep Creek facilities (18,000 KW).
(j) Represents the Subsidiaries' undivided interests in these stations which
are net users rather than net producers of electric energy.
All the GPU System's coal-fired, hydroelectric (other than the Deep Creek
station) and pumped storage stations (other than the Yards Creek station) are
located in Pennsylvania. The TMI-1 nuclear station is also located in
Pennsylvania. The GPU System's gas-fired and oil-fired stations (other than
some combustion turbines in Pennsylvania), the Yards Creek pumped storage
station and the Oyster Creek nuclear station are located in New Jersey. The
Deep Creek hydroelectric station is located in Maryland.
Substantially all of the Subsidiaries' properties are subject to the lien
of their respective first mortgage bond indentures.
The peak loads of the GPU System and its Subsidiaries were as follows:
(In KW)
Company Date Peak Load
GPU July 9, 1993 8,533,000
JCP&L July 9, 1993 4,564,000
Met-Ed July 20, 1994 2,000,000
Penelec Jan. 18, 1994 2,514,000
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Nonutility Generation Facilities
At December 31, 1994, EI had ownership interests through special-purpose
subsidiaries in natural gas-fired cogeneration facilities with an aggregate
capability of 932,000 KW as follows:
Name of Year of EI Equity
Facility Location Installation Total KW Interest (KW)
Selkirk NY 1992/94 350,000 70,000
Lake* FL 1993 112,000 56,000
Pasco* FL 1993 112,000 56,000
Onondaga* NY 1994 80,000 40,000
Syracuse* NY 1992 80,000 26,400
Marcal* NJ 1989 65,000 32,500
Ada* MI 1991 29,000 290
Camarillo* CA 1988 27,000 13,500
Chino* CA 1987 27,000 13,500
FPB CA 1983 26,000 7,800
Berkeley* CA 1988 24,000 12,000
932,000 327,990
* EI has operating responsibility for these plants.
Transmission and Distribution System
At December 31, 1994, the GPU System owned the following:
GPU System
JCP&L Met-Ed Penelec Total
Transmission and Distribution
Substations 297 295 469 1,061
Aggregate Installed Transformer
Capacity of Substations
(in kilovoltamperes - KVA) 22,039,652 11,645,925 16,012,505 49,698,082
Transmission System:
Lines (In Circuit Miles):
500 KV 18 188 235 441
345 KV - - 149 149
230 KV 570 383 650 1,603
138 KV - 3 11 14
115 KV 232 356 1,325 1,913
69 KV, 46 KV and 34.5 KV 1,752 478 364 2,594
Total 2,572 1,408 2,734 6,714
Distribution System:
Line Transformer Capacity (KVA) 9,450,169 5,528,937 6,077,980 21,057,086
Pole Miles of Overhead Lines 15,519 12,613 22,436 50,568
Trench Miles of Underground
Cable 6,484 1,943 1,752 10,179
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ITEM 3. LEGAL PROCEEDINGS.
Reference is made to Nuclear Facilities - TMI-2, Rate Proceedings and
Environmental Matters under Item 1 and to Note 1 to GPU's consolidated
financial statements contained in Item 8 for a description of certain pending
legal proceedings involving the GPU System.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
All of JCP&L's, Met-Ed's and Penelec's outstanding common stock is owned
by GPU. During 1994, JCP&L, Met-Ed and Penelec paid GPU $100 million, $35
million and $65 million in dividends, respectively, on their common stock.
In accordance with the Subsidiaries' mortgage indentures, as
supplemented, the balances of retained earnings at December 31, 1994 that is
restricted as to the payment of dividends on their common stock are as
follows:
JCP&L - $1.7 million Met-Ed - $3.4 million Penelec - $10 million
Stock Trading
General Public Utilities Corporation is listed as GPU on the New York
Stock Exchange. On February 28, 1995, there were approximately 48,000
registered holders of GPU common stock.
Dividends
GPU common stock dividend declaration dates are the first Thursdays of
April, June, October and December. Dividend payment dates fall on the last
Wednesdays of February, May, August and November. Dividend declarations and
quarterly stock price ranges for 1994 and 1993 are set forth below.
Common Stock
Dividends Declared Price Ranges*
1994 1993
1994 1993 Quarter High/Low High/Low
April $.45 $.40 First $30 7/8 $27 5/8 $30 1/4 $25 3/4
June .45 .425 Second 31 5/8 26 32 3/8 28 5/8
October .45 .425 Third 27 1/2 23 3/4 34 3/4 31 5/8
December .45 .425 Fourth 26 7/8 24 34 28 3/4
* Based on New York Stock Exchange Composite Transactions as reported in the
Wall Street Journal.
ITEM 6. SELECTED FINANCIAL DATA.
See page F-1 for references to each registrant's Selected Financial Data
required by this item.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
See page F-1 for references to each registrant's 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 references to each registrant's 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.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Identification of Directors
Information regarding GPU's directors is incorporated by reference to
pages 2 through 6 of GPU's Proxy Statement for the 1995 Annual Meeting of
Stockholders. The current directors of JCP&L, Met-Ed/Penelec, their ages,
positions held and business experience during the past five years are as
follows:
Year First
Name Age Position Elected
JCP&L:
J. R. Leva (a) 62 Chairman of the Board 1986
and Chief Executive Officer
D. Baldassari (b) 45 President 1982
R. C. Arnold (c) 57 Director 1989
J. G. Graham (d) 56 Vice President and Chief 1986
Financial Officer
M. P. Morrell (e) 46 Vice President 1993
G. E. Persson (f) 63 Director 1983
D. W. Myers (g) 50 Vice President and Comptroller 1994
S. C. Van Ness (h) 61 Director 1983
S. B. Wiley (i) 65 Director 1982
Year First Elected
Met-Ed/Penelec: Met-Ed Penelec
J. R. Leva (a) 62 Chairman of the Board 1992 1992
and Chief Executive Officer
F. D. Hafer (j) 53 President 1978 1994
J. G. Graham (d) 56 Vice President and 1986 1986
Chief Financial Officer
J. F. Furst (k) 48 Vice President 1994 1994
G. R. Repko (l) 49 Vice President 1994 1993
R. S. Zechman (m) 51 Vice President 1994 1994
R. C. Arnold (c) 57 Director 1989 1989
(a) Mr. Leva is also Chairman, President, Chief Executive Officer and a
director of GPUSC; Chairman of the Board and a director of GPUN; and
Chairman and a director of Energy Initiatives, Inc. (EI), and EI Power,
Inc. (EI Power), all subsidiaries of GPU. Prior to 1992, Mr. Leva
served as President of JCP&L since 1986. Mr. Leva is also a director of
Chemical Bank, NJ, N.A., Princeton Bank and Trust Co., N.A. and
Utilities Mutual Insurance Company.
(b) Mr. Baldassari was elected a director of GPUSC and GPUN in 1992. Prior
to that, Mr. Baldassari served as Vice President - Materials & Services
of JCP&L since 1990. He also served as Vice President - Rates of JCP&L
from 1982 to 1990. Mr. Baldassari is also a director of First Morris
Bank of Morristown, NJ.
(c) Mr. Arnold was elected Executive Vice President-Power Supply of GPUSC in
1990. He is also a director of GPUSC.
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(d) Mr. Graham was elected Vice President of GPU in 1989. He is also
Executive Vice President, Chief Financial Officer and a director of
GPUSC; Vice President and Chief Financial Officer of GPUN; and a
director of EI and EI Power.
(e) Mr. Morrell became Vice President - Regulatory and Public Affairs in
1994. Prior to 1993, Mr. Morrell served as Vice President of GPU since
1989.
(f) Mrs. Persson is owner and President of Business Dynamics Associates of
Red Bank, 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. Myers, prior to 1994, served as Vice President and Treasurer of GPU,
GPUSC, JCP&L and Met-Ed/Penelec since 1993. He served as Vice President
and Comptroller of GPUN from 1986 to 1993.
(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, 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 of Morristown, NJ.
(j) Mr. Hafer is also a director of GPUSC and GPUN and a director of
Meridian Bancorp of Reading, PA and Utilities Mutual Insurance Company.
(k) Mr. Furst was elected Vice President - Rates & Marketing of Met-
Ed/Penelec in 1994. Prior to that, he served as Vice President -
Customer Services of Penelec since 1984.
(l) Mr. Repko was elected Vice President - Customer Services and Operations
of Met-Ed/Penelec in 1994. Prior to that, he served as Vice President -
Division Operations of Penelec from 1986 to 1993.
(m) Mr. Zechman was elected Vice President-Administration and Finance of
Met-Ed/Penelec in 1994. Prior to that, he served as Vice President -
Administrative Services of Met-Ed since 1992 and as Vice President -
Human Resources of Met-Ed from 1990 to 1992.
The directors of the Subsidiary companies are elected at their
respective annual meeting of stockholders to serve until the next meeting of
stockholders and until their respective successors are duly elected and
qualified. There are no family relationships among the directors of the
Subsidiary companies.
43
<PAGE>
Identification of Executive Officers
The executive officers of GPU, JCP&L and Met-Ed/Penelec, their ages,
positions held and business experience during the past five years are as
follows:
Year First
Name Age Position Elected
GPU:
J. R. Leva (a) 62 Chairman, President and Chief 1992
Executive Officer
I. H. Jolles (b) 56 Senior Vice President and General 1990
Counsel
J. G. Graham (c) 56 Senior Vice President and Chief 1987
Financial Officer
F. A. Donofrio (d) 52 Vice President, Comptroller and 1985
Chief Accounting Officer
P. C. Mezey (e) 55 Senior Vice President, GPUSC 1992
T. G. Howson (f) 46 Vice President and Treasurer 1994
M. A. Nalewako (g) 60 Secretary 1988
P. R. Clark (h) 64 President, GPUN 1983
R. L. Wise (i) 51 President, Fossil Generation-GPUSC 1994
F. D. Hafer (j) 53 President, Met-Ed/Penelec 1994
D. Baldassari (k) 45 President, JCP&L 1992
B. L. Levy (l) 39 President and Chief Executive 1991
Officer, EI
R. C. Arnold (m) 57 Executive Vice President, GPUSC 1990
JCP&L:
J. R. Leva (a) 62 Chairman of the Board and Chief 1992
Executive Officer
D. Baldassari (k) 45 President 1992
C. R. Fruehling 59 Vice President - Engineering and 1982
Operations
J. G. Graham (c) 56 Vice President and Chief 1987
Financial Officer
E. J. McCarthy (n) 56 Vice President - Customer Operations 1982
and Sales
M. P. Morrell (o) 46 Vice President - Regulatory 1993
and Public Affairs
T. G. Howson (f) 46 Vice President and Treasurer 1994
D. W. Myers (p) 50 Vice President - Operations Support 1994
and Comptroller
R. J. Toole 52 Vice President - Generation 1990
J. J. Westervelt (q) 54 Vice President - Human Resources 1982
and Corporate Services
R. S. Cohen 52 Secretary and Corporate Counsel 1986
44
<PAGE>
<TABLE>
Year First Elected
Name Age Position Met-Ed Penelec
<CAPTION>
<S> <C> <C> <C> <C> <C>
Met-Ed/Penelec:
J. R. Leva (a) 62 Chairman of the Board and 1992 1992
Chief Executive Officer
F. D. Hafer (j) 53 President 1986 1994
J. G. Graham (c) 56 Vice President and Chief
Financial Officer 1987 1987
J. F. Furst (r) 48 Vice President - Rates and 1994 1984
Marketing
T. G. Howson (f) 46 Vice President and Treasurer 1994 1994
G. R. Repko (s) 49 Vice President - Customer 1994 1986
Services and Operations
R. J. Toole 52 Vice President - Generation 1989 -
J. G. Herbein (t) 56 Vice President - Generation - 1982
R. S. Zechman (u) 51 Vice President - Administration 1990 1994
and Finance
D. L. O'Brien 52 Comptroller 1981 1994
W. A. Boquist II (v) 47 Vice President - Legal Services 1994 1994
C. B. Snyder (w) 49 Vice President - Public Affairs 1994 1994
W. C. Matthews II (x) 42 Secretary 1994 1990
<FN>
(a) See Note (a) on page 42.
(b) Mr. Jolles was elected Senior Vice President and General Counsel of GPU
in 1990. He is also Executive Vice President, General Counsel and a
director of GPUSC since 1990 and a director of EI and EI Power since
1994.
(c) See Note (d) on page 43.
(d) Mr. Donofrio was elected Vice President of GPU in 1989. He is also
Senior Vice President - Financial Controls of GPUSC and a director of
GPUSC since 1987.
(e) Mr. Mezey was elected Senior Vice President - System Services of GPUSC
in 1992 and is a director of EI and EI Power. He previously served as
Vice President of GPUSC from January 1991 through March 1992 and
President of EI from February 1990 through December 1991.
(f) Mr. Howson is also Vice President and Treasurer of GPUSC and GPUN.
Prior to that, Mr. Howson served as Vice President - Materials, Services
and Regulatory Affairs and a director for JCP&L since 1992. Prior to
that, he served as Vice President - Corporate Strategic Planning for
GPUSC since 1989.
(g) Mrs. Nalewako was also elected Secretary of GPUSC in 1988. She is also
Assistant Secretary of GPUN, JCP&L and Met-Ed/Penelec.
(h) Mr. Clark is also a director of GPUSC since 1986.
45
<PAGE>
(i) Mr. Wise is also a director of GPUSC, GPUN, EI, and EI Power. Prior to
1994, he served as President and a director of Penelec since December
1986. Mr. Wise is also a director of U.S. Bancorp and U.S. National
Bank of Johnstown, PA.
(j) See Note (j) on page 43.
(k) See Note (b) on page 42.
(l) Mr. Levy is also a director of EI since 1991 and President and Chief
Executive Officer and a director of EI Power. Prior to 1991, he served
as Vice President - Business Development of EI since 1985.
(m) See Note (c) on page 42.
(n) Mr. McCarthy became Vice President - Customer Operations and Sales in
1994. Prior to that, he served as Vice President - Customer Services of
JCP&L since 1982.
(o) See Note (e) on page 43.
(p) See Note (g) on page 43.
(q) Mr. Westervelt became Vice President - Human Resources and Corporate
Services in 1994. Prior to that, he served as Vice President - Human
Resources of JCP&L since 1982.
(r) See note (k) on page 43.
(s) See note (l) on page 43.
(t) Mr. Herbein was elected Vice President - Generation of Penelec in 1992.
He was Vice President, Station Operations at Penelec from 1982 to 1992.
(u) See note (m) on page 43.
(v) Mr. Boquist also served as Corporate Counsel and Secretary of Met-Ed
from 1992 to 1994 and Assistant Secretary of Met-Ed from 1988 to 1992.
(w) Mrs. Snyder also served as Regional Director of Met-Ed from April 1991
to July 1994. She was Divisional Director from October 1990 to March
1991 and Assistant Comptroller of Met-Ed from January 1989 to September
1990.
(x) Mr. Matthews was elected Secretary of Met-Ed/Penelec in 1994. Prior to
that, he served as Corporate Counsel and Secretary of Penelec from
November 1990 to June 1994.
</FN>
</TABLE>
The executive officers of the GPU System Companies are elected each year
by their respective Boards of Directors at the first meeting of the Board held
following the annual meeting of stockholders. Executive officers hold office
until the next meeting of directors following the annual meeting of
stockholders and until their respective successors are duly elected and
qualified. There are no family relationships among the executive officers.
46
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item with respect to GPU is
incorporated by reference to pages 9 through 18 of GPU's Proxy Statement for
the 1995 Annual Meeting of Stockholders. The following table sets forth
remuneration paid to the Chief Executive Officer and the four most highly
compensated executive officers of JCP&L, Met-Ed and Penelec for the year ended
December 31, 1994.
As discussed in Item 1 under Corporate Realignment, the managements of
Met-Ed and Penelec were combined in 1994. Accordingly, the amounts shown
below represent the aggregate remuneration paid to such executive officers by
Met-Ed and Penelec during 1994. In addition, Mr. Toole's remuneration
includes an amount paid by Met-Ed and JCP&L during the year.
Remuneration of Executive Officers
SUMMARY COMPENSATION TABLE
Long-Term
Compensation
Annual Compensation Awards
Other
Name and Annual Restricted All Other
Principal Compen- Stock/Unit Compen-
Position Year Salary Bonus sation(1) Awards(2) sation
J. R. Leva
Chairman of the Board
and Chief Executive
Officer (3) (3) (3) (3) (3) (3)
JCP&L:
D. Baldassari 1994 $271,250 $62,000 $ 17 $39,188 $16,823(4)
President 1993 253,750 57,000 - 41,850 15,436
1992 211,480 50,000 - 35,100 14,177
M. P. Morrell 1994 150,175 27,300 804 15,936 6,000(5)
Vice President - 1993 144,200 26,000 1,932 15,500 5,768
Regulatory and 1992 137,500 24,900 1,166 14,560 5,267
Public Affairs
D. W. Myers 1994 142,125 29,300 - 13,716 5,685(6)
Vice President - 1993 135,125 22,400 - 13,950 5,405
Operations Support 1992 129,925 25,000 - 14,300 5,197
and Comptroller
E. J. McCarthy 1994 136,267 26,100 - 13,324 5,451(7)
Vice President - 1993 125,825 22,500 - 13,020 5,033
Customer Operations 1992 121,125 19,100 - 13,000 4,845
and Sales
R. S. Cohen 1994 127,225 22,800 - 12,018 5,089(8)
Secretary and 1993 122,500 19,500 - 12,710 4,902
Corporate Counsel 1992 117,950 18,600 - 13,000 4,718
47
<PAGE>
Met-Ed/Penelec:
F. D. Hafer 1994 275,250 77,000 - 39,841 19,733(9)
President 1993 258,250 50,000 - 41,850 18,975
1992 246,250 40,000 - 41,600 18,375
J. G. Herbein 1994 148,025 34,000 - 14,238 9,861(10)
Vice President - 1993 142,200 25,900 - 15,190 15,338
Generation 1992 136,500 22,100 743 15,340 10,507
G. R. Repko 1994 142,225 32,000 - 14,630 5,689(11)
Vice President - 1993 129,100 24,200 - 13,330 5,164
Customer Services 1992 120,900 19,200 - 13,520 4,836
and Operations
R. J. Toole 1994 142,125 30,100 - 13,716 5,685(12)
Vice President - 1993 136,750 21,000 - 13,950 5,470
Generation 1992 131,875 17,100 - 13,520 5,275
R. S. Zechman 1994 132,500 31,000 - 13,324 5,300(13)
Vice President - 1993 118,750 17,000 - 12,400 4,750
Administration 1992 113,750 12,500 - 12,480 4,550
and Finance
D. L. O'Brien 1994 129,750 23,000 548 12,018 1,238(14)
Comptroller 1993 124,750 16,500 1,161 12,400 1,187
1992 119,750 12,500 598 13,000 1,137
(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 1994
(dividends are paid or accrued on these restricted shares/units and
reinvested):
Aggregate Aggregate
Shares/Units $ Value
JCP&L:
D. Baldassari 5,000 $134,302
M. P. Morrell 2,520 65,284
D. W. Myers 2,285 59,192
E. J. McCarthy 2,190 56,588
R. S. Cohen 2,140 55,202
Met-Ed/Penelec:
F. D. Hafer 7,075 182,129
J. G. Herbein 2,535 65,444
G. R. Repko 2,270 58,724
R. J. Toole 2,355 60,721
R. S. Zechman 2,105 54,439
D. L. O'Brien 2,090 53,981
48
<PAGE>
(3) As noted above, Mr. Leva is Chairman and Chief Executive Officer of
General Public Utilities Corporation and its affiliates. Mr. Leva is
compensated by GPUSC for his overall service on behalf of the GPU System
and accordingly is not compensated directly by the other subsidiary
companies for his services. Information with respect to Mr. Leva's
compensation is included on pages 13 through 15 in GPU's 1995 Proxy
Statement, which are incorporated herein by reference.
(4) Consists of employer matching contributions under the Savings Plan
($6,000), matching contributions under the non-qualified deferred
compensation plan ($4,850), the benefit of interest-free use of the non-
term portion of employer paid premiums for split-dollar life insurance
($5,956) and above-market interest accrued on the retirement portion of
deferred compensation ($17).
(5) Consists of employer matching contributions under the Savings Plan
($6,000).
(6) Consists of employer matching contributions under the Savings Plan
($5,685).
(7) Consists of employer matching contributions under the Savings Plan
($5,451).
(8) Consists of employer matching contributions under the Savings Plan
($5,089).
(9) Consists of employer matching contributions under the Savings Plan
($6,000), matching contributions under the non-qualified deferred
compensation plan ($5,010), the benefit of interest-free use of the non-
term portion of employer paid premiums for split-dollar life insurance
($8,630) and above-market interest accrued on the retirement portion of
deferred compensation ($93).
(10) Consists of employer matching contributions under the Savings Plan
($4,661) and above-market interest accrued on the retirement portion of
deferred compensation ($5,200).
(11) Consists of employer matching contributions under the Savings Plan
($5,689).
(12) Consists of employer matching contributions under the Savings Plan
($5,685).
(13) Consists of employer matching contributions under the Savings Plan
($5,300).
(14) Consists of employer matching contributions under the Savings Plan
($1,238).
Note: The split-dollar life insurance amounts reported in the "All Other
Compensation" column are equal to the present value of the interest-free use
of the current year employer paid premium to the projected date the premiums
will be refunded to the Corporation. Prior years' amounts have been restated.
49
<PAGE>
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Estimated future payouts
under nonstock price-
based plans(1)
Performance
Number of or other
shares, period until
units or maturation Target
Name other rights or payout ( $ or #)
JCP&L:
D. Baldassari 1,500 5 years $35,438
M. P. Morrell 610 5 years $14,411
D. W. Myers 525 5 years $12,403
E. J. McCarthy 510 5 years $12,049
R. S. Cohen 460 5 years $10,868
Met-Ed/Penelec:
F. D. Hafer 1,525 5 years $36,028
J. G. Herbein 545 5 years $12,876
G. R. Repko 560 5 years $13,230
R. J. Toole 525 5 years $12,403
R. S. Zechman 510 5 years $12,049
D. L. O'Brien 460 5 years $10,868
(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 1994 multiplied by the 1994
year-end market value of $26.25. 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
None of the named executive officers in the Summary Compensation Table
has an employment contract. The compensation of executive officers is
determined from time to time by the Personnel & Compensation Committee of the
GPU Board of Directors.
50
<PAGE>
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 non-qualified plans providing that the portion of a participant's
pension benefits which, 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.
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 1995 (computed
on a single life annuity basis) to persons in specified salary and years of
service classifications:
<TABLE>
ESTIMATED ANNUAL RETIREMENT BENEFITS
BASED UPON CAREER AVERAGE COMPENSATION(2) (3) (4)
<CAPTION>
(1995 Retirement)
Career
Average 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years 40 years
Compensation(1) of Service of Service of Service of Service of Service of Service of Service
<S> <C> <C> <C> <C> <C> <C> <C>
$ 50,000 $ 9,410 $ 14,114 $ 18,819 $ 23,524 $ 28,229 $ 32,934 $ 37,356
100,000 19,410 29,114 38,819 48,524 58,229 67,934 76,956
150,000 29,410 44,114 58,819 73,524 88,229 102,934 116,556
200,000 39,410 59,114 78,819 98,524 118,229 137,934 156,156
250,000 49,410 74,114 98,819 123,524 148,229 172,934 195,756
300,000 59,410 89,114 118,819 148,524 178,229 207,934 235,356
350,000 69,410 104,114 138,819 173,524 208,229 242,934 274,956
400,000 79,410 119,114 158,819 198,524 238,229 277,934 314,556
450,000 89,410 134,114 178,819 223,524 268,229 312,934 354,156
500,000 99,410 149,114 198,819 248,524 298,229 347,934 393,756
</TABLE>
(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: JCP&L:
Messrs. Baldassari - $158,239; Morrell - $122,625; Myers - $141,733;
McCarthy - $120,292; Cohen - $107,124 and Met-Ed/Penelec: Messrs.
Hafer - $238,121; Herbein - $134,432; Repko - $121,220; Toole -
$121,095; Zechman - $103,287; O'Brien - $115,985.
51
<PAGE>
(2) Years of Creditable Service: JCP&L: Messrs. Baldassari - 22 years;
Morrell - 23 years; Myers - 14 years; McCarthy - 34 years; Cohen - 26
years and Met-Ed/Penelec: Messrs. Hafer - 32 years; Herbein - 29 years;
Repko - 28 years; Toole - 28 years; Zechman - 25 years; O'Brien -
22 years.
(3) Based on an assumed retirement at age 65 in 1995. To reduce the above
amounts to reflect a retirement benefit assuming a continual annuity to
a surviving spouse equal to 50 percent of the annuity payable at
retirement, multiply the above benefits by 90 percent. 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 percent of the average
compensation received during the last three years prior to retirement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item for GPU is incorporated by
reference to page 8 of the GPU Proxy Statement for the 1995 Annual Meeting of
Stockholders.
All of the outstanding shares of JCP&L (15,371,270), Met-Ed (859,500)
and Penelec (5,290,596) common stock are owned beneficially and of record by
the Company's parent, General Public Utilities Corporation, 100 Interpace
Parkway, Parsippany, NJ 07054.
The following table sets forth, as of February 1, 1995, the beneficial
ownership of equity securities of each of the Company's directors and each of
the executive officers named in the Company's 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 Class Beneficial Ownership (1)
JCP&L:
J. R. Leva GPU Common Stock 4,170 Shares - Direct
GPU Common Stock 100 Shares - Indirect
J. G. Graham GPU Common Stock 6,626 Shares - Direct
GPU Common Stock 1,480 Shares - Indirect
R. C. Arnold GPU Common Stock 6,003 Shares - Direct
D. Baldassari GPU Common Stock 1,009 Shares - Direct
R. S. Cohen GPU Common Stock 970 Shares - Direct
E. J. McCarthy GPU Common Stock 958 Shares - Direct
M. P. Morrell GPU Common Stock 1,071 Shares - Direct
D. W. Myers GPU Common Stock 959 Shares - Direct
G. E. Persson GPU Common Stock None
S. C. Van Ness GPU Common Stock None
S. B. Wiley GPU Common Stock None
All Directors and GPU Common Stock 26,427 Shares - Direct
Officers as a Group GPU Common Stock 1,580 Shares - Indirect
52
<PAGE>
Met-Ed/Penelec:
J. R. Leva GPU Common Stock 4,170 Shares - Direct
GPU Common Stock 100 Shares - Indirect
J. G. Graham GPU Common Stock 6,626 Shares - Direct
GPU Common Stock 1,480 Shares - Indirect
R. C. Arnold GPU Common Stock 6,003 Shares - Direct
J. F. Furst GPU Common Stock 746 Shares - Direct
GPU Common Stock 1,363 Shares - Indirect
F. D. Hafer GPU Common Stock 4,470 Shares - Direct
GPU Common Stock 116 Shares - Indirect
J. G. Herbein GPU Common Stock 1,144 Shares - Direct
G. R. Repko GPU Common Stock 958 Shares - Direct
R. J. Toole GPU Common Stock 1,776 Shares - Direct
R. S. Zechman GPU Common Stock 895 Shares - Direct
D. L. O'Brien GPU Common Stock 920 Shares - Direct
All Directors and GPU Common Stock 29,886 Shares - Direct
Officers as a Group GPU Common Stock 3,059 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.
53
<PAGE>
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 GPUSC By-Laws, as amended.
4-A First Amendment to the Credit Agreement dated November 1,
1994 between GPU, JCP&L, Met-Ed and Penelec; Chemical Bank
and Citibank, N.A. as co-agents; and Chemical Bank as
administrative agent incorporated by reference to
Exhibit B-1(a) pursuant to Rule 24 Certificate for SEC
File No. 70-7926.
4-B Subordinated Debenture Indenture of Penelec dated as of
July 1, 1994 incorporated by reference to Exhibit No. A-8(a)
pursuant to Rule 24 Certificate for SEC File No. 70-8403.
4-C Subordinated Debenture Indenture of Met-Ed dated as of
August 1, 1994 incorporated by reference to Exhibit No.
A-8(a) pursuant to Rule 24 Certificate for SEC File
No. 70-8401.
10-A General Public Utilities Corporation Restricted Stock Plan
for Outside Directors
10-B Retirement Plan for Outside Directors of General Public
Utilities Corporation
10-C Deferred Remuneration Plan for Outside Directors of General
Public Utilities Corporation
12 Statements Showing Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
A - Jersey Central Power & Light Company
B - Metropolitan Edison Company
C - Pennsylvania Electric Company
21 Subsidiaries of the Registrant
A - Metropolitan Edison Company
B - Pennsylvania Electric Company
23 Consent of Independent Accountants
A - General Public Utilities Corporation
B - Jersey Central Power & Light Company
C - Metropolitan Edison Company
D - Pennsylvania Electric Company
54
<PAGE>
27 Financial Data Schedule
A - General Public Utilities Corporation
B - Jersey Central Power & Light Company
C - Metropolitan Edison Company
D - Pennsylvania Electric Company
(b) Reports on Form 8-K:
None.
55
<PAGE>
GENERAL PUBLIC UTILITIES CORPORATION
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.
GENERAL PUBLIC UTILITIES CORPORATION
Dated: March 9, 1995 BY: /s/ J. R. Leva
J. R. Leva, Chairman and 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 9, 1995
J. R. Leva, Chairman (Chief Executive
Officer) President and Director
/s/ J. G. Graham March 9, 1995
J. G. Graham, Senior Vice President
(Chief Financial Officer)
/s/ F. A. Donofrio March 9, 1995
F. A. Donofrio, Vice President and
Comptroller (Chief Accounting Officer)
/s/ L. J. Appell, Jr. March 9, 1995
L. J. Appell, Jr., Director
/s/ D. J. Bainton March 9, 1995
D. J. Bainton, Director
/s/ T. H. Black March 9, 1995
T. H. Black, Director
/s/ T. B. Hagen March 9, 1995
T. B. Hagen, Director
/s/ H. F. Henderson, Jr. March 9, 1995
H. F. Henderson, Jr., Director
/s/ J. M. Pietruski March 9, 1995
J. M. Pietruski, Director
/s/ C. A. Rein March 9, 1995
C. A. Rein, Director
/s/ P. R. Roedel March 9, 1995
P. R. Roedel, Director
/s/ C. A. H. Trost March 9, 1995
C. A. H. Trost, Director
/s/ P. K. Woolf March 9, 1995
P. K. Woolf, Director
56
<PAGE>
JERSEY CENTRAL POWER & LIGHT COMPANY
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. The Signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
JERSEY CENTRAL POWER & LIGHT COMPANY
Dated: March 9, 1995 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 9, 1995
J. R. Leva, Chairman
(Principal Executive Officer) and Director
/s/ D. Baldassari March 9, 1995
D. Baldassari, President
(Principal Operating Officer) and Director
/s/ J. G. Graham March 9, 1995
J. G. Graham, Vice President
(Principal Financial Officer) and Director
/s/ D. W. Myers March 9, 1995
D. W. Myers, Vice President-Comptroller
(Principal Accounting Officer) and Director
/s/ R. C. Arnold March 9, 1995.
R. C. Arnold, Director
/s/ M. P. Morrell March 9, 1995
M. P. Morrell, Vice President and Director
/s/ G. E. Persson March 9, 1995
G. E. Persson, Director
/s/ S. C. Van Ness March 9, 1995
S. C. Van Ness, Director
/s/ S. B. Wiley March 9, 1995
S. B. Wiley, Director
57
<PAGE>
METROPOLITAN EDISON COMPANY
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. The Signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
METROPOLITAN EDISON COMPANY
Dated: March 9, 1995 BY: /s/ F. D. Hafer
F. D. Hafer, 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 9, 1995
J. R. Leva, Chairman (Principal Executive
Officer) and Director
/s/ F. D. Hafer March 9, 1995
F. D. Hafer, President (Principal
Operating Officer) and Director
/s/ J. G. Graham March 9, 1995
J. G. Graham, Vice President (Principal
Financial Officer) and Director
/s/ D. L. O'Brien March 9, 1995
D. L. O'Brien, Comptroller (Principal
Accounting Officer)
/s/ J. F. Furst March 9, 1995
J. F. Furst, Vice President and
Director
/s/ G. R. Repko March 9, 1995
G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 9, 1995
R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 9, 1995
R. C. Arnold, Director
58
<PAGE>
PENNSYLVANIA ELECTRIC COMPANY
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. The Signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
PENNSYLVANIA ELECTRIC COMPANY
Dated: March 9, 1995 BY: /s/ F. D. Hafer
F. D. Hafer, 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 9, 1995
J. R. Leva, Chairman (Principal Executive
Officer) and Director
/s/ F. D. Hafer March 9, 1995
F. D. Hafer, President (Principal
Operating Officer) and Director
/s/ J. G. Graham March 9, 1995
J. G. Graham, Vice President (Principal
Financial Officer) and Director
/s/ D. L. O'Brien March 9, 1995
D. L. O'Brien, Comptroller (Principal
Accounting Officer)
/s/ J. F. Furst March 9, 1995
J. F. Furst, Vice President and
Director
/s/ G. R. Repko March 9, 1995
G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 9, 1995
R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 9, 1995
R. C. Arnold, Director
59
<PAGE>
Exhibit 12
Page 1 of 2
<TABLE>
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
<CAPTION>
Twelve Months Ended
December 31, December 31, December 31, December 31, December 31,
1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES $1 604 962 $1 773 219 $1 774 071 $1 935 909 $1 952 425
OPERATING EXPENSES 1 358 796 1 519 908 1 536 596 1 600 984 1 622 399
Interest portion
of rentals (A) 15 925 13 085 12 414 10 944 10 187
Net expense 1 342 871 1 506 823 1 524 182 1 590 040 1 612 212
OTHER INCOME:
Allowance for funds
used during
construction 9 300 8 683 8 071 4 756 4 143
Other income, net 24 519 20 664 21 519 6 281 21 995
Total other income 33 819 29 347 29 590 11 037 26 138
EARNINGS AVAILABLE FOR FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS
(excluding taxes
based on income) $ 295 910 $ 295 743 $ 279 479 $ 356 906 $ 366 351
FIXED CHARGES:
Interest on funded
indebtedness $ 78 196 $ 85 420 $ 92 942 $ 100 246 $ 93 477
Other interest 14 945 11 540 4 873 6 530 14 726
Interest portion
of rentals (A) 15 925 13 085 12 414 10 944 10 187
Total fixed charges $ 109 066 $ 110 045 $ 110 229 $ 117 720 $ 118 390
RATIO OF EARNINGS TO
FIXED CHARGES 2.71 2.69 2.54 3.03 3.09
Preferred stock dividend
requirement 16 313 19 440 20 604 16 810 14 795
Ratio of income before
provision for income
taxes to net income (B) 147.7% 146.8% 144.2% 151.1% 152.3%
Preferred stock dividend
requirement on a pretax
basis 24 094 28 538 29 711 25 400 22 529
Fixed charges, as above 109 066 110 045 110 229 117 720 118 390
Total fixed charges
and preferred
stock dividends $ 133 160 $ 138 583 $ 139 940 $ 143 120 $ 140 919
RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED STOCK
DIVIDENDS 2.22 2.13 2.00 2.49 2.60
</TABLE>
<PAGE>
Exhibit 12
Page 2 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
NOTES:
(A) The Company has included the equivalent of the interest portion of all
rentals charged to income as fixed charges for this statement and has
excluded such components from Operating Expenses.
(B) Represents income before provision for income taxes divided by income
before cumulative effect of accounting change as follows:
<TABLE>
Twelve Months Ended
December 31, December 31, December 31, December 31, December 31,
1990 1991 1992 1993 1994
<CAPTION>
<S> <C> <C> <C> <C> <C>
Income before provisions
for income taxes $186 844 $185 698 $169 250 $239 187 $247 961
Income before cumulative
effect of accounting
changes 126 532 126 460 117 361 158 344 162 841
</TABLE>
<PAGE>
Exhibit 12
Page 1 of 2
<TABLE>
METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
STATEMENTS SHOWING COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
<CAPTION>
Twelve Months Ended
December 31, December 31, December 31, December 31, December 31,
1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES $719 387 $788 462 $821 823 $801 487 $801 303
OPERATING EXPENSES
(excluding taxes
based on income) 559 701 687 439 660 497 624 025 655 805
Interest portion
of rentals (A) 6 830 5 574 5 817 4 932 5 315
Net expense 552 871 681 865 654 680 619 093 650 490
OTHER INCOME:
Allowance for funds
used during
construction 3 912 2 330 2 858 2 919 3 847
Other income, net 17 833 15 531 3 229 (5 581) (98 953)
Total other income 21 745 17 861 6 087 (2 662) (95 106)
EARNINGS AVAILABLE FOR
FIXED CHARGES $188 261 $124 458 $173 230 $179 732 $ 55 707
FIXED CHARGES:
Interest on funded
indebtedness $ 33 512 $ 36 413 $ 38 882 $ 42 887 $ 43 270
Other interest 11 121 9 028 6 039 6 990 15 137(B)
Interest portion
of rentals (A) 6 830 5 574 5 817 4 932 5 315
Total fixed charges $ 51 463 $ 51 015 $ 50 738 $ 54 809 $ 63 722
RATIO OF EARNINGS TO
FIXED CHARGES 3.66 2.44 3.41 3.28 .87
Preferred stock dividend
requirements $ 10 289 $ 10 289 $ 10 289 $ 6 960 $ 2 960
Ratio of income before
provision for income
taxes to net income(C) 146.8% 154.9% 167.6% 160.4% 174.8%
Preferred stock dividend
requirement on a pre-
tax basis 15 104 15 937 17 244 11 164 5 174
Fixed charges, as above 51 463 51 015 50 738 54 809 63 722
Total fixed charges
and preferred
stock dividends $ 66 567 $ 66 952 $ 67 982 $ 65 973 $ 68 896
RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED STOCK
DIVIDENDS 2.83 1.86 2.55 2.72 .81
</TABLE>
<PAGE>
Exhibit 12
Page 2 of 2
METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
STATEMENTS SHOWING COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
NOTES:
(A) The Company included the equivalent of the interest portion of all
rentals charged to income as fixed charges for this statement and has
excluded such components from Operating Expenses.
(B) Includes dividends as preferred securities of subsidiary of $3,200.
(C) Represents income before provisions for income taxes divided by income
before cumulative effect of accounting change as follows:
Twelve Months Ended
December 31, December 31, December 31, December 31,
1990 1991 1992 1993
Income before
provisions for
income taxes $136 798 $ 73 443 $122 492 $124 923
Income before
cumulative
effect of
accounting
changes 93 191 47 400 73 077 77 875
For the twelve months ended December 31, 1994, the ratio was based on the
composite income tax rate for 1994.
<PAGE>
Exhibit 12
Page 1 of 2
<TABLE>
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
<CAPTION>
Twelve Months Ended
December 31, December 31, December 31, December 31, December 31,
1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES $817 923 $865 552 $896 337 $908 280 $944 744
OPERATING EXPENSES 615 852 684 709 678 478 688 587 776 215
Interest portion
of rentals (A) 5 412 4 149 3 945 3 406 3 632
Net expense 610 440 680 560 674 533 685 181 772 583
OTHER INCOME AND DEDUCTIONS:
Allowance for funds
used during
construction 5 902 3 396 1 651 2 261 3 837
Other income
/(expense), net 10 029 6 603 (179) (7 021) (71 287)
Total other income
and deductions 15 931 9 999 1 472 (4 760) (67 450)
EARNINGS AVAILABLE FOR FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS
(excluding taxes
based on income) $223 414 $194 991 $223 276 $218 339 $104 711
FIXED CHARGES:
Interest on funded
indebtedness $ 44 370 $ 45 289 $ 42 615 $ 44 714 $ 46 439
Other interest 7 232 6 744 6 415 5 255 11 913(B)
Interest portion
of rentals (A) 5 412 4 149 3 945 3 406 3 632
Total fixed
charges $ 57 014 $ 56 182 $ 52 975 $ 53 375 $ 61 984
RATIO OF EARNINGS
TO FIXED CHARGES 3.92 3.47 4.21 4.09 1.69
Preferred stock
dividend requirement 8 814 6 189 5 664 4 987 2 937
Ratio of income before
provision for
income taxes to
net income (C) 153.1% 153.6% 170.7% 172.3% 134.4%
Preferred stock
dividend requirement
on a pretax basis 13 491 9 507 9 671 8 594 3 946
Fixed charges, as above 57 014 56 182 52 975 53 375 61 984
Total fixed charges
and preferred
stock dividends $70 505 $65 689 $62 646 $61 969 $65 930
RATIO OF EARNINGS
TO COMBINED FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS 3.17 2.97 3.56 3.52 1.59
</TABLE>
<PAGE>
Exhibit 12
Page 2 of 2
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
STATEMENTS SHOWING COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
Notes:
(A) The Company has included the equivalent of the interest portion of all
rentals charged to income as fixed charges for this statement and has
excluded such components from Operating Expenses.
(B) Includes dividends on preferred securities of subsidiary of $4,492.
(C) Represents income before provision for income taxes divided by income
before cumulative effect of accounting change as follows:
<TABLE>
Twelve Months Ended December 31,
1990 1991 1992 1993 1994
<CAPTION>
<S> <C> <C> <C> <C> <C>
Income before provision
for income taxes $166 400 $138 809 $170 301 $164 964 $42 727
Income before cumulative
effect of accounting
changes 108 712 90 361 99 744 95 728 31 799
</TABLE>
<PAGE>
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
GENERAL PUBLIC UTILITIES CORPORATION
Supplementary Data Page
System Statistics F-3
Selected Financial Data F-4
Management's Discussion and Analysis of Financial
Condition and Results of Operations F-5
Quarterly Financial Data F-23
Financial Statements
Report of Independent Accountants F-24
Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 F-25
Balance Sheets as of December 31, 1994 and 1993 F-26
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 F-28
Statements of Cash Flows for the Years Ended
December 31, 1994, 1993 and 1992 F-29
Notes to Financial Statements F-30
Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts for the
Years 1992-1994 F-56
JERSEY CENTRAL POWER & LIGHT COMPANY
Supplementary Data Page
Company Statistics F-57
Selected Financial Data F-58
Management's Discussion and Analysis of Financial
Condition and Results of Operations F-59
Quarterly Financial Data F-73
Financial Statements
Report of Independent Accountants F-74
Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 F-75
Balance Sheets as of December 31, 1994 and 1993 F-76
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 F-78
Statement of Capital Stock as of December 31, 1994 F-79
Statements of Cash Flows for the Years Ended
December 31, 1994, 1993 and 1992 F-80
Statement of Long-Term Debt as of December 31, 1994 F-81
Notes to Financial Statements F-82
Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts for the
Years 1992-1994 F-104
F-1<PAGE>
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
METROPOLITAN EDISON COMPANY
Supplementary Data Page
Company Statistics F-105
Selected Financial Data F-106
Management's Discussion and Analysis of Financial
Condition and Results of Operations F-107
Quarterly Financial Data F-120
Financial Statements
Report of Independent Accountants F-121
Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 F-122
Balance Sheets as of December 31, 1994 and 1993 F-123
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 F-125
Statement of Capital Stock and Preferred Securities
as of December 31, 1994 F-126
Statements of Cash Flows for the Years Ended
December 31, 1994, 1993 and 1992 F-127
Statement of Long-Term Debt as of December 31, 1994 F-128
Notes to Financial Statements F-129
Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts for the
Years 1992-1994 F-150
PENNSYLVANIA ELECTRIC COMPANY
Supplementary Data Page
Company Statistics F-151
Selected Financial Data F-152
Management's Discussion and Analysis of Financial
Condition and Results of Operations F-153
Quarterly Financial Data F-167
Financial Statements
Report of Independent Accountants F-168
Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 F-169
Balance Sheets as of December 31, 1994 and 1993 F-170
Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 F-172
Statement of Capital Stock and Preferred Securities
as of December 31, 1994 F-173
Statements of Cash Flows for the Years Ended
December 31, 1994, 1993 and 1992 F-174
Statement of Long-Term Debt as of December 31, 1994 F-175
Notes to Financial Statements F-176
Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts for the
Years 1992-1994 F-196
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-2
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
SYSTEM STATISTICS
<CAPTION>
For The Years Ended December 31, 1994 1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Capacity at System Peak (In MW):
Company owned ................................... 6,655 6,735 6,718 6,737 6,870 6,865
Contracted....................................... 3,416 3,236 3,360 3,045 2,270 2,120
Total capacity (a)........................... 10,071 9,971 10,078 9,782 9,140 8,985
Hourly Peak Load (In MW):
Summer peak...................................... 8,521 8,533 8,067 8,271 7,634 7,711
Winter peak...................................... 7,683 7,167 7,173 7,119 6,847 7,339
Reserve at system peak (%)....................... 18.2 16.9 24.9 18.3 19.7 16.5
Load factor (%) (b).............................. 61.7 60.9 62.3 61.1 64.4 64.4
Sources of Energy:
Energy sales (In Thousands of MWH):
Net generation................................. 27,835 28,158 29,981 27,727 29,842 31,607
Power purchases and interchange................ 19,136 20,367 20,001 20,189 16,798 14,564
Total sources of energy...................... 46,971 48,525 49,982 47,916 46,640 46,171
Company use, line loss, etc.................... (4,313) (5,166) (4,843) (4,775) (4,325) (5,026)
Total........................................ 42,658 43,359 45,139 43,141 42,315 41,145
Energy mix (%):
Coal........................................... 35 35 36 37 40 42
Nuclear........................................ 22 22 23 18 21 21
Utility purchases and interchange.............. 22 25 24 30 29 27
Nonutility purchases........................... 19 17 16 12 7 4
Other (gas, hydro & oil)....................... 2 1 1 3 3 6
Total........................................ 100 100 100 100 100 100
Energy cost (In Mills per KWH):
Coal........................................... 14.70 14.66 13.79 14.99 14.96 14.29
Nuclear........................................ 6.14 5.99 5.51 6.30 6.58 6.78
Utility purchases and interchange.............. 20.71 19.31 19.94 21.89 24.98 24.42
Nonutility purchases........................... 59.97 58.56 58.50 57.81 60.18 60.86
Other (gas & oil).............................. 38.42 44.60 39.98 32.87 39.22 37.96
Average...................................... 23.21 22.05 20.90 21.32 19.78 18.76
Electric Energy Sales (In Thousands of MWH):
Residential...................................... 14,788 14,498 13,725 13,852 13,369 13,377
Commercial....................................... 13,301 12,919 12,333 12,336 11,760 11,469
Industrial....................................... 11,983 11,699 11,901 12,035 12,344 12,422
Other............................................ 1,245 1,221 1,303 1,369 1,239 1,208
Sales to customers........................... 41,317 40,337 39,262 39,592 38,712 38,476
Sales to other utilities......................... 1,341 3,022 5,877 3,549 3,603 2,669
Total........................................ 42,658 43,359 45,139 43,141 42,315 41,145
Operating Revenues (In Millions):
Residential...................................... $1,503 $1,465 $1,339 $1,341 $1,211 $1,181
Commercial....................................... 1,215 1,169 1,079 1,060 951 903
Industrial....................................... 774 755 752 753 709 700
Other............................................ 78 89 89 93 86 86
Revenues from customers...................... 3,570 3,478 3,259 3,247 2,957 2,870
Sales to other utilities......................... 24 67 127 84 108 81
Total electric revenues...................... 3,594 3,545 3,386 3,331 3,065 2,951
Other revenues................................... 56 51 48 41 39 41
Total........................................ $3,650 $3,596 $3,434 $3,372 $3,104 $2,992
Price per KWH (In Cents):
Residential...................................... 10.18 10.07 9.73 9.67 9.06 8.83
Commercial....................................... 9.12 9.04 8.72 8.59 8.09 7.87
Industrial....................................... 6.46 6.47 6.32 6.25 5.75 5.64
Total sales to customers......................... 8.64 8.61 8.28 8.20 7.64 7.46
Total sales...................................... 8.43 8.17 7.49 7.72 7.24 7.17
Kilowatt-hour Sales per Residential Customer....... 8,646 8,575 8,215 8,374 8,146 8,238
Customers at Year-End (In Thousands)............... 1,949 1,925 1,901 1,879 1,863 1,842
<FN>
(a) Summer ratings at December 31, 1994 of owned and contracted capacity were 6,651 MW and 3,463 MW, respectively.
(b) The ratio of the average hourly load in kilowatts supplied during the year to the peak load occurring during the year.
</FN>
F-3
</TABLE>
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
SELECTED FINANCIAL DATA
<CAPTION>
For The Years Ended December 31, 1994* 1993 1992 1991** 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Common Stock Data
Earnings per average common share $ 1.42 $ 2.65 $ 2.27 $ 2.49 $ 2.51 $ 2.50
Cash dividends paid per share $ 1.775 $ 1.65 $ 1.575 $ 1.45 $ 1.25 $ 1.00
Book value per share $ 22.31 $ 22.69 $ 21.46 $ 20.81 $ 19.83 $ 18.63
Closing market price per share $ 26 1/4 $ 30 7/8 $ 27 5/8 $ 27 1/4 $ 22 3/4 $ 23 5/8
Common shares outstanding (In Thousands):
Average 115,160 111,779 110,840 110,798 110,763 112,764
At year-end 115,315 115,041 110,857 110,815 110,775 110,747
Market price to book value at year-end 118% 136% 129% 131% 115% 127%
Price/earnings ratio 18.5 11.7 12.2 10.9 9.1 9.4
Return on average common equity 6.3% 11.9% 10.7% 12.0% 12.9% 13.8%
Financial Data (In Thousands)
Operating revenues $3,649,516 $3,596,090 $3,434,153 $3,371,599 $3,104,224 $2,991,727
Other operation and maintenance expense 1,076,925 909,786 856,773 891,314 834,455 843,550
Net income 163,688 295,673 251,636 275,882 278,234 282,464
Net utility plant in service 5,730,962 5,512,057 5,244,039 5,064,254 4,833,045 4,537,154
Cash construction expenditures 585,916 495,517 460,073 467,050 490,546 486,911
Total assets 9,209,777 8,829,255 7,730,738 7,408,834 6,935,440 6,693,774
Long-term debt 2,345,417 2,320,384 2,221,617 1,992,499 1,935,956 1,867,553
Long-term obligations under
capital leases 16,982 23,320 24,094 27,210 27,546 21,835
Preferred securities of subsidiaries 205,000 - - - - -
Cumulative preferred stock with
mandatory redemption 150,000 150,000 150,000 100,000 100,000 -
<FN>
* Results for 1994 reflect a net decrease in earnings of $1.43 per share due to a write-off of certain TMI-2 future costs
($0.91 per share); charges for costs related to the Voluntary Enhanced Retirement Programs ($0.66 per share); a write-off
of Penelec's postretirement benefit costs not considered likely to be recovered in rates ($0.09 per share), and interest
income from refunds of previously paid federal income taxes related to the tax retirement of TMI-2 ($0.23 per share).
** Results for 1991 reflect an increase in earnings of $0.53 per share ($58.2 million) for an accounting change recognizing
unbilled revenues and a decrease in earnings of $0.51 per share ($56.2 million) for estimated TMI-2 costs.
</FN>
F-4
</TABLE>
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings per share were $1.42 compared to $2.65 per share in
1993 and net income decreased $132 million to $163.7 million. The 1994
earnings decrease was principally attributable to a second quarter write-off
of $104.9 million after-tax ($0.91 per share) from an unfavorable Pennsylvania
Commonwealth Court order disallowing the collection of revenues for certain
Three Mile Island Unit 2 (TMI-2) retirement costs, a $76.1 million after-tax
($0.66 per share) charge to earnings for costs related to the Voluntary
Enhanced Retirement Programs, and a $10.6 million after-tax ($0.09 per share)
write-off of postretirement benefit costs not considered likely to be
recovered through ratemaking. The effect of these charges was partially
offset by first quarter interest income of $26.9 million after-tax ($0.23 per
share) from refunds of previously paid federal income taxes related to the tax
retirement of TMI-2. Net income for 1994 would have been $328.4 million, or
$2.85 per share, if not for these nonrecurring events.
Earnings were positively affected by an increase in sales resulting
primarily from growth in the number of customers and colder winter weather as
compared to last year, and an increase in revenues attributable to a February
1993 retail base rate increase at Jersey Central Power & Light Company
(JCP&L). These increases were partially offset by increases in other
operation and maintenance (O&M) expense. GPU's return on average common
equity was 6.3% for 1994 compared to 11.9% for 1993.
Net income for 1993 was $295.7 million, or $2.65 per share, compared to
$251.6 million, or $2.27 per share in 1992. Earnings in 1993 benefited
primarily from the February 1993 retail base rate increase at JCP&L and higher
customer sales due primarily to the significantly warmer summer temperatures
as compared to the mild weather in 1992. These gains were partially offset by
increases in other O&M expense, the write-off of $15.4 million after-tax
($0.14 per share) of costs related to the cancellation of proposed power
supply and transmission facilities agreements and increased depreciation
expense associated with additions to utility plant. Earnings in 1992 were
negatively affected primarily by a reduction in weather-related sales and
increased capital costs, partially offset by increased revenues from new
residential and commercial customers.
OPERATING REVENUES:
Revenues increased 1.5% to $3.65 billion in 1994 after increasing 4.7%
to $3.6 billion in 1993. The components of these changes are as follows:
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General Public Utilities Corporation and Subsidiary Companies
(In Millions)
1994 1993
Kilowatt-hour (KWH) revenues $ 30.6 $ 61.0
(excluding energy portion)
Rate increases 20.8 108.7
Energy revenues (.9) (24.1)
Other revenues 2.9 16.3
Increase in revenues $ 53.4 $161.9
Kilowatt-hour revenues
1994
The increase in KWH revenues was principally due to increases in sales
resulting from new customer additions in the residential and commercial
sectors, and the colder winter weather as compared to last year.
1993
KWH revenues increased primarily due to higher third quarter sales in
the JCP&L service territory resulting from the significantly warmer summer
temperatures as compared to the milder weather during the same period in 1992.
An increase in weather-related sales in the Metropolitan Edison Company (Met-
Ed) service territory, a 1.2% increase in the average number of customers and
a slight increase in nonweather-related usage also contributed to the increase
in KWH revenues. New customer growth, which occurred in the commercial and
residential sectors, was partially offset by a slight reduction in the number
of industrial customers.
1994 MWH Customer Sales by Service Class
Residential 36%
Commercial 32%
Industrial/Other 32%
Rate increases
1993
In February 1993, the New Jersey Board of Public Utilities (NJBPU)
authorized a $123 million increase in JCP&L's retail base rates, or
approximately 7% annually.
Energy revenues
1994 and 1993
Changes in energy revenues do not affect net income as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. The 1993 decrease in energy revenues was principally due to lower
electric sales to other utilities as compared to 1992 when the GPU System
experienced a significant increase in sales to other utilities.
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Other revenues
1994 and 1993
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. However, earnings in 1993 were favorably affected by a one-time
benefit from the recognition of prior period transmission service revenues
approved by the Pennsylvania Public Utility Commission (PaPUC).
OPERATING EXPENSES:
Power purchased and interchanged
1994 and 1993
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Subsidiaries' energy
clauses. However, earnings for 1994 and 1993 were favorably affected by a
reduction in reserve capacity expense resulting from the replacement of
expiring utility purchase power contracts at lower rates.
Other operation and maintenance
1994
The increase in other O&M expense was primarily attributable to a
$127 million pre-tax charge for costs related to the Voluntary Enhanced
Retirement Programs. Increases were also due to higher emergency and winter
storm repairs and the accrual of additional payroll expense under an expanded
employee incentive compensation program designed to tie pay increases more
closely to business results and enhance productivity.
1993
The increase in other O&M expense was largely due to emergency and
storm-related activities, higher tree-trimming expenses and increased costs
related to fossil plant outages.
Depreciation and amortization
1993
The increase in depreciation and amortization expense for 1993
primarily resulted from additions to existing generating facilities to
maintain system reliability and additions to the transmission and distribution
system related to new customer growth.
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General Public Utilities Corporation and Subsidiary Companies
Taxes, other than income taxes
1994 and 1993
Generally, changes in taxes other than income taxes do not
significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income/(expense), net
1994
The increase in other expense is principally related to the second
quarter write-off of future TMI-2 retirement costs and postretirement benefit
costs. The effect of these write-offs was partially offset by first quarter
interest income resulting from refunds of previously paid federal income taxes
related to the tax retirement of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993
PaPUC order that permitted Met-Ed to recover estimated TMI-2 retirement costs
from customers. As a result, second quarter charges were taken at Met-Ed
totaling $127.6 million pre-tax. Pennsylvania Electric Company (Penelec)
recorded charges of $56.3 million pre-tax for its share of such costs. These
charges were comprised of $169.2 million for retirement costs and $14.7
million for monitored storage costs.
Also in the second quarter of 1994, Penelec wrote off $14.6 million
pre-tax in deferred postretirement benefit costs related to the adoption of
Statement of Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." This was a result of a
Commonwealth Court decision reversing a PaPUC order that allowed a
nonaffiliated utility, outside a base rate case, to defer certain
postretirement benefit costs for future recovery from customers. Penelec had
deferred such costs under a similar accounting order issued by the PaPUC. In
addition, Penelec recognized a $4 million pre-tax charge for the remaining
transition obligation related to postretirement benefit costs for the
employees who participated in the Voluntary Enhanced Retirement Programs.
The tax retirement of TMI-2 resulted in a refund for the tax years
after TMI-2 was retired. The effect on pre-tax earnings was an increase of
$59.4 million in interest income.
1993
The reduction in other income is principally due to the write-off of
$24.7 million pre-tax of costs related to the cancellation of proposed power
supply and transmission facilities agreements between the Subsidiaries and
Duquesne Light Company. The decrease is also due to the absence of carrying
charges on certain tax payments made by JCP&L in 1992 that are now being
recovered through rates.
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INTEREST CHARGES AND PREFERRED DIVIDENDS:
1994 and 1993
Other interest expense was higher in 1994 due primarily to the tax
retirement of TMI-2, which resulted in a $13.8 million pre-tax increase in
interest expense on additional amounts owed for tax years in which
depreciation deductions with respect to TMI-2 had been taken. Preferred stock
dividends decreased in both years due to the redemption of $60 million and
$156 million stated value of preferred stock in 1994 and 1993, respectively.
Interest on long-term debt increased in 1993 primarily due to the
issuance of additional long-term debt, offset partially by decreases resulting
from the refinancing of higher cost debt at lower interest rates.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Subsidiaries' capital needs were $719 million in 1994, consisting
of cash construction expenditures of $586 million and amounts for maturing
obligations of $133 million. During 1994, construction funds were used
primarily to maintain and improve existing generation facilities and the
transmission and distribution system, proceed with various clean air
compliance projects, and build new generation facilities. For 1995,
construction expenditures are estimated to be $482 million, consisting mainly
of $384 million for ongoing system development, $57 million for clean air
compliance projects, and $36 million for the continued construction of new
generation facilities. The 1995 estimated reduction is largely due to the
completion in 1994 of a significant portion of clean air compliance
requirements and a new generation facility. Expenditures for maturing debt
are expected to be $91 million for 1995, and $129 million for 1996 including
amounts for mandatory redemptions of preferred stock. In the late 1990s,
construction expenditures are expected to include substantial amounts for
additional clean air requirements and other System needs. Management
estimates that approximately two-thirds of the GPU System's 1995 capital needs
will be satisfied through internally generated funds.
Cash Construction Expenditures
(In millions of dollars)
1990 1991 1992 1993 1994 1995
$491 $467 $460 $496 $586 $482*
* Forecast
The Subsidiaries' 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 TMI-1) of nuclear fuel costs may be outstanding at any time.
Nuclear fuel capital leases at December 31, 1994, totaled $148 million. When
consumed, portions of the presently leased material will be replaced by
additional leased material at a rate of approximately $65 million annually.
In the event the needed nuclear fuel cannot be leased, the associated capital
requirements would have to be met by other means.
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General Public Utilities Corporation and Subsidiary Companies
FINANCING:
In 1994, Penelec and Met-Ed issued $205 million of Monthly Income
Preferred Securities (carried on the balance sheet as Preferred securities of
subsidiaries) through special-purpose finance subsidiaries, and an aggregate
of $180 million principal amount of long-term debt. A portion of these
proceeds was used to refinance long-term debt and redeem more costly preferred
stock amounting to $64 million and $60 million, respectively. In February
1995, Penelec issued $30 million of long-term debt. The net proceeds from
this issuance will be used to reduce short-term debt.
JCP&L anticipates receiving regulatory authorization in the first
quarter of 1995 to issue, through a special-purpose finance subsidiary, up to
$125 million of Monthly Income Preferred Securities. A portion of the JCP&L
securities is expected to be issued in 1995 to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and
Exchange Commission (SEC) to issue up to five million shares of additional
common stock through 1996. The proceeds from the sale of such additional
common stock would be used to increase the Subsidiaries' common equity ratios
and reduce GPU short-term debt. GPU will monitor the capital markets as well
as its capitalization ratios relative to its targets to determine whether, and
when, to issue such shares.
The Subsidiaries have regulatory authority to issue and sell first
mortgage bonds (FMBs), which may be issued as secured medium-term notes, and
preferred stock for various periods through 1995. Under existing
authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the
amount of $275 million, $250 million and $260 million, respectively, of which
$100 million for each Subsidiary may consist of preferred stock. Met-Ed and
Penelec, through their special-purpose finance subsidiaries, have remaining
regulatory authority to issue an additional $25 million and $20 million,
respectively, of Monthly Income Preferred Securities. The Subsidiaries also
have regulatory authority to incur short-term debt, a portion of which may be
through the issuance of commercial paper.
The Subsidiaries' bond indentures and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Subsidiaries may issue. As a result of the TMI-2 retirement
costs write-offs, together with certain other costs recognized in the second
quarter of 1994, Met-Ed will be unable to meet the interest and preferred
dividend coverage requirements of its indenture and charter, respectively,
until the third quarter of 1995. Therefore, Met-Ed's ability to issue senior
securities through June 1995 will be limited to the issuance of FMBs on the
basis of $65 million of previously issued and retired bonds. For similar
reasons, Penelec has sufficient coverage to issue only approximately
$49 million of FMBs through June 1995, depending on interest rates at the time
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General Public Utilities Corporation and Subsidiary Companies
of issuance, plus $38 million of FMBs on the basis of previously issued and
retired bonds. Penelec will be unable to meet coverage requirements for
issuing preferred stock until the third quarter of 1995. The ability of Met-
Ed and Penelec to issue their remaining authorized Monthly Income Preferred
Securities, which have no such coverage restrictions, is not affected by these
write-offs. JCP&L currently has the ability to issue $319 million of FMBs on
the basis of previously issued and retired bonds and has interest and dividend
coverage ratios well in excess of indenture and charter restrictions.
The GPU System's cost of capital and ability to obtain external
financing is affected by the Subsidiaries' security ratings, which are
periodically reviewed by the three major credit rating agencies. In June
1994, Standard & Poor's Corporation (S&P) and Duff & Phelps (D&P) lowered
JCP&L's security ratings citing relatively high customer rates in an
increasingly competitive environment and a perceived credit risk associated
with large purchased power commitments.
Following a review that was prompted by the Commonwealth Court's order
denying recovery of TMI-2 retirement costs, Moody's Investors Service
(Moody's) and S&P downgraded Met-Ed and Penelec's security ratings in August
1994 citing, among other things, the Subsidiaries' weakened financial
flexibility resulting from the second quarter 1994 write-offs. Though
unaffected by the Court's order, JCP&L's credit ratings were reduced by
Moody's due, in part Moody's said, to its relatively high cost structure. The
Subsidiaries' FMBs are currently rated at an equivalent of a BBB+ or higher by
the three major credit rating agencies, while the preferred stock issues and
Monthly Income Preferred Securities have been assigned an equivalent of BBB or
higher. In addition, the Subsidiaries' commercial paper is rated as having
good to high credit quality. Although credit quality has been reduced, the
Subsidiaries' credit ratings remain above investment grade.
In 1994, the S&P rating outlook, which is used to assess the potential
direction of an issuer's long-term debt rating over the intermediate to
longer-term, was revised to "stable" from "negative" for each of the
Subsidiaries. The outlooks reflect S&P's judgement that the Subsidiaries have
manageable construction spending, limited external financing requirements,
regionally competitive rates (particularly Penelec), and an emphasis on cost
cutting to offset base rate relief requirements during the next few years.
Though its outlook was upgraded, S&P believed that Met-Ed risked some
deterioration in its competitive position due to S&P's judgment that there are
substantial purchased power-related rate recovery needs. S&P also assigned
the Subsidiaries a "low average" to "average" business position, a financial
benchmarking standard for rating the debt of electric utilities to reflect the
changing risk profiles resulting primarily from the intensifying competitive
pressures in the industry.
In June 1994, Moody's announced that it developed a new method to
calculate the minimum price an electric utility must charge its customers in
order to recover all of its generation costs. Moody's believes that an
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General Public Utilities Corporation and Subsidiary Companies
assessment of relative cost position will become increasingly critical to the
credit analysis of electric utilities in a competitive marketplace. Specific
rating actions are not anticipated, however, until the pace and implications
of utility market deregulation are more certain.
Present plans call for GPU to issue common stock and the Subsidiaries
to issue long-term debt and Monthly Income Preferred Securities during the
next three years to finance construction activities, make additional
investments in GPU's nonregulated businesses, fund the redemption of maturing
senior securities, make contributions to decommissioning trust funds and,
depending on the level of interest rates, refinance outstanding senior
securities.
CAPITALIZATION:
The GPU System targets capitalization ratios that should warrant
sufficient credit quality ratings to permit capital market access at
reasonable costs. Recent evaluations of the industry by credit rating
agencies indicate that the Subsidiaries may have to increase their equity
ratios to maintain their current credit ratings. GPU's financing plans
contemplate security issuances in 1995 to strengthen the equity component of
the Subsidiaries' capital structures. The targets and actual capitalization
ratios are as follows:
Target Range 1994 1993 1992
Common equity 46-49% 44% 47% 46%
Preferred equity 8-10 8 5 9
Notes payable and
long-term debt 46-41 48 48 45
100% 100% 100% 100%
In 1994, the quarterly dividend on common stock was increased by 5.9%
to an annualized rate of $1.80 per share. Management will continue to review
its dividend policy to determine how to best serve the long-term interests of
shareholders.
NONREGULATED BUSINESS:
Energy Initiatives, Inc. (EI), a wholly-owned subsidiary of GPU
develops, owns, operates and invests in cogeneration and other nonutility
power production facilities.
In 1994, EI acquired North Canadian Power, Inc. (NCP) along with
partnership interests in NCP's five domestic operating projects. As of
December 31, 1994, EI had twelve combined-cycle cogeneration plants in-service
located in the United States and Canada totaling 932 MW of capacity and a 24
MW facility under construction expected to be completed in 1996. EI operates
nine of these plants. In addition, EI is a participant in a joint venture
developing a 750 MW combined-cycle plant in Barranquilla, Colombia.
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General Public Utilities Corporation and Subsidiary Companies
As a result of the federal Energy Policy Act of 1992, EI has expanded
its business activities to include development of exempt wholesale generation
facilities in both domestic and certain international markets. EI has
submitted proposals for the development of additional capacity in the United
States and is pursuing development projects in Latin America and Asia, while
investigating other international opportunities.
In 1994, GPU made $75 million in cash capital contributions to EI for
the purpose of investing in nonutility generation projects and partnerships.
Total EI investments for the year consisted of approximately $54 million for
the NCP acquisition and $20 million for other capital expenditures. At
December 31, 1994, GPU's net investment in EI was $111 million. The SEC has
authorized GPU to invest up to an additional $200 million in EI through 1997.
Management expects that EI will be a source of future earnings growth
and intends to make additional investments in the development and ownership of
nonutility generation facilities to expand these business activities. The
timing and amounts of these investments, however, will depend upon the
development of appropriate opportunities.
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated
monopolies. Over the last few years, however, market forces combined with
state and federal actions, have laid the foundation for the continued
development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of
competition in Pennsylvania's electric utility industry and solicited comments
on various issues. Met-Ed and Penelec jointly filed responses in November
1994 suggesting, among other things, that the PaPUC provide for the equitable
recovery of stranded investments, enable utilities to offer flexible pricing
to customers with competitive alternatives, and address regulatory
requirements that impose costs unequally on Pennsylvania utilities as compared
with unregulated or out-of-state suppliers. At the end of the investigation,
which is expected to be concluded in early 1995, the PaPUC will decide whether
to conduct a rulemaking proceeding.
In May 1994, the NJBPU approved JCP&L's request to implement a new rate
initiative designed to retain and expand the economic base in its service
territory. Under the contract rate service, JCP&L may enter into individual
contracts to provide electric service to large commercial and industrial
customers. This initiative will allow JCP&L more flexibility in responding to
competitive pressures.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking regarding the recovery by utilities of
legitimate and verifiable stranded costs. Costs incurred by a utility to
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General Public Utilities Corporation and Subsidiary Companies
provide integrated electric service to a franchise customer become stranded
when that customer subsequently purchases power from another supplier using
the utility's transmission services. Among other things, the FERC proposed
that utilities be allowed under certain circumstances to recover such stranded
costs associated with existing wholesale customer contracts, but not under new
wholesale contracts unless expressly provided for in the contract. While it
stated a "strong" policy preference that state regulatory agencies address
recovery of stranded retail costs, the FERC also set forth alternative
proposals for how it would address the matter if the states failed to do so.
Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of
Appeals for the District of Columbia, in an unrelated case, questioned the
FERC's authority to permit utilities to recover stranded costs. The Court
remanded the matter to the FERC for it to conduct an evidentiary hearing in
the case to determine whether, among other things, permitting stranded cost
recovery was so inherently anticompetitive that it violates antitrust laws.
While largely supported by the electric utility industry, the Proposed
Rulemaking has been strongly opposed by other groups. There can be no
assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing
for electric transmission services. The policy statement contains five
principles that will provide the foundation for the FERC's analyses of all
subsequent transmission rate proposals. Recognizing the evolution of a more
competitive marketplace, the FERC contends that it is critical that
transmission services be priced in a manner that appropriately compensates
transmission owners and creates adequate incentives for efficient system
expansion.
In November 1994, the NJBPU issued a draft New Jersey Energy Master
Plan Phase I Report promoting regulatory policy changes intended to move the
state's electric and gas utilities into a competitive marketplace. In the
draft, the NJBPU recommends, among other things, the adoption of 1) rate-
flexibility legislation to allow utilities to compete in order to retain and
attract customers; 2) alternatives to rate base/rate-of-return regulation;
3) consumer protection standards to ensure that captive ratepayers do not
subsidize competitive activities; and 4) an integrated resource planning and
competitive supply-side procurement process to streamline the regulatory
review process, lower costs, and ensure that the state's environmental and
energy conservation goals are met in a competitive marketplace. Although the
NJBPU proposes actions and regulatory reforms that encourage competition, the
draft Plan calls for an evolutionary transition toward open markets. The
recommendations are largely intended to be interim measures while the NJBPU
investigates other issues, including retail wheeling and stranded costs, that
are likely to affect the future of the electric utility industry. The New
Jersey Energy Master Plan is being developed in three phases, with Phase I
scheduled to be adopted in March 1995 and the remaining phases expected to be
concluded by year-end 1995.
In 1994, the SEC issued for public comment a Concept Release regarding
modernization of the Public Utility Holding Company Act of 1935 (Holding
Company Act). GPU regards the Holding Company Act as a significant impediment
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General Public Utilities Corporation and Subsidiary Companies
to competition and supports its repeal. In addition, GPU believes that the
Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally
reformed given the burdens being placed on electric utilities by PURPA
mandated uneconomic long-term power purchase agreements with nonutility
generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related
actions as a result of its ongoing strategic planning activities. Responding
to its assessment that competition in the electric utility industry is likely
to accelerate, GPU proceeded to implement two major organizational changes as
well as other programs designed to reduce costs and strengthen GPU's
competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the
non-nuclear generation facilities owned by the Subsidiaries as well as
undertake responsibility to construct any new non-nuclear generation
facilities which the Subsidiaries may need in the future. By forming GPU
Generation Corporation (GPUGC), GPU will consolidate and streamline the
management of these generation facilities, and seek to apply management and
operating efficiency techniques similar to those employed in more competitive
industries. This initiative is intended to bring the Subsidiaries' generation
costs more in line with projected market prices. GPU Nuclear Corporation is
engaging in a search for parallel opportunities. The Subsidiaries received
regulatory approvals to enter into an operating agreement with GPUGC from the
PaPUC and NJBPU. SEC authorization is expected to be received in 1995.
The second part of the realignment includes the management combination
of the two Pennsylvania subsidiaries. This action is intended to increase
effectiveness and lower costs of Pennsylvania customer operations and service
functions.
Other organizational realignments, designed to streamline management
and reduce costs, were also implemented throughout the GPU System in 1994. In
addition, GPU expanded employee participation in its incentive compensation
program to tie pay increases more closely to business results and enhance
productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU
System workforce accepted the Voluntary Enhanced Retirement Programs. Future
payroll and benefits savings, which are estimated to be $75 million annually,
began in the third quarter and reflect limiting the replacement of employees
up to ten percent of those retired. Retirement benefits will be substantially
paid from pension and postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the
electric utility industry that calls into question the assumptions regarding
the recovery of certain costs through ratemaking. As the utility industry
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General Public Utilities Corporation and Subsidiary Companies
continues to experience an increasingly competitive environment, GPU is
attempting to assess the impact that these and other changes will have on its
financial position. For additional information regarding the other changes
that may have an adverse effect on the Subsidiaries, see the Competition and
the Changing Regulatory Environment section of Note 1 to the Consolidated
Financial Statements.
Due to the current availability of excess capacity in the marketplace,
the cost of near- to intermediate-term regional energy supply from existing
facilities, as evidenced by the results of the JCP&L all source competitive
supply solicitation conducted in 1994, is less than the rates in virtually all
of the Subsidiaries' nonutility generation agreements. In addition, the
projected cost of energy from new supply sources is now lower than was
expected in the recent past due to improvements in power plant technologies
and reduced fuel prices.
The long-term nonutility generation agreements included in GPU's supply
plan have been entered into pursuant to the requirements of PURPA and state
regulatory directives. The Subsidiaries intend to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Subsidiaries are also attempting to renegotiate, and in some cases buy out,
existing high cost long-term nonutility generation agreements.
While the Subsidiaries thus far have been granted recovery of their
nonutility generation costs from customers by the PaPUC and NJBPU, there can
be no assurance that the Subsidiaries will continue to recover these costs
throughout the terms of the related agreements. GPU currently estimates that
in 1998, when substantially all of these nonutility generation projects are
scheduled to be in-service, above market payments (benchmarked against the
expected cost of electricity produced by a new gas-fired combined cycle
facility) will range from $300 million to $450 million annually.
THE GPU SUPPLY PLAN:
Under existing retail regulation, supply planning in the electric
utility industry is directly related to projected growth in the franchise
service territory. At this time, management cannot estimate the timing and
extent to which retail electric competition will affect the GPU supply plan.
As GPU prepares to operate in an increasingly competitive environment, its
supply plan currently focuses on maintaining the Subsidiaries' existing
customer base by offering competitively priced electricity.
Over the next five years, each Subsidiary is projected to experience an
average growth in sales to customers of about 2% annually. These increases
are expected to result from continued economic growth in the service
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General Public Utilities Corporation and Subsidiary Companies
territories and a slight increase in customers. To meet this growth, assuming
the continuation of existing retail electric regulation, actual and projected
capacity and sources of energy are as follows:
Capacity
1994 1999
MW % MW %
Coal 3,022 30 3,040 28
Nuclear 1,396 14 1,405 13
Gas, Hydro & Oil 2,233 22 2,480 23
Contracted Purchases 3,463 34 3,695 34
Uncommitted Sources - - 280 2
Total 10,114 100 10,900 100
Sources of Energy
1994 1999
GWH % GWH %
Coal 16,547 35 17,210 32
Nuclear 10,217 22 10,105 19
Gas, Hydro & Oil 1,071 2 1,325 2
Contracted Purchases 14,533 31 21,150 39
Spot Market & Interchange
Purchases 4,603 10 4,465 8
Total 46,971 100 54,255 100
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" market purchases, and
avoidance of long-term firm commitments. Through 1999, the plan consists of
the continued utilization of GPU's existing generation facilities combined
with power purchases, the construction of new facilities, and the continued
promotion of economic energy-conservation and load-management programs. GPU's
present strategy includes minimizing the financial exposure associated with
new long-term purchase commitments and the construction of new facilities by
evaluating these options in terms of an unregulated power market. The GPU
System will take necessary actions to avoid adding new capacity at costs that
may exceed future market prices. In addition, GPU will seek regulatory
support to renegotiate or buy out contracts with nonutility generators where
the pricing is in excess of projected market prices.
New Energy Supplies
The GPU System's supply plan includes contracted capacity from
nonutility generators, the replacement of expiring utility purchase contracts
at lower costs, the construction of new peaking units, and the repowering of
existing generation facilities. The supply plan also includes the addition of
approximately 280 MW of currently uncommitted capacity. Additional capacity
needs are principally related to the expiration of existing commitments rather
than new customer load.
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General Public Utilities Corporation and Subsidiary Companies
The Subsidiaries have contracts and anticipated commitments with
nonutility generators under which a total of 1,416 MW of capacity is currently
in service and about an additional 1,180 MW are currently scheduled or
anticipated to be in service by 1999.
In January 1994, JCP&L issued an all-source solicitation for the short-
to intermediate-term supply of energy and capacity to determine and evaluate
the availability of competitively priced power supply options. JCP&L is
completing contract negotiations with three suppliers to purchase about 350 MW
of capacity beginning in 1996, increasing to approximately 700 MW by 1999, for
terms of up to eight years. JCP&L will continue to evaluate additional
economic purchase opportunities as both demand and supply market conditions
evolve and conduct further solicitations to fulfill, if warranted, a
significant part of the uncommitted sources identified in GPU's supply plan.
In October 1994, Met-Ed completed construction on a 134 MW gas-fired
combustion turbine located adjacent to its Portland Generating station at a
cost of approximately $50 million. After completing operational testing, the
new unit was placed in-service in January 1995 and is expected to produce
power at a lower cost than similar peaking units now in operation.
JCP&L has commenced construction of a 141 MW gas-fired combustion
turbine at its Gilbert Generating station. The new facility is estimated to
cost $50 million and, coupled with the retirement of two older units, will
result in a net capacity increase of approximately 95 MW. The project is
expected to be in-service by mid-1996. Petitions have been filed with the
NJBPU by two organizations seeking, among other things, reconsideration of the
NJBPU's order which found that New Jersey's Electric Facility Need Assessment
Act is not applicable to this combustion turbine and that construction of this
facility, without a market test, is consistent with New Jersey energy
policies. This matter is pending.
The GPU supply plan also includes a repowering project at Penelec's
Warren Generating station that combines a coal-fueled combustion turbine with
an existing generator. The repowering project will enable the station to
comply with state and federal standards for reduced emissions and increase
electrical output to approximately 100 MW. While the U.S. Department of
Energy has agreed to fund 50% of the $146 million project cost as part of its
Clean Coal Technology Program, management is unable to determine what effect
recent federal budget cut proposals will have on Congressional appropriation
of this funding. The project is in the early stages of development and is
estimated to be in-service in 1996.
Managing Nonutility Generation
The Subsidiaries are pursuing actions to either eliminate or
substantially reduce above-market payments for energy supplied by nonutility
generators. The Subsidiaries will also continue to take legal, regulatory and
legislative initiatives to avoid entering into any new power-supply agreements
that are either not needed or, if needed, are not consistent with competitive
market pricing. The following is a discussion of major nonutility generation
activities involving the Subsidiaries.
F-18
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
In a 1993 order, the NJBPU directed all utilities to identify
nonutility generation contracts which were uneconomic and, therefore,
candidates for buyout or other remedial measures. JCP&L identified a proposed
100 MW nonutility generation project as such a candidate, but was unable to
negotiate a buyout or contract repricing to a level consistent with prices of
replacement power. The NJBPU therefore ordered that hearings be held to
determine whether their order approving the agreement should be modified or
revoked. After hearings commenced in early 1994, the nonutility generator
filed a complaint with the U.S. District Court seeking to enjoin the NJBPU
proceedings on the grounds they were preempted by PURPA. The District Court
dismissed the complaint finding, among other things, that the federal courts
did not have jurisdiction to consider the matter. In January 1995, however,
the U.S. Court of Appeals for the Third Circuit overturned the District Court
decision. The Court of Appeals held, among other things, that once the NJBPU
approves a power purchase agreement under PURPA and approves the utility's
collection of costs from its customers, PURPA preempts the NJBPU from altering
its order approving the contract and JCP&L's recovery from customers of its
payment to the nonutility generator. The Court of Appeals reached its
decision despite the contract provision that if the NJBPU at any time in the
future disallowed any such rate recovery, JCP&L's payments to the nonutility
generator would be equally reduced. JCP&L, the NJBPU and the New Jersey
Division of Rate Advocate have each filed motions for rehearing with the Court
of Appeals.
In 1994, a nonutility generator requested that the NJBPU and the PaPUC
order JCP&L and Met-Ed to enter into long-term agreements to buy capacity and
energy. JCP&L is contesting this request and the NJBPU has referred this
matter to an Administrative Law Judge for hearings. Met-Ed sought to dismiss
the request based on a May 1994 PaPUC order, which granted a Met-Ed and
Penelec petition to obtain additional nonutility purchases through competitive
bidding until new PaPUC regulations have been adopted. In September 1994, the
Commonwealth Court granted the PaPUC's application to revise its May 1994
order for the purpose of reevaluating the nonutility generator's right to sell
power to Met-Ed. The PaPUC subsequently ordered that hearings be held in this
matter.
In November 1994, Penelec requested the Pennsylvania Supreme Court to
review a Commonwealth Court decision upholding a PaPUC order requiring Penelec
to purchase a total of 160 MW from two nonutility generators. The PaPUC had
ordered Penelec in 1993 to enter into power purchase agreements with the
nonutility generators for 80 MW of power each under long-term contracts
commencing in 1997 or later. In August 1994, the Commonwealth Court denied
Penelec's appeal of the PaPUC order. Penelec's petition to the Supreme Court
contends that the Commonwealth Court imposed unnecessary and excessive costs
on Penelec customers by finding that Penelec had a need for capacity. The
petition also questions the Commonwealth Court's upholding of the PaPUC's
determination that the nonutility generators had incurred a legal obligation
entitling them to payments under PURPA.
In May 1994, the NJBPU issued an order granting two nonutility
generators, aggregating 200 MW, a final in-service date extension for projects
originally scheduled to be operational in 1997. In June 1994, JCP&L appealed
F-19
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General Public Utilities Corporation and Subsidiary Companies
the NJBPU's decision to the Appellate Division of the New Jersey Superior
Court. The NJBPU order extends the in-service date for one year plus the
period until JCP&L's appeals are decided.
As part of the effort to reduce above-market payments under nonutility
generation agreements, the Subsidiaries are seeking to implement a program
under which the natural gas fuel and transportation for the Subsidiaries' gas-
fired facilities, as well as up to approximately 1,100 MW of nonutility
generation capacity, would be pooled and managed by a nonaffiliated fuel
manager. The Subsidiaries believe the plan has the potential to provide
substantial savings for their customers. The Subsidiaries have begun initial
discussions with the nonutility generators who would be eligible to
participate. Requirements for approval of the plan by state and federal
regulatory agencies are being reviewed.
Conservation and Load Management
The NJBPU and PaPUC continue to encourage the development of new
conservation and load-management programs. Because the benefits of some of
these programs may not offset program costs, the Subsidiaries are working to
mitigate the impacts these programs can have on the Subsidiaries' competitive
position in the marketplace.
In New Jersey, JCP&L continues to conduct demand-side management (DSM)
programs approved in 1992 by the NJBPU. DSM includes utility-sponsored
activities designed to improve energy efficiency in customer electricity use
and load-management programs that reduce peak demand. These JCP&L programs
have resulted in summer peak demand reductions of over 43 MW through 1994.
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of DSM costs and directed utilities to implement DSM programs. Met-Ed and
Penelec subsequently filed DSM programs that were expected to be approved by
the PaPUC in the first quarter of 1995. However, an industrial intervenor had
contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court
reversed the PaPUC order. As a result, the nature and scope of Met-Ed and
Penelec's DSM programs is uncertain at this time.
ENVIRONMENTAL ISSUES:
The Clean Air Act Amendments of 1990 (Clean Air Act) require
substantial reductions in sulfur dioxide and nitrogen oxide emissions by the
year 2000. The Subsidiaries' current plan includes installing and operating
emission control equipment at some of their coal-fired facilities as well as
switching to lower sulfur coal at other coal-fired facilities.
To comply with the Clean Air Act, the Subsidiaries expect to spend up
to $380 million by the year 2000 for air pollution control equipment. During
1994, the first of two scrubbers was installed at the jointly owned Conemaugh
station. The second scrubber is scheduled to be installed in November 1995.
When operational, these scrubbers are expected to reduce sulfur dioxide
emissions by 95%. Met-Ed's share of the total project cost is estimated to be
F-20
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
$55 million. Through December 31, 1994, the Subsidiaries have made capital
expenditures of approximately $179 million (including the first Conemaugh
scrubber mentioned above) to comply with the Clean Air Act requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of
representatives of 12 northeast states (including New Jersey and Pennsylvania)
and the District of Columbia proposed reductions in nitrogen oxide (NOx)
emissions it believes necessary to meet ambient air quality standards for
ozone and the statutory deadlines set by the Clean Air Act. The Subsidiaries
expect that the U.S. Environmental Protection Agency will approve the
proposal, and that as a result, the Subsidiaries will spend an estimated $60
million, beginning in 1997, to meet the reductions set by the OTC. The OTC
requires additional NOx reductions to meet the Clean Air Act's 2005 National
Ambient Air Quality Standards for ozone. However, the specific requirements
that will have to be met, at that time, have not been finalized. The
Subsidiaries are unable to determine what, if any, additional costs will be
incurred.
In developing its least-cost plan to comply with the Clean Air Act, the
Subsidiaries will continue to evaluate the risk of recovering capital
investments compared to increased participation in the emission allowance
market and the use of low-sulfur coal or the early retirement of facilities.
These 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 plants are expected to be
recoverable through the current ratemaking process, but management recognizes
that recovery is not assured.
For more information, see the Environmental Matters section of Note 1
to the Consolidated Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately
2,100 individual claims for alleged personal injury (including claims for
punitive damages), which are material in amount, have been asserted against
GPU and the Subsidiaries and are still pending. For more information, see the
TMI-2 section of Note 1 to the Consolidated Financial Statements.
EFFECTS OF INFLATION:
Under traditional ratemaking, the GPU System is affected by inflation
since the regulatory process results in a time lag during which increased
operating expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry,
the Subsidiaries do not plan to take any actions that would increase
customers' base rates over the next several years. Therefore, the control of
F-21
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
operating and capital costs will be essential. As competition and
deregulation accelerate, there can be no assurance as to the recovery of
increased operating expense or utility plant investments.
The GPU System is committed to long-term cost control and continues to
seek and implement measures to reduce or limit the growth of operating
expenses and capital expenditures, including the associated effects of
inflation. Though currently operating in a regulated environment, the GPU
System's focus will be less reliant on the ratemaking process, and geared
toward continued performance improvement and cost reduction to facilitate the
competitive pricing of its products and services.
F-22
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
QUARTERLY FINANCIAL DATA (UNAUDITED)
<CAPTION>
First Quarter Second Quarter
In Thousands Except
Per Share Data 1994* 1993 1994** 1993
<S> <C> <C> <C> <C>
Operating revenues........................ $937,209 $881,154 $873,533 $863,236
Operating income.......................... 156,596 134,061 45,700 116,808
Net income................................ 122,902 79,323 (125,342) 58,570
Earnings per share........................ 1.07 .72 (1.09) .52
Third Quarter Fourth Quarter
In Thousands Except
Per Share Data 1994 1993 1994 1993***
Operating revenues........................ $994,672 $990,160 $844,102 $861,540
Operating income.......................... 169,014 176,647 117,215 100,260
Net income................................ 111,299 126,486 54,829 31,294
Earnings per share........................ .97 1.14 .47 .27
<FN>
* Results for the first quarter 1994 reflect an increase in earnings of $0.23 per share
($26.9 million) resulting from interest on refunds of previously paid federal income
taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of $1.66 per
share for the write-off of previously deferred TMI-2 future costs ($104.9 million),
Voluntary Enhanced Retirement Program costs ($76.1 million), and postretirement
benefit costs not considered likely to be recovered through ratemaking ($10.6
million).
*** Results for the fourth quarter 1993 reflect a decrease in earnings of $0.14 per
share ($15.7 million) for the write-off of the Duquesne transactions.
</FN>
F-23</TABLE>
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
General Public Utilities Corporation
Parsippany, New Jersey
We have audited the consolidated financial statements and financial statement
schedule of General Public Utilities Corporation and Subsidiary Companies as
listed in the index on page F-1 of this Form 10-K. These financial statements
and financial statement schedule are the responsibility of the Corporation's
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule 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 consolidated financial position of General Public
Utilities Corporation and Subsidiary Companies as of December 31, 1994 and
1993, and the consolidated results of their operations and their cash flows
for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
As more fully discussed in Note 1 to the consolidated financial statements,
the Corporation is unable to determine the ultimate consequences of certain
contingencies which have resulted from the accident at Unit 2 of the Three
Mile Island Nuclear Generating Station ("TMI-2"). The matters which remain
uncertain are (a) the extent to which the retirement costs of TMI-2 could
exceed amounts currently recognized for ratemaking purposes or otherwise
accrued, and (b) 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 7 and 9 to the consolidated financial statements, the
Corporation 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.
COOPERS & LYBRAND L.L.P.
New York, New York
February 1, 1995
F-24
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Revenues................................... $3,649,516 $3,596,090 $3,434,153
Operating Expenses:
Fuel............................................... 363,834 363,643 356,230
Power purchased and interchanged................... 894,560 897,185 900,504
Deferral of energy costs, net...................... (29,025) (6,598) 40,175
Other operation and maintenance.................... 1,076,925 909,786 856,773
Depreciation and amortization...................... 353,705 359,898 339,721
Taxes, other than income taxes..................... 348,945 344,221 328,307
Total operating expenses...................... 3,008,944 2,868,135 2,821,710
Operating Income Before Income Taxes................. 640,572 727,955 612,443
Income taxes....................................... 152,047 200,179 162,166
Operating Income..................................... 488,525 527,776 450,277
Other Income and Deductions:
Allowance for other funds used during construction. 4,712 4,831 5,606
Other income/(expense), net........................ (152,236) (7,579) 30,503
Income taxes....................................... 66,369 2,756 (11,762)
Total other income and deductions............. (81,155) 8 24,347
Income Before Interest Charges and
Preferred Dividends................................ 407,370 527,784 474,624
Interest Charges and Preferred Dividends:
Interest on long-term debt......................... 183,186 187,847 174,439
Other interest..................................... 39,227 20,612 18,966
Allowance for borrowed funds used during
construction...................................... (7,115) (5,105) (6,974)
Dividends on preferred securities of subsidiaries.. 7,692 - -
Preferred stock dividends of subsidiaries.......... 20,692 28,757 36,557
Total interest charges and preferred dividends 243,682 232,111 222,988
Net Income........................................... $ 163,688 $ 295,673 $ 251,636
Earnings Per Average Common Share.................... $ 1.42 $ 2.65 $ 2.27
Average Common Shares Outstanding (In Thousands)..... 115,160 111,779 110,840
Cash Dividends Paid Per Share........................ $ 1.775 $ 1.65 $ 1.575
F-25</TABLE>
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost....................... $8,879,630 $8,441,335
Less, accumulated depreciation..................... 3,148,668 2,929,278
Net utility plant in service................... 5,730,962 5,512,057
Construction work in progress...................... 340,248 267,381
Other, net......................................... 195,388 214,178
Net utility plant.............................. 6,266,598 5,993,616
Other Property and Investments:
Nuclear decommissioning trusts..................... 260,482 219,178
Nonregulated investments, net...................... 115,538 31,830
Nuclear fuel disposal fund......................... 82,920 82,095
Other, net......................................... 33,553 29,662
Total other property and investments........... 492,493 362,765
Current Assets:
Cash and temporary cash investments................ 26,731 25,843
Special deposits................................... 10,226 11,868
Accounts receivable:
Customers, net................................... 248,728 253,186
Other............................................ 56,903 55,037
Unbilled revenues.................................. 113,581 113,960
Materials and supplies, at average cost or less:
Construction and maintenance..................... 184,644 187,606
Fuel............................................. 55,498 51,676
Deferred energy costs.............................. 8,728 (20,787)
Deferred income taxes.............................. 18,399 15,554
Prepayments........................................ 62,164 79,490
Total current assets........................... 785,602 773,433
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs............ 157,042 339,672
Unamortized property losses........................ 108,699 113,566
Deferred income taxes.............................. 428,897 275,257
Income taxes recoverable through future rates...... 561,498 554,590
Other.............................................. 408,948 416,356
Total deferred debits and other assets......... 1,665,084 1,699,441
Total Assets................................... $9,209,777 $8,829,255
The accompanying notes are an integral part of the consolidated financial statements.
F-26</TABLE>
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock....................................... $ 314,458 $ 314,458
Capital surplus.................................... 663,418 667,683
Retained earnings.................................. 1,775,759 1,813,490
Total.......................................... 2,753,635 2,795,631
Less, reacquired common stock, at cost............. 181,051 185,258
Total common stockholders' equity.............. 2,572,584 2,610,373
Cumulative preferred stock:
With mandatory redemption........................ 150,000 150,000
Without mandatory redemption..................... 98,116 158,242
Preferred securities of subsidiaries............... 205,000 -
Long-term debt..................................... 2,345,417 2,320,384
Total capitalization........................... 5,371,117 5,238,999
Current Liabilities:
Debt due within one year........................... 91,165 133,232
Notes payable...................................... 347,408 216,056
Obligations under capital leases................... 157,168 161,744
Accounts payable................................... 317,259 300,181
Taxes accrued...................................... 80,027 140,132
Interest accrued................................... 66,628 73,368
Other.............................................. 213,041 155,944
Total current liabilities...................... 1,272,696 1,180,657
Deferred Credits and Other Liabilities:
Deferred income taxes.............................. 1,438,743 1,389,241
Unamortized investment tax credits................. 156,262 170,108
Three Mile Island Unit 2 future costs.............. 341,139 319,867
Other.............................................. 629,820 530,383
Total deferred credits and other liabilities... 2,565,964 2,409,599
Commitments and Contingencies (Note 1)
Total Liabilities and Capital.................. $9,209,777 $8,829,255
The accompanying notes are an integral part of the consolidated financial statements.
F-27</TABLE>
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Balance at beginning of year....................... $1,813,490 $1,716,196 $1,644,249
Add - Net income................................. 163,688 295,673 251,636
Deduct - Cash dividends declared on common stock. 207,215 189,150 177,308
Other adjustments, net.................. (5,796) 9,229 2,381
Balance at end of year............................. $1,775,759 $1,813,490 $1,716,196
The accompanying notes are an integral part of the consolidated financial statements.
F-28</TABLE>
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Activities:
Income before preferred stock dividends
of subsidiaries.................................... $ 184,380 $ 324,430 $ 288,193
Adjustments to reconcile income to cash provided:
Depreciation and amortization..................... 363,099 362,536 340,138
Amortization of property under capital leases..... 56,793 62,816 67,820
Three Mile Island Unit 2 costs.................... 183,944 - -
Voluntary enhanced retirement program............. 126,964 - -
Nuclear outage maintenance costs, net............. (7,425) (5,266) 16,736
Deferred income taxes and investment tax
credits, net.................................... (80,139) 63,334 8,720
Deferred energy costs, net........................ (28,463) (5,971) 40,989
Accretion income.................................. (14,855) (16,786) (20,500)
Allowance for other funds used during
construction.................................... (4,713) (4,831) (5,606)
Changes in working capital:
Receivables....................................... 6,799 (32,221) 23,546
Materials and supplies............................ 316 20,278 (1,780)
Special deposits and prepayments.................. 25,696 (38,571) (852)
Payables and accrued liabilities.................. (58,952) (101,231) (47,039)
Other, net.......................................... (3,311) (32,465) (23,766)
Net cash provided by operating activities...... 750,133 596,052 686,599
Investing Activities:
Cash construction expenditures...................... (585,916) (495,517) (460,073)
Contributions to decommissioning trusts............. (33,575) (84,546) (22,714)
Nonregulated investments............................ (73,835) (16,426) (747)
Other, net.......................................... (17,429) 9,822 (25,621)
Net cash used for investing activities......... (710,755) (586,667) (509,155)
Financing Activities:
Issuance of long-term debt.......................... 178,787 947,485 585,954
Increase/(Decrease) in notes payable, net........... 131,574 114,705 (87,776)
Retirement of long-term debt........................ (197,232) (752,250) (387,029)
Capital lease principal payments.................... (61,002) (56,424) (70,440)
Issuance of common stock............................ - 132,500 -
Issuance of preferred securities of subsidiaries.... 197,917 - -
Issuance of preferred stock of subsidiaries......... - - 50,000
Redemption of preferred stock of subsidiaries....... (62,763) (163,734) (51,635)
Dividends paid on common stock...................... (204,233) (184,616) (174,538)
Dividends paid on preferred stock of subsidiaries... (21,538) (31,598) (36,711)
Net cash provided/(required) by
financing activities......................... (38,490) 6,068 (172,175)
Net increase in cash and temporary cash
investments from above activities................... 888 15,453 5,269
Cash and temporary cash investments, beginning of year 25,843 10,390 5,121
Cash and temporary cash investments, end of year...... $ 26,731 $ 25,843 $ 10,390
Supplemental Disclosure:
Interest paid (net of amount capitalized)........... $ 249,765 $ 222,891 $ 200,640
Income taxes paid................................... $ 124,274 $ 157,226 $ 184,062
New capital lease obligations incurred.............. $ 43,246 $ 57,609 $ 48,087
Common stock dividends declared but not paid........ $ 51,843 $ 48,861 $ 44,327
The accompanying notes are an integral part of the consolidated financial statements.
F-29</TABLE>
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Public Utilities Corporation (the Corporation) is a holding
company registered under the Public Utility Holding Company Act of 1935. The
Corporation does not directly operate any utility properties, but owns all
the outstanding common stock of three electric utilities -- Jersey Central
Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec) (the Subsidiaries). The Corporation
also owns all the common stock of GPU Service Corporation (GPUSC), a service
company; GPU Nuclear Corporation (GPUN), which operates and maintains the
nuclear units of the Subsidiaries; and Energy Initiatives, Inc. (EI) and EI
Power, Inc., which develop, own and operate nonutility generating facilities.
All of these companies considered together with their subsidiaries are
referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Subsidiaries have 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. TMI-1 and TMI-2 are jointly owned by
JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%,
respectively. Oyster Creek is owned by JCP&L. At December 31, the
Subsidiaries' net investment in TMI-1, TMI-2 and Oyster Creek, including
nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2 Oyster Creek
1994 $627 $103 $817
1993 $670 $115 $784
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, safety standards and experience gained in the
construction and operation of nuclear facilities. The GPU System may also
incur costs and experience reduced output at its nuclear plants because of the
prevailing design criteria 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 the 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 each plant's useful life (whether scheduled or
premature), the carrying costs of that investment and retirement costs, is not
assured (see NUCLEAR PLANT RETIREMENT COSTS). Management intends, in general,
to seek recovery of such costs through the ratemaking process, but recognizes
that recovery is not assured (see COMPETITION AND THE CHANGING REGULATORY
ENVIRONMENT).
F-30
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
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 accident cleanup program was completed in 1990. After receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100
individual claims for alleged personal injury (including claims for punitive
damages), which are material in amount, have been asserted against the
Corporation and the Subsidiaries and the suppliers of equipment and services
to TMI-2, and are pending in the United States District Court for the Middle
District of Pennsylvania. Some of the claims also seek recovery on the basis
of alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are
not covered by insurance and are not subject to the liability limitations of
the federal Price-Anderson Act ($560 million at the time of the accident),
punitive damage awards could have a material adverse effect on the financial
position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Subsidiaries had (a) primary financial protection in the form of
insurance policies with groups of insurance companies providing an aggregate
of $140 million of primary coverage, (b) secondary financial protection in the
form of private liability insurance under an industry retrospective rating
plan providing for premium charges deferred in whole or in major part under
such plan, and (c) an indemnity agreement with the NRC, bringing their total
primary and secondary insurance financial protection and indemnity agreement
with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against the Corporation and the Subsidiaries and their
suppliers under a reservation of rights with respect to any award of punitive
damages. However, in March 1994, the defendants in the TMI-2 litigation and
the insurers agreed that the insurers would withdraw their reservation of
rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is likely to begin in 1996. 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
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General Public Utilities Corporation and Subsidiary Companies
for summary judgment. In July 1994, the Court granted defendants' motion for
interlocutory appeal of these orders, stating that they raise questions of law
that contain substantial grounds for differences of opinion. The issues are
now before the United States Court of Appeals.
In an Order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against the Corporation
and the Subsidiaries; and (2) stated in part that the Court is of the opinion
that any punitive damages owed must be paid out of and limited to the amount
of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
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 Subsidiaries 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 Subsidiaries 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 targets (in 1994 dollars) for TMI-1 and Oyster Creek
are $157 million and $189 million, respectively. Based on NRC studies, a
comparable funding target for TMI-2 has been developed which takes the
accident into account (see TMI-2 Future Costs). The NRC continues to study
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 considered 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 $225 to $309 million and $239 to $350 million, respectively
(adjusted to 1994 dollars). In addition, the studies estimated the cost of
removal of nonradiological structures and materials for TMI-1 and Oyster Creek
at $74 million and $48 million, respectively (adjusted to 1994 dollars).
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The ultimate cost of retiring the GPU System's 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
Subsidiaries charge to expense and contribute to external trusts amounts
collected from customers for nuclear plant decommissioning and nonradiological
costs. In addition, the Subsidiaries have contributed amounts written off for
TMI-2 nuclear plant decommissioning in 1990 and 1991 to TMI-2's external trust
and will await resolution of the case pending before the Pennsylvania Supreme
Court before making any further contributions for amounts written off by Met-
Ed and Penelec in 1994. Amounts deposited in external trusts, including the
interest earned on these funds, are classified as Nuclear Decommissioning
Trusts on the balance sheet.
TMI-1 and Oyster Creek:
JCP&L is collecting revenues for decommissioning, which are expected to
result in the accumulation of its share of the NRC funding target for each
plant. JCP&L is also collecting revenues, based on estimates of $15.3 million
for TMI-1 and $31.6 million for Oyster Creek adopted in rate orders issued in
1991 and 1993 by the New Jersey Board of Public Utilities (NJBPU), for its
share of the cost of removal of nonradiological structures and materials. In
1993, the Pennsylvania Public Utility Commission (PaPUC) granted Met-Ed
revenues for decommissioning costs of TMI-1 based on its share of the NRC
funding target and nonradiological cost of removal as estimated in the site-
specific study. Also in 1993, the PaPUC approved a rate change for Penelec
that increased the collection of revenues for decommissioning costs for TMI-1
to a basis equivalent to that granted Met-Ed. Collections from customers for
retirement expenditures are deposited in external trusts. Provision for the
future expenditures of these funds has been made in accumulated depreciation,
amounting to $46 million for TMI-1 and $100 million for Oyster Creek at
December 31, 1994. Oyster Creek and TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
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 current ratemaking process.
TMI-2 Future Costs:
The Corporation and its Subsidiaries have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target in
1994 dollars. The Subsidiaries record escalations, when applicable, in the
liability based upon changes in the NRC funding target. The Subsidiaries have
also
recorded a liability for incremental costs specifically attributable to
monitored storage. In addition, the Subsidiaries have recorded a liability for
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nonradiological cost of removal consistent with the TMI-1 site-specific study
and have spent $2 million as of December 31, 1994. Estimated Three Mile
Island Unit 2 Future Costs as of December 31, 1994 and 1993 are as follows:
(Millions) (Millions)
1994 1993
Radiological Decommissioning $250 $229
Nonradiological Cost of Removal 72 71
Incremental Monitored Storage 19 20
Total $341 $320
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At December 31, 1994, $109 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet,
and $56 million was recoverable from customers and included in Three Mile
Island Unit 2 Deferred Costs on the balance sheet.
In 1993, a PaPUC rate order for Met-Ed allowed for the future recovery
of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer
Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate
order and in 1994, the Commonwealth Court reversed the PaPUC order. In
December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to
review that decision. As a consequence of the Commonwealth Court decision,
Met-Ed recorded pre-tax charges totaling $127.6 million during 1994. Penelec,
which is also subject to PaPUC regulation, recorded pre-tax charges of
$56.3 million during 1994, for its share of such costs applicable to its
retail customers. These charges appear in the Other Income and Deductions
section of the Income Statement and are composed of $121 million for
radiological decommissioning costs, $48.2 million for the nonradiological cost
of removal and $14.7 million for incremental monitored storage costs. Met-Ed
and Penelec will await resolution of the case pending before the Pennsylvania
Supreme Court before making any nonrecoverable funding contributions to
external trusts for their share of these costs. The Pennsylvania Subsidiaries
will be similarly required to charge to expense their share of future
increases in the estimate of the costs of retiring TMI-2. Future earnings on
trust fund deposits for Met-Ed and Penelec will be recorded as income. Prior
to the Commonwealth Court's decision, Met-Ed and Penelec expensed and
contributed $40 million and $20 million respectively, to external trusts
relating to their nonrecoverable shares of the accident-related portion of the
decommissioning liability. JCP&L has also expensed and made a nonrecoverable
contribution of $15 million to an external decommissioning trust. JCP&L's
share of earnings on trust fund deposits are offset against amounts shown on
the balance sheet under Three Mile Island Unit 2 Deferred Costs as collectible
from customers.
The NJBPU has granted decommissioning revenues for JCP&L's share of the
remainder of the NRC funding target and allowances for the cost of removal of
nonradiological structures and materials. JCP&L, which is not affected by the
Commonwealth Court's ruling, intends to seek recovery for any increases in
TMI-2 retirement costs, but recognizes that recovery cannot be assured.
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As a result of TMI-2's entering long-term monitored storage in late
1993, the Subsidiaries are incurring incremental annual storage costs of
approximately $1 million. The Subsidiaries estimate that the remaining annual
storage costs will total $19 million through 2014, the expected retirement
date of TMI-1. JCP&L's rates reflect its $5 million share of these costs.
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 GPU System.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station 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 for stabilization of
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 that
station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial 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 two operating reactors (TMI-2 is excluded under
an exemption received from the NRC in 1994), subject to an annual maximum
payment of $10 million per incident per reactor.
The GPU System has insurance coverage for incremental replacement power
costs resulting from an accident-related outage at its nuclear plants.
Coverage commences after the first 21 weeks of the outage and continues for
three years beginning at $1.8 million for Oyster Creek and $2.6 million for
TMI-1 per week for the first year, decreasing by 20 percent for years two and
three.
Under its insurance policies applicable to nuclear operations and
facilities, the GPU System is subject to retrospective premium assessments of
up to $69 million in any one year, in addition to those payable (up to $20
million annually per incident) under the Price-Anderson Act.
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COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
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 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation," the GPU System'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.
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 any
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 GPU System'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 currently.
Management believes that to the extent that the GPU System no longer qualifies
for FAS 71 accounting treatment, a material adverse effect on its results of
operations and financial position may result.
The Subsidiaries have 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 Subsidiaries to purchase at the
contract price all of the power produced up to the contract limits. As of
December 31, 1994, facilities covered by these agreements having 1,416 MW
(JCP&L 882 MW, Met-Ed 239 MW and Penelec 295 MW) of capacity were in service
and 130 MW were scheduled
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General Public Utilities Corporation and Subsidiary Companies
to commence operation in 1995. Payments made pursuant to these agreements were
$528 million, $491 million and $471 million for 1994, 1993 and 1992,
respectively. For the years 1995, 1996, 1997, 1998, and 1999, payments
pursuant to these agreements are estimated to aggregate $694 million,
$918 million, $1,088 million, $1,304 million and $1,337 million, respectively.
These agreements, together with those for facilities which are not yet in
operation, provide for the purchase of approximately 2,596 MW (JCP&L 1,176 MW,
Met-Ed 846 MW and Penelec 574 MW) of capacity and energy by the GPU System by
the mid-to-late 1990s, at varying prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the System's energy supply needs which has caused
the Subsidiaries to change their supply strategy to now seek shorter-term
agreements offering more flexibility (see Management's Discussion and Analysis
-COMPETITIVE ENVIRONMENT). Due to the current availability of excess capacity
in the market place, the cost of near- to intermediate-term (i.e., one to
eight years) energy supply from existing generation facilities is currently
competitively priced. The projected cost of energy from new generation supply
sources has also decreased due to improvements in power plant technologies and
reduced forecasted fuel prices. As a result of these developments, the rates
under virtually all of the Subsidiaries' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources. These agreements have been entered into pursuant to the requirements
of the federal Public Utility Regulatory Policies Act and state regulatory
directives. The Subsidiaries have initiated lawful actions which are intended
to substantially reduce these above market payments. In addition, the
Subsidiaries intend to avoid, to the maximum extent practicable, entering into
any new nonutility generation agreements that are not needed or not consistent
with current market pricing. The Subsidiaries are also attempting to
renegotiate, and in some cases buy out, high cost long-term nonutility
generation agreements.
While the Subsidiaries thus far have been granted recovery of their
nonutility generation costs from customers by the PaPUC and NJBPU, there can
be no assurance that the Subsidiaries will continue to be able to recover
these costs throughout the term of the related agreements. GPU currently
estimates that in 1998, when substantially all of the these nonutility
generation projects are scheduled to be in service, above market payments
(benchmarked against the expected cost of electricity produced by a new gas-
fired combined cycle facility) will range from $300 million to $450 million
annually. Moreover, efforts to lower these costs have led to disputes before
both the NJBPU and the PaPUC, as well as to litigation, and may result in
claims against the Subsidiaries for substantial damages. There can be no
assurance as to the outcome of these matters.
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
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General Public Utilities Corporation and Subsidiary Companies
fields, and storage and disposal of hazardous and/or toxic wastes, the GPU
System may be required to incur substantial additional costs to construct new
equipment, modify or replace existing and proposed equipment, remediate,
decommission or clean up waste disposal and other sites currently or formerly
used by it, including formerly owned manufactured gas plants and mine refuse
piles and generating facilities, 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.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of
1990, the Subsidiaries expect to spend up to $380 million for air pollution
control equipment by the year 2000. In developing its least-cost plan to
comply with the Clean Air Act, the GPU System will continue to evaluate major
capital investments compared to participation in the emission allowance market
and the use of low-sulfur fuel or retirement of facilities. In September
1994, the Ozone Transport Commission (OTC), consisting of representatives of
12 northeast states (including New Jersey and Pennsylvania) and the District
of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Corporation expects that the U.S.
Environmental Protection Agency (EPA) will approve the proposal, and that as a
result, the Subsidiaries will spend an estimated $60 million, beginning in
1997, to meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Subsidiaries are unable to
determine what, if any, additional costs will be incurred.
The GPU System companies have been notified by the EPA and state
environmental authorities that they are 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 13 hazardous and/or toxic
waste sites. In addition, the Subsidiaries have been requested to voluntarily
participate in the remediation or supply information to the EPA and state
environmental authorities on several other sites for which they have not yet
been named as PRPs. The Subsidiaries have also been named in lawsuits
requesting damages for hazardous and/or toxic substances allegedly released
into the environment. 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 Subsidiaries.
JCP&L has entered into agreements with the New Jersey Department of
Environmental Protection for the investigation and remediation of 17 formerly
owned manufactured gas plant sites. One of these sites has been repurchased
by JCP&L. JCP&L has also entered into various cost-sharing agreements with
other utilities for some of the sites. As of December 31, 1994, JCP&L has an
estimated environmental liability of $32 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
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General Public Utilities Corporation and Subsidiary Companies
to be performed are lengthened, JCP&L 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 JCP&L 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 JCP&L is required to utilize different remediation methods,
the costs could be materially in excess of $60 million.
In 1993, the NJBPU approved a mechanism similar to JCP&L's Levelized
Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas
plant remediation costs when expenditures exceed prior collections. The NJBPU
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. A final NJBPU order dated December 16, 1994 indicated
that interest is to be accrued retroactive to June 1993. JCP&L is pursuing
reimbursement of the above costs from its insurance carriers. In November
1994, JCP&L filed a complaint with the Superior Court of New Jersey against
several of its insurance carriers, relative to these manufactured gas plant
sites. JCP&L requested the Court to order the insurance carriers to reimburse
JCP&L for all amounts it has paid, or may be required to pay, in connection
with the remediation of the sites.
The GPU System companies are 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.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the Corporation's Subsidiaries offered Voluntary Enhanced
Retirement Programs (VERP) to certain employees. The enhanced retirement
programs were part of a corporate realignment undertaken in 1994.
Approximately 82% of eligible employees accepted the retirement programs,
resulting in a pre-tax charge to earnings of $127 million. These charges are
included as Other Operation and Maintenance on the income statement.
The GPU System's construction programs, for which substantial
commitments have been incurred and which extend over several years,
contemplate expenditures of $482 million during 1995. As a consequence of
reliability, licensing, environmental and other requirements, 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 such costs through
the ratemaking process, but recognizes that recovery is not assured.
The Subsidiaries have entered into long-term contracts with
nonaffiliated mining companies for the purchase of coal for certain generating
stations in which they have ownership interests. The contracts, which expire
between 1995 and the end of the expected service lives of the generating
stations, require the
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General Public Utilities Corporation and Subsidiary Companies
purchase of either fixed or minimum amounts of the stations' coal
requirements. The price of the coal under the contracts is based on
adjustments of indexed cost components. One contract also includes a
provision for the payment of environmental and postretirement benefits. The
Subsidiaries' share of the cost of coal purchased under these agreements is
expected to aggregate $98 million for 1995.
The Subsidiaries have entered into agreements and JCP&L is completing
contract negotiations with three other utilities to purchase capacity and
energy for various periods through 2004. These agreements, including
contracts under negotiation, will provide for up to 1,308 MW in 1995,
declining to 1,096 MW in 1997 and 696 MW by 2004. For the years 1995, 1996,
1997, 1998, and 1999, payments pursuant to these agreements are estimated to
aggregate $208 million, $175 million, $162 million, $145 million and $128
million, respectively. JCP&L's contract negotiations are the result of their
all-source solicitation for competitively priced, short- to intermediate-term
energy and capacity, described in the New Energy Supplies section of
Management's Discussion and Analysis.
The NJBPU 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 Division of the Ratepayer Advocate (Ratepayer
Advocate), 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 1993, JCP&L and the other New Jersey electric utilities filed motions for
summary judgment with the NJBPU. Ratepayer Advocate 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 JCP&L for the
1988-92 LEAC periods would be approximately $102 million. In 1994, the NJBPU
ruled that the 1991 LEAC period was considered closed but subsequent LEACs
remain open for further investigation. This matter is pending before a NJBPU
Administrative Law Judge. Management estimates that the potential exposure
for LEAC periods subsequent to 1991 is approximately $67 million through
February 1996, the end of the next LEAC period. There can be no assurance as
to the outcome of this proceeding.
JCP&L's two operating nuclear units are subject to the NJBPU'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 $11 million. While a capacity factor
below 40% would generate no specific monetary charge, it would require the
issue to be brought before the NJBPU for review. The annual measurement
period, which begins in March of each year, coincides with that used for the
LEAC. At the request of the PaPUC, Met-Ed and Penelec, as well as the other
Pennsylvania utilities, have supplied the PaPUC with proposals for the
establishment of a nuclear performance standard. Met-Ed and Penelec expect
the PaPUC to adopt a generic nuclear performance standard as a part of their
respective energy cost rate (ECR) clauses in 1995.
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General Public Utilities Corporation and Subsidiary Companies
During the normal course of the operation of their businesses, in
addition to the matters described above, the GPU System companies are from
time to time involved in disputes, claims and, in some cases, as defendants in
litigation in which compensatory and punitive damages are sought by customers,
contractors, vendors and other suppliers of equipment and services and by
employees alleging unlawful employment practices. It is not expected that the
outcome of these types of matters would have a material effect on the GPU
System's financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The consolidated financial statements include the accounts of all
subsidiaries. Certain reclassifications of prior years' data have been made
to conform with current presentation. The Subsidiaries' accounting records
are maintained in accordance with the Uniform System of Accounts prescribed by
the Federal Energy Regulatory Commission (FERC) and adopted by the PaPUC and
NJBPU.
REVENUES
The Corporation and its Subsidiaries recognize electric operating
revenues for services rendered (including an estimate of unbilled revenues) to
the end of the respective accounting period.
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 GPU System 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 GPU System 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
Subsidiaries used depreciation rates which, on an aggregate composite basis,
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General Public Utilities Corporation and Subsidiary Companies
resulted in annual rates of 3.16%, 3.19% and 3.17% for the years 1994, 1993
and 1992, 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 pre-tax 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 6.45%, 6.80% and 7.33% for the years 1994, 1993 and 1992,
respectively.
AMORTIZATION POLICIES
Accounting for TMI-2 and Forked River Investments:
JCP&L 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 2008. Met-Ed and Penelec have collected all of their
TMI-2 investment attributable to retail customers. At December 31, 1994,
$91 million is included in Unamortized Property Losses on the balance sheet
for JCP&L's Forked River project. JCP&L 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 Subsidiaries
have not been provided revenues for a return on the unamortized balances of
the damaged TMI-2 facility and the cancelled Forked River project, these
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/(Expense), Net on the income statement.
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 Subsidiaries have 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, 1994 amounted to $40 million and is primarily
reflected in Deferred Credits and Other Liabilities - Other. Utilities with
nuclear plants will contribute annually, based on an assessment computed on
prior enrichment purchases, over a 15-year period. The Subsidiaries made
their initial payment to this fund in 1993, and they are recovering the
remaining amounts through their fuel clauses. At December 31, 1994, $46
million is recorded on the balance sheet in Deferred Debits and Other Assets -
Other.
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<PAGE>
General Public Utilities Corporation and Subsidiary Companies
NUCLEAR OUTAGE MAINTENANCE COSTS
The GPU System accrues incremental nuclear outage maintenance costs
anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE
The Subsidiaries are 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 Subsidiaries 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, 1994, all of which relates to
spent nuclear fuel from nuclear generation through April 1983, amounted to
$150 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 Subsidiaries have reflected such excess
of $28 million at December 31, 1994 in Deferred Debits and Other Assets -
Other. The rates presently charged to customers provide for the collection of
these costs, plus interest, over remaining periods of 12 years for JCP&L, 13
years for Met-Ed and 3 years for Penelec.
The Subsidiaries are collecting one mill per kilowatt-hour from their
customers for spent nuclear fuel disposal costs resulting from nuclear
generation subsequent to April 1983. These amounts are remitted quarterly to
the DOE.
INCOME TAXES
The GPU System companies file a consolidated federal income tax return.
All participants are jointly and severally liable for the full amount of any
tax, including penalties and interest, which may be assessed against the
group.
Deferred income taxes, which result primarily from liberalized
depreciation methods, deferred energy costs, decommissioning funds and
discounted Forked River and TMI-2 investments, 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 GPU System 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 amounts of assets and
liabilities recognized for financial reporting purposes and the amounts
recognized for tax purposes.
F-43
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
STATEMENTS OF CASH FLOWS
For the purpose of the consolidated 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, 1994, the GPU System had $348 million of short-term
notes outstanding, of which $60 million was commercial paper and the remainder
was issued under bank lines of credit (credit facilities).
The GPU System has $528 million of credit facilities, which includes a
Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1,
1999, are limited to $250 million in total borrowings outstanding at any time
and subject to various covenants and acceleration under certain conditions.
The Credit Agreement borrowing rates and facility fee are dependent on the
long-term debt ratings of the Subsidiaries.
4. LONG-TERM DEBT
At December 31, 1994, the Subsidiaries had long-term debt outstanding,
as follows:
Interest Rates
4 5/8% to 7% to 9% to
Maturities 6.97% 8 7/8% 10 1/2% Total
(In Thousands)
First mortgage bonds:
1995-2004 $ 587,005 $ 494,191 $148,500 $1,229,696
2005-2014 215,120 138,300 - 353,420
2015-2025 205,000 557,200 50,000 812,200
Total $1,007,125 $1,189,691 $198,500 2,395,316
Amounts due within one year (87,930)
Total 2,307,386
Other long-term debt (net of $3,235 due within one year) 42,968
Unamortized net discount (4,937)
Total $2,345,417
F-44
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
For the years 1995, 1996, 1997, 1998 and 1999, the Subsidiaries have
long-term debt maturities of $91 million, $119 million, $145 million, $39
million and $63 million, respectively. Substantially all of the utility plant
owned by the Subsidiaries is subject to the lien of their respective
mortgages.
The estimated fair value of the Corporation's long-term debt, as of
December 31, 1994 and 1993 is as follows:
(In Thousands)
Carrying Fair
Amount Value
1994 $2,345,417 $2,142,854
1993 $2,320,384 $2,446,407
The fair value of long-term debt is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to the
Corporation for debt of the same remaining maturities and credit qualities.
5. PREFERRED SECURITIES OF SUBSIDIARIES
At December 31, 1994, Met-Ed Capital L.P., a special-purpose finance
subsidiary of Met-Ed, and Penelec Capital L.P., a special-purpose finance
subsidiary of Penelec, had the following issues of Monthly Income Preferred
Securities outstanding:
Issue Securities
Company Series Price Outstanding Total
(In Thousands)
Met-Ed Capital 9.00% $25 4,000,000 $100,000
Penelec Capital 8.75% $25 4,200,000 105,000
Total $205,000
The fair value of the Monthly Income Preferred Securities for Met-Ed Capital
and Penelec Capital, based on market price quotes at December 31, 1994, is
$98 million and $100.8 million, respectively.
In 1994, Met-Ed Capital L.P. and Penelec Capital L.P. issued $100 million
and $105 million, respectively, of Monthly Income Preferred Securities. The
proceeds from the issuance of the Monthly Income Preferred Securities were
then lent to Met-Ed and Penelec; they in turn issued deferrable interest
subordinated debentures to their special-purpose finance subsidiaries.
Penelec and Met-Ed are taking tax deductions for the interest paid on the
subordinated debentures.
The issued and outstanding Monthly Income Preferred Securities of Met-Ed
Capital L.P. and Penelec Capital L.P. mature in 2043. They are redeemable at
the option of Met-Ed and Penelec at 100 percent of the principal amount
beginning in 1999, or earlier under certain limited circumstances, including
the loss of the tax deduction for interest paid. Distributions on the Monthly
Income Preferred Securities are paid monthly but can be deferred for up to 60
months. However, Met-Ed and Penelec may not pay dividends or redeem or
acquire any of their preferred or common stock until deferred payments on
their respective subordinated debentures are paid in full.
F-45
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
6. CAPITAL STOCK
COMMON STOCK
The following table presents information relating to the common stock
($2.50 par value) of the Corporation:
1994 1993
Authorized shares 150,000,000 150,000,000
Issued shares 125,783,338 125,783,338
Reacquired shares 10,575,086 10,816,561
Outstanding shares 115,208,252 114,966,777
Restricted units 107,063 74,076
In 1993, the Corporation sold four million shares of common stock through
an underwritten public offering. In 1994 and 1993, pursuant to the 1990
Restricted Stock Plan, the Corporation issued to officers restricted units
representing rights to receive shares of common stock, on a one-for-one basis,
at the end of the restriction period. The restricted units do not affect the
issued and outstanding shares of common stock until conversion at the end of
the restriction period. However, the restricted units are considered common
stock equivalents and therefore are included in average common shares
outstanding for the earnings per share computation on the income statement.
The restricted units accrue dividends on a quarterly basis. In 1994 and 1993,
the Corporation awarded to plan participants 34,595 and 32,740 restricted
units, respectively. In 1994 and 1993, the Corporation issued a total of
6,275 and 3,729 restricted shares, respectively, from previously reacquired
shares. No shares of common stock were reacquired in 1994 or 1993.
PREFERRED STOCK
At December 31, 1994, the Subsidiaries had the following issues of
cumulative preferred stock outstanding:
Stated Value Shares (In Thousands)
Series per Share Outstanding Stated Value
With mandatory redemption:
7.52% - 8.65% $100 1,500,000 $150,000
Without mandatory redemption:
3.70% - 4.70% $100 723,912 $ 72,391
7.88% $100 250,000 25,000
Total 973,912 97,391
Premium 725
Total $ 98,116
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<PAGE>
General Public Utilities Corporation and Subsidiary Companies
During 1994, Met-Ed and Penelec redeemed their 7.68% (aggregate stated
value of $35 million) and 8.36% (aggregate stated value of $25 million)
cumulative preferred stock, respectively. Met-Ed's total cost of the
redemption was $36 million, which resulted in a $1.2 million charge to
Retained Earnings. Penelec's total cost of the redemption was $26 million,
resulting in a $1.1 million charge to Retained Earnings.
During 1993, the Subsidiaries redeemed preferred stock as follows: JCP&L
redeemed all of its outstanding 8.12% Series and 8% Series cumulative
preferred stock (aggregate stated value of $50 million) at a total cost of
$52.4 million. Met-Ed redeemed all of its outstanding 8.32% Series H, 8.32%
Series J, 8.12% Series I and its 8.12% cumulative preferred stock (aggregate
stated value of $81 million) at a total cost of $85.3 million. Penelec
redeemed all of its outstanding 8.12% Series I cumulative preferred stock
(aggregate stated value of $25 million) at a total cost of $26 million. These
redemptions resulted in a net $6.9 million charge to Retained Earnings.
During 1992, JCP&L issued 500,000 shares of 7.52% Series cumulative
preferred stock with mandatory redemption provisions. The series is callable
beginning in the year 2002 at various prices above its stated value. The
series is to be redeemed ratably over 20 years beginning in the year 1998.
This issue provides that JCP&L 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 $0.5 million incurred in
connection with the issuance of the cumulative preferred stock were charged to
Capital Surplus on the balance sheet.
During 1992, JCP&L redeemed all its outstanding 8.75% Series H 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 $0.7 million were charged to Retained
Earnings.
The issued and outstanding shares of preferred stock without mandatory
redemption are callable at various prices above their stated values. At
December 31, 1994, the aggregate amount at which these shares could be called
by the Subsidiaries was $102 million. The issued and outstanding shares with
mandatory redemption have aggregate redemption requirements of $45 million for
the years 1995 through 1999.
At December 31, 1994 and 1993, the Subsidiaries were authorized to issue
37,035,000 shares of cumulative preferred stock. If dividends on any of the
preferred stock of any of the Subsidiaries 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 of that Subsidiary until all dividends in
arrears have been paid. A Subsidiary may not redeem preferred stock unless
dividends on all of that Subsidiary's preferred stock for all past quarterly
dividend periods have been paid or declared and set aside for payment.
F-47
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
7. INCOME TAXES
Effective January 1, 1993, the GPU System 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 $9 million and an increase in the
deferred tax liabilities of $48 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.
As of December 31, 1994 and 1993, the balance sheet reflected $562 million and
$555 million, respectively, of income taxes recoverable through future rates,
(related to liberalized depreciation), and a regulatory liability for income
taxes refundable through future rates of $106 million and $111 million,
respectively, (related to unamortized ITC), substantially due to the
recognition of amounts not previously recorded.
A summary of the components of deferred taxes as of December 31, 1994 and
1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993
Current: Current:
Unbilled revenue $ 16 $ 14 Revenue taxes $ 18 $ (12)
Other 2 2 Deferred energy 4 (6)
Total $ 18 $ 16 Total $ 22 $ (18)
Noncurrent: Noncurrent:
Unamortized ITC $106 $111 Liberalized
Decommissioning 131 48 depreciation:
Contribution in aid previously flowed
of construction 25 22 through $ 333 $ 327
Other 167 94 future revenue
Total $ 429 $275 requirements 229 228
Subtotal 562 555
Liberalized
depreciation 767 726
Forked River 54 30
Other 56 78
Total $1,439 $1,389
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:
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<PAGE>
General Public Utilities Corporation and Subsidiary Companies
(In Millions)
1994 1993 1992
Net income $164 $296 $252
Preferred stock dividends 21 29 37
Income tax expense 86 197 174
Book income subject to tax $271 $522 $463
Federal statutory rate 35% 35% 34%
State tax, net of federal benefit - 4 5
Other (3) (1) (1)
Effective income tax rate 32% 38% 38%
Federal and state income tax expense is comprised of the following:
(In Millions)
1994 1993 1992
Provisions for taxes currently payable $162 $127 $165
Deferred income taxes:
Liberalized depreciation 31 32 34
New Jersey revenue tax 32 32 3
Deferral of energy costs 12 6 (16)
Accretion income 11 7 9
Decommissioning (76) - -
VERP (51) - -
Other (21) 5 (8)
Deferred income taxes, net (62) 82 22
Amortization of ITC, net (14) (12) (13)
Income tax expense $ 86 $197 $174
In 1994, the GPU System and the Internal Revenue Service (IRS) reached
an agreement to settle the Corporation's claim for 1986 that TMI-2 has been
retired for tax purposes. The Corporation's Subsidiaries have received net
refunds totaling $17 million, which have been credited to their customers.
Also in 1994, the GPU System received net interest from the IRS totaling $46
million (before income taxes), associated with the refund settlement, which
was credited to income. The IRS has completed its examinations of the GPU
System's federal income tax returns through 1989. The years 1990 through 1992
are currently being audited.
F-49
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
8. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses
consisted of the following:
(In Millions)
1994 1993 1992
Maintenance $271 $275 $251
Other taxes:
New Jersey unit tax $204 $202 $197
Pennsylvania state gross receipts 70 68 67
Real estate and personal property 21 21 22
Other 54 53 42
Total $349 $344 $328
9. EMPLOYEE BENEFITS
Pension Plans:
The GPU System maintains defined benefit pension plans covering
substantially all employees. The GPU System'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)
1994 1993 1992
Service cost-benefits earned during the period $ 34.8 $ 28.6 $ 26.3
Interest cost on projected benefit obligation 95.4 91.8 87.8
Less: Expected return on plan assets (104.4) (96.6) (89.5)
Amortization (1.4) (2.2) (2.5)
Net periodic pension cost $ 24.4 $ 21.6 $ 22.1
The above 1994 amounts do not include a pre-tax charge to earnings of
$97 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992
were gains of $13.8 million, $145.9 million and $53.2 million, respectively.
The funded status of the plans and related assumptions at December 31,
1994 and 1993 were as follows:
F-50
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
(In Millions)
1994 1993
Accumulated benefit obligation (ABO):
Vested benefits $ 1,118.2 $ 982.3
Nonvested benefits 120.5 122.9
Total ABO 1,238.7 1,105.2
Effect of future compensation levels 182.6 197.2
Projected benefit obligation (PBO) $ 1,421.3 $ 1,302.4
PBO $(1,421.3) $(1,302.4)
Plan assets at fair value 1,279.9 1,288.6
PBO in excess of plan assets (141.4) (13.8)
Less: Unrecognized net loss 72.5 19.8
Unrecognized prior service cost (0.6) (5.9)
Unrecognized net transition asset (6.6) (8.6)
Adjustment required to recognize
minimum liability (1.2) (2.3)
Accrued pension liability $ (77.3) $ (10.8)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
Annual increase in compensation levels 6.0 5.0
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $48 million decrease in the PBO
as of December 31, 1994. Also, in 1994, the PBO increased by $109 million as
a result of the VERP. 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 loss represents actual experience
different from that assumed, which is deferred and not included in the
determination of pension cost until it exceeds certain levels. Both the
unrecognized prior service cost resulting from retroactive changes in benefits
and the unrecognized net transition asset arising out of the adoption of
Statement of Financial Accounting Standards No. 87, "Employers' Accounting for
Pensions," are being amortized as a credit to pension cost over the average
remaining service periods for covered employees.
At December 31, 1994 and 1993, GPUSC had accumulated pension obligations
in excess of amounts accrued; as a result, additional minimum liabilities in
the amounts of $.7 million and $1.3 million, net of deferred income taxes of
$.5 million and $1 million, respectively, are reflected as reductions in
Retained Earnings.
F-51
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
Savings Plans:
The GPU System also maintains savings plans for substantially all
employees. These plans provide for employee contributions up to specified
limits. The GPU System's savings plans provide for various levels of matching
contributions. The matching contributions for the GPU System for 1994, 1993
and 1992 were $12.7 million, $12.2 million and $11.2 million, respectively.
Postretirement Benefits Other than Pensions:
The GPU System provides certain retiree health care and life insurance
benefits for substantially all employees who reach retirement age while
working for the GPU System. Health care benefits are administered by various
organizations. A portion of the costs are borne by the participants. For
1992, the annual premium costs associated with providing these benefits
totaled approximately $16.6 million.
Effective January 1, 1993, the GPU System 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 GPU System 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 1994 and 1993 follows:
(In Millions)
1994 1993
Service cost-benefits attributed to service
during the period $14.6 $ 12.5
Interest cost on the accumulated postretirement
benefit obligation 37.0 34.3
Expected return on plan assets (7.0) (3.4)
Amortization of transition obligation 18.1 18.1
Other amortization, net 2.1 -
Net periodic postretirement benefit cost 64.8 61.5
Less, deferred for future recovery (15.8) (27.5)
Postretirement benefit cost, net of deferrals $49.0 $ 34.0
The above 1994 amounts do not include a pre-tax charge to earnings of
$30 million relating to the VERP.
The actual return on the plans' assets for the years 1994 and 1993 was a
gain of $2.3 million and $3.9 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as
follows:
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<PAGE>
General Public Utilities Corporation and Subsidiary Companies
(In Millions)
1994 1993
Accumulated Postretirement Benefit Obligation:
Retirees $ 291.7 $ 207.1
Fully eligible active plan participants 67.2 72.4
Other active plan participants 197.6 223.1
Total accumulated postretirement
benefit obligation (APBO) $ 556.5 $ 502.6
APBO $(556.5) $(502.6)
Plan assets at fair value 129.0 47.1
APBO in excess of plan assets (427.5) (455.5)
Less: Unrecognized net loss 46.9 65.2
Unrecognized prior service cost 2.5 2.9
Unrecognized transition obligation 313.3 343.6
Accrued postretirement benefit liability $ (64.8) $ (43.8)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
The GPU System intends to continue funding amounts for postretirement
benefits with an independent trustee, as deemed appropriate from time to time.
The plan assets include equities and fixed income securities.
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $39 million decrease in the
APBO as of December 31, 1994. Also, in 1994, the APBO increased by $35
million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible
for Medicare, then 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 31, 1995. The effect of a 1% annual increase in these
assumed cost trend rates would increase the accumulated postretirement benefit
obligation by approximately $53 million as of December 31, 1994 and the
aggregate of the service and interest cost components of net periodic
postretirement health-care cost by approximately $6 million.
In JCP&L's 1993 base rate proceeding, the NJBPU allowed JCP&L 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 (EITF) Issue 92-12, "Accounting
for OPEB Costs by Rate-Regulated Enterprises", JCP&L is deferring the amounts
above that level. Met-Ed began deferring the incremental postretirement
benefit costs, charged to expense, associated with the adoption of FAS 106 and
in accordance with EITF Issue 92-12, as authorized by the PaPUC in its 1993
base rate order.
F-53
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
In 1993, Penelec began deferring its FAS 106 incremental expense in
accordance with the PaPUC's generic policy statement permitting the deferral
of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the
PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of
such costs, stating that FAS 106 expense incurred after January 1, 1993 (the
effective date for the accounting change) but prior to its next base rate case
could not be deferred for future recovery, and that to assure such future
recovery constituted retroactive ratemaking. As a result of the Court's
decision, in the second quarter of 1994, Penelec determined that deferred
incremental FAS 106 expense was not likely to be recovered and wrote off $14.6
million deferred since January 1993. In addition, $4 million of Penelec's
unrecognized transition obligation resulting from employees who elected to
participate in the VERP was also written off during the second quarter of
1994. During the remainder of 1994, Penelec continued to expense FAS 106
costs ($4.2 million) and anticipates annual charges to income of approximately
$9 million, beginning in 1995, which represents continued amortization of the
transition obligation along with current accruals of FAS 106 expense for
active employees.
The Corporation believes that the Commonwealth Court ruling does not
affect Met-Ed because it received PaPUC authorization as part of its 1993
retail base rate order to defer incremental FAS 106 expense. JCP&L received
similar authorization in a 1993 NJBPU base rate order.
10. 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 Subsidiaries participated with nonaffiliated utilities
in the following jointly owned stations at December 31, 1994:
Balance (In Millions)
% Accumulated
Station Owner Ownership Investment Depreciation
Homer City Penelec 50 $441.2 $158.7
Conemaugh Met-Ed 16.45 138.9 27.9
Keystone JCP&L 16.67 84.5 20.8
Yards Creek JCP&L 50 26.4 6.7
Seneca Penelec 20 16.4 4.5
11. LEASES
The GPU System's capital leases consist primarily of leases for nuclear
fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled
$148 million and $150 million, respectively (net of amortization of
$112 million and $69 million, respectively). The recording of capital leases
has no effect on net income because all leases, for ratemaking purposes, are
considered operating leases.
F-54
<PAGE>
General Public Utilities Corporation and Subsidiary Companies
The Subsidiaries 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 presently leased material
will be replaced by additional leased material. The Subsidiaries 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, 1994, 1993 and
1992 these amounts were $50 million, $66 million and $74 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 Subsidiaries are required to
purchase all nuclear fuel then under lease at a price that will allow the
lessor to recover its net investment.
JCP&L and Met-Ed have sold and leased back substantially all of their
respective ownership interests in the Merrill Creek Reservoir project. The
minimum lease payments under these operating leases, which have remaining
terms of 38 years, average approximately $3 million annually for each company.
F-55
<PAGE>
<TABLE>
General Public Utilities Corporation and Subsidiary Companies
GENERAL PUBLIC UTILITIES CORPORATION
and Subsidiary Companies
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
<CAPTION>
Column A Column B Column C Column D Column E
Additions
Balance (1) (2)
at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1994
Allowance for doubtful
accounts $ 7,361 $14,105 $ 5,031(a) $19,067(b) $ 7,430
Allowance for inventory
obsolescence 5,681 - 814(c) 1,572(d) 4,923
Year Ended December 31, 1993
Allowance for doubtful
accounts $ 7,433 $13,768 $ 4,393(a) $18,233(b) $ 7,361
Allowance for inventory
obsolescence 7,168 80 56(c) 1,623(d) 5,681
Year Ended December 31, 1992
Allowance for doubtful
accounts $ 5,955 $15,344 $ 4,275(a) $18,141(b) $ 7,433
Allowance for inventory
obsolescence 12,701 286 322(c) 6,141(d) 7,168
____________________________
<FN>
(a) Recovery of accounts previously written off.
(b) Accounts receivable written off.
(c) Primarily sale of inventory previously written off, and reestablishment of zero value
inventory at JCP&L.
(d) Inventory written off.
</FN>
F-56</TABLE>
<PAGE>
<TABLE>
Jersey Central Power & Light Company
COMPANY STATISTICS
<CAPTION>
For the Years Ended December 31, 1994 1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Capacity at Company Peak (In MW):
Company-owned 2 765 2 839 2 826 2 836 2 821 2 823
Contracted 2 403 2 033 2 364 1 995 1 600 1 661
Total capacity (a) 5 168 4 872 5 190 4 831 4 421 4 484
Hourly Peak Load (In MW):
Summer peak 4 292 4 564 4 149 4 376 4 047 3 972
Winter peak 3 242 3 129 3 135 3 222 2 879 3 189
Reserve at Company peak (%) 20.4 6.7 25.1 10.4 9.2 12.9
Load factor (%) (b) 50.8 49.1 51.7 49.3 51.3 53.3
Sources of Energy:
Energy sales (In Thousands of MWH):
Net generation 7 770 8 594 8 514 7 354 8 649 8 372
Power purchases and interchange 11 886 12 073 12 447 13 077 10 854 11 109
Total sources of energy 19 656 20 667 20 961 20 431 19 503 19 481
Company use, line loss, etc. (1 405) (2 026) (2 075) (1 799) (1 404) (1 641)
Total 18 251 18 641 18 886 18 632 18 099 17 840
Energy mix (%):
Coal 9 10 10 9 9 10
Nuclear 27 30 30 21 29 22
Utility purchases and interchange 35 35 34 47 46 50
Nonutility purchases 25 23 25 18 10 7
Other (gas, hydro & oil) 4 2 1 5 6 11
Total 100 100 100 100 100 100
Energy cost (In Mills per KWH):
Coal 14.69 14.06 13.08 14.66 13.75 13.18
Nuclear 6.65 6.80 6.48 7.34 7.28 8.74
Utility purchases and interchange 18.88 18.35 18.72 20.50 22.30 22.32
Nonutility purchases 61.85 60.49 59.99 60.45 64.13 63.20
Other (gas & oil) 36.72 43.26 37.99 31.57 37.40 36.60
Average 26.98 25.34 25.57 25.07 22.33 23.09
Electric Energy Sales (In Thousands of MWH):
Residential 7 094 6 983 6 568 6 757 6 497 6 615
Commercial 6 586 6 474 6 207 6 243 6 104 6 003
Industrial 3 673 3 689 3 723 3 816 3 790 3 899
Other 76 369 389 383 382 388
Sales to customers 17 429 17 515 16 887 17 199 16 773 16 905
Sales to other utilities 822 1 126 1 999 1 433 1 326 935
Total 18 251 18 641 18 886 18 632 18 099 17 840
Operating Revenues (In Millions):
Residential $ 855 $ 835 $ 735 $ 750 $ 665 $ 651
Commercial 721 699 630 620 559 529
Industrial 322 321 306 309 281 279
Other 21 40 40 39 37 38
Revenues from customers 1 919 1 895 1 711 1 718 1 542 1 497
Sales to other utilities 19 31 53 45 54 43
Total electric revenues 1 938 1 926 1 764 1 763 1 596 1 540
Other revenues 15 10 10 10 9 9
Total $1 953 $1 936 $1 774 $1 773 $1 605 $1 549
Price per KWH (In Cents):
Residential 12.06 11.90 11.15 11.11 10.24 9.84
Commercial 10.92 10.78 10.08 9.93 9.16 8.80
Industrial 8.78 8.70 8.20 8.08 7.43 7.15
Total sales to customers 11.00 10.80 10.09 9.99 9.19 8.85
Total sales 10.61 10.31 9.30 9.47 8.82 8.63
Kilowatt-hour Sales per Residential Customer 8 690 8 669 8 264 8 585 8 303 8 534
Customers at Year-End (In Thousands) 924 911 897 887 881 871
<FN>
(a) Summer ratings at December 31, 1994 of owned and contracted capacity
were 2,765 MW and 1,976 MW, respectively.
(b) The ratio of the average hourly load in kilowatts supplied during the
year to the peak load occurring during the year.
</FN>
F-57
</TABLE>
<PAGE>
<TABLE>
Jersey Central Power & Light Company
SELECTED FINANCIAL DATA
<CAPTION> (In Thousands)
For the Years Ended December 31, 1994* 1993 1992 1991** 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $1 952 425 $1 935 909 $1 774 071 $1 773 219 $1 604 962 $1 549 088
Other operation and
maintenance expense 526 623 460 128 424 285 433 562 398 598 403 174
Net income 162 841 158 344 117 361 153 523 126 532 131 902
Earnings available
for common stock 148 046 141 534 96 757 134 083 110 219 121 027
Net utility plant
in service 2 620 212 2 558 160 2 429 756 2 365 987 2 234 243 2 082 104
Cash construction
expenditures 243 878 197 059 218 874 241 774 271 588 270 255
Total assets 4 336 788 4 269 155 3 886 904 3 695 645 3 531 898 3 290 650
Long-term debt 1 168 444 1 215 674 1 116 930 1 022 903 927 686 899 058
Long-term obligations
under capital leases 4 362 6 966 4 645 5 471 4 459 2 886
Cumulative preferred stock
with mandatory redemption 150 000 150 000 150 000 100 000 100 000 -
Return on average
common equity 11.2% 11.1% 8.0% 11.9% 10.5% 12.5%
<FN>
* Results for 1994 reflect a decrease in earnings of $30.4 million after-tax
for costs related to the Voluntary Enhanced Retirement Programs and an
increase in earnings of $7.4 million after-tax for interest income
from refunds of previously paid federal income taxes related to the tax
retirement of
TMI-2.
** Results for 1991 reflect an increase in earnings available for common
stock of $27.1 million after-tax for an accounting change recognizing
unbilled revenues and a decrease in earnings of $5.7 million
after-tax for estimated TMI-2 costs.
</FN>
F-58
</TABLE>
<PAGE>
Jersey Central Power & Light Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings available for common stock increased $6.5 million to
$148 million due principally to increases in sales resulting from growth in
the number of customers and colder winter weather as compared to last year,
and an increase in revenues attributable to a February 1993 retail base rate
case. Also contributing to the earnings increase was reduced reserve capacity
expense, first quarter interest income of $7.4 million after-tax from refunds
of previously paid federal income taxes related to the tax retirement of Three
Mile Island Unit 2 (TMI-2), and a performance award for the operation of the
Company's nuclear generating stations.
The earnings increase was partially offset by a second quarter after-tax
charge of $30.4 million related to the Voluntary Enhanced Retirement Programs
and increased other operation and maintenance (O&M) expense, which included
higher emergency and winter storm repairs.
Earnings available for common stock increased $44.8 million to
$141.5 million in 1993 due principally to additional revenues resulting from a
February 1993 retail base rate increase and higher customer sales due
primarily to the significantly warmer 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 O&M expense, the write-off of approximately
$6.2 million (after-tax) of costs related to the cancellation of proposed
power supply and transmission facilities agreements, and higher depreciation
expense and financing costs associated with additions to utility plant.
Financing costs reflect savings derived from the early redemption of first
mortgage bonds and preferred stock.
The Company's return on average common equity was 11.2% for 1994 as
compared with 11.1% for 1993.
OPERATING REVENUES:
Revenues increased 0.9% to $1.95 billion in 1994 after increasing 9.1% to
$1.94 billion in 1993. The components of these changes are as follows:
(In Millions)
1994 1993
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ 21.5 $ 37.5
Rate increase 20.8 108.2
Energy revenues (31.0) 13.4
Other revenues 5.2 2.7
Increase in revenues $ 16.5 $161.8
F-59
<PAGE>
Jersey Central Power & Light Company
Kilowatt-hour revenues
1994
The increase in KWH revenues was due principally to increases in sales
resulting from new customer additions and the colder winter weather as
compared to last year. New customer growth occurred primarily in the
residential and commercial sectors.
1993
KWH revenues increased due principally to higher third quarter sales
resulting from the significantly warmer 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.
Rate increase
1993
In February 1993, the New Jersey Board of Public Utilities (NJBPU)
authorized a $123 million increase in retail base rates, or approximately 7%
annually.
Energy revenues
1994
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 decreased as a result of a January 1994 decrease in
energy cost rates in effect, the loss of wholesale customers and decreased KWH
sales to other utilities.
1993
Energy revenues increased as a result of increased KWH sales to ultimate
customers partially offset by decreased sales to other utilities.
Other revenues
1994 and 1993
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.
OPERATING EXPENSES:
Power purchased and interchanged
1994
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these
F-60
<PAGE>
Jersey Central Power & Light Company
cost increases are substantially recovered through the Company's energy
clause. However, earnings were favorably affected by lower reserve capacity
expense resulting primarily from the expiration of a purchase contract with
another utility and a reduction in purchases from affiliated companies. The
decrease in expense was partially offset by higher nonutility generation
purchases.
1993
Earnings 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 due to a decrease in nonutility generation
purchases.
Other operation and maintenance
1994
The increase in other O&M expense was primarily attributable to a $46.9
million pre-tax charge for costs related to the Voluntary Enhanced Retirement
Programs. Increases were also due to higher emergency and winter storm
repairs and the accrual of additional payroll expense under an expanded
employee incentive compensation program designed to tie pay increases more
closely to business results and enhance productivity.
1993
Other O&M expense increased primarily due to emergency and storm-related
activities and higher tree trimming expense. Other O&M 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.
Depreciation and amortization
1994 and 1993
Depreciation and amortization expense increased due to increases in
utility plant and additional amortization of deferred assets. The increases
in utility plant consisted primarily of additions to existing generating
facilities to maintain system reliability and additions to the transmission
and distribution system related to new customer growth.
Taxes, other than income taxes
1994 and 1993
Generally, changes in taxes other than income taxes do not significantly
affect earnings as they are substantially recovered in revenues.
F-61
<PAGE>
Jersey Central Power & Light Company
OTHER INCOME AND DEDUCTIONS:
Other income, net
1994
The increase in other income, net was due principally to first quarter
interest income resulting from refunds of previously paid federal income taxes
related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted
in a refund for the tax years after TMI-2 was retired. The effect on pre-tax
earnings was an increase of $14.7 million.
1993
The reduction in other income, net was due to the write-off of
$9.3 million pre-tax of costs related to the cancellation of proposed power
supply and transmission facilities agreements between the Company and its
affiliates and Duquesne Light Company. The decrease was 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.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
1994
Interest on long-term debt decreased due to the retirement of $60 million
of secured medium-term notes and lower interest rates associated with the
refinancing in 1993 of higher cost debt. Other interest expense was higher
due primarily to an increase in the average levels of short-term borrowings
outstanding. Other interest expense also increased due to the tax retirement
of TMI-2, which resulted in a $3.3 million pre-tax increase in interest
expense on additional amounts owed for tax years in which depreciation
deductions with respect to TMI-2 had been taken.
1993
Interest on long-term debt increased due primarily 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.
1994 and 1993
Preferred dividends decreased due to the redemption in 1993 of an
aggregate of $50 million of preferred stock.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs were $304 million in 1994, consisting of cash
construction expenditures of $244 million and amounts for maturing obligations
F-62
<PAGE>
Jersey Central Power & Light Company
of $60 million. During 1994, construction funds were used primarily to
maintain and improve existing generation facilities and the transmission and
distribution system, proceed with various clean air compliance projects, and
build a new generation facility. For 1995, the Company's construction
expenditures are estimated to be $220 million, consisting mainly of
$182 million for ongoing system development, $20 million for clean air
compliance requirements, and $16 million for the continued construction of a
new generation facility. The 1995 estimated reduction is largely due to the
completion in 1994 of construction expenditures during an outage at the
Company's Oyster Creek Nuclear Generating Station. Expenditures for maturing
debt are expected to be $47 million for 1995 and $36 million for 1996
including amounts for mandatory redemptions of preferred stock. In the late
1990s, construction expenditures are expected to include substantial amounts
for additional clean air requirements and other Company needs. Management
estimates that approximately two-thirds of the Company's 1995 capital needs
will be satisfied through internally generated funds.
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 TMI-1) of nuclear fuel costs may be
outstanding at any one time. The Company's share of nuclear fuel capital
leases at December 31, 1994 totaled $99 million. When consumed, portions of
the presently leased material will be replaced by additional leased material
at a rate of approximately $41 million annually. In the event the needed
nuclear fuel cannot be leased, the associated capital requirements would have
to be met by other means.
FINANCING:
The Company anticipates receiving regulatory authorization in the first
quarter of 1995 to issue, through a special-purpose finance subsidiary, up to
$125 million of Monthly Income Preferred Securities. A portion of these
securities is expected to be issued in 1995 to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and
Exchange Commission (SEC) to issue up to five million shares of additional
common stock through 1996. The proceeds from the sale of such additional
common stock would be used to increase the Company and its affiliates' common
equity ratios and reduce GPU short-term debt. GPU will monitor the capital
markets as well as its capitalization ratios relative to its targets to
determine whether, and when, to issue such shares.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), 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.
F-63
<PAGE>
Jersey Central Power & Light Company
The Company's cost of capital and ability to obtain external financing is
affected by its security ratings, which are periodically reviewed by the three
major credit rating agencies. In June 1994, Standard & Poor's Corporation
(S&P) and Duff & Phelps lowered the Company's security ratings citing
relatively high customer rates in an increasingly competitive environment and
a perceived credit risk associated with large purchased power commitments.
Moody's Investors Service (Moody's) downgraded the Company's security ratings
in August 1994 due, in part Moody's said, to the Company's relatively high
cost structure. The Company's FMBs are currently rated at an equivalent of a
BBB+ by the three major credit rating agencies, while the preferred stock
issues have been assigned an equivalent of BBB. In addition, the Company's
commercial paper is rated as having good credit quality. Although credit
quality has been reduced, the Company's credit ratings remain above investment
grade.
In 1994, the S&P rating outlook, which is used to assess the potential
direction of an issuer's long-term debt rating over the intermediate- to
longer-term, was revised to "stable" from "negative" for the Company. The
outlook reflects S&P's judgment that the Company's newly assigned BBB+ bond
rating should be sustainable going forward without further decline anticipated
in the near term. S&P also assigned the Company a "low average" business
position, a financial benchmarking standard for rating the debt of electric
utilities to reflect the changing risk profiles resulting primarily from the
intensifying competitive pressures in the industry.
In June 1994, Moody's announced that it developed a new method to
calculate the minimum price an electric utility must charge its customers in
order to recover all of its generation costs. Moody's believes that an
assessment of relative cost position will become increasingly critical to the
credit analysis of electric utilities in a competitive marketplace. Specific
rating actions are not anticipated, however, until the pace and implications
of utility market deregulation are more certain.
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 currently has interest and
dividend coverage ratios well in excess of indenture and charter restrictions.
The ability to issue securities in the future will depend on interest and
dividend coverages at that time. Present plans call for the Company to issue
long-term debt and Monthly Income Preferred Securities during the next three
years to finance construction activities, fund the redemption of maturing
senior securities and, depending on the level of interest rates, refinance
outstanding senior securities.
CAPITALIZATION:
The Company targets capitalization ratios that should warrant sufficient
credit quality ratings to permit capital market access at reasonable costs.
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
F-64
<PAGE>
Jersey Central Power & Light Company
ratings. GPU's financing plans contemplate security issuances in 1995 to
strengthen the equity component of the Company and its affiliates' capital
structures. The Company's targets and actual capitalization ratios are as
follows:
Capitalization
Target Range 1994 1993 1992
Common equity 48-51% 47% 47% 47%
Preferred equity 8-10 7 7 9
Notes payable and
long-term debt 44-39 46 46 44
100% 100% 100% 100%
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated
monopolies. Over the last few years, however, market forces combined with
state and federal actions, have laid the foundation for the continued
development of additional competition in the electric utility industry.
In May 1994, the NJBPU approved the Company's request to implement a new
rate initiative designed to retain and expand the economic base in its
service territory. Under the contract rate service, the Company may enter
into individual contracts to provide electric service to large commercial and
industrial customers. This initiative will allow the Company more
flexibility in responding to competitive pressures.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking regarding the recovery by utilities of
legitimate and verifiable stranded costs. Costs incurred by a utility to
provide integrated electric service to a franchise customer become stranded
when that customer subsequently purchases power from another supplier using
the utility's transmission services. Among other things, the FERC proposed
that utilities be allowed under certain circumstances to recover such
stranded costs associated with existing wholesale customer contracts, but not
under new wholesale contracts unless expressly provided for in the contract.
While it stated a "strong" policy preference that state regulatory agencies
address recovery of stranded retail costs, the FERC also set forth
alternative proposals for how it would address the matter if the states
failed to do so. Subsequent to FERC's Notice of Proposed Rulemaking,
however, the U.S. Court of Appeals for the District of Columbia, in an
unrelated case, questioned the FERC's authority to permit utilities to
recover stranded costs. The Court remanded the matter to the FERC for it to
conduct an evidentiary hearing in the case to determine whether, among other
things, permitting stranded cost recovery was so inherently anticompetitive
that it violates antitrust laws. While largely supported by the electric
utility industry, the Proposed Rulemaking has been strongly opposed by other
groups. There can be no assurance as to the outcome of this proceeding.
F-65
<PAGE>
Jersey Central Power & Light Company
In October 1994, the FERC issued a policy statement regarding pricing for
electric transmission services. The policy statement contains five
principles that will provide the foundation for the FERC's analyses of all
subsequent transmission rate proposals. Recognizing the evolution of a more
competitive marketplace, the FERC contends that it is critical that
transmission services be priced in a manner that appropriately compensates
transmission owners and creates adequate incentives for efficient system
expansion.
In November 1994, the NJBPU issued a draft New Jersey Energy Master Plan
Phase I Report promoting regulatory policy changes intended to move the
state's electric and gas utilities into a competitive marketplace. In the
draft, the NJBPU recommends, among other things, the adoption of 1) rate-
flexibility legislation to allow utilities to compete in order to retain and
attract customers; 2) alternatives to rate base/rate-of-return regulation; 3)
consumer protection standards to ensure that captive ratepayers do not
subsidize competitive activities; and 4) an integrated resource planning and
competitive supply-side procurement process to streamline the regulatory
review process, lower costs, and ensure that the state's environmental and
energy conservation goals are met in a competitive marketplace. Although the
NJBPU proposes actions and regulatory reforms that encourage competition, the
draft Plan calls for an evolutionary transition toward open markets. The
recommendations are largely intended to be interim measures while the NJBPU
investigates other issues, including retail wheeling and stranded costs, that
are likely to affect the future of the electric utility industry. The New
Jersey Energy Master Plan is being developed in three phases, with Phase I
scheduled to be adopted in March 1995 and the remaining phases expected to be
concluded by year-end 1995.
In 1994, the SEC issued for public comment a Concept Release regarding
modernization of the Public Utility Holding Company Act of 1935 (Holding
Company Act). GPU regards the Holding Company Act as a significant
impediment to competition and supports its repeal. In addition, GPU believes
that the Public Utility Regulatory Policies Act of 1978 (PURPA) should be
fundamentally reformed given the burdens being placed on electric utilities
by PURPA mandated uneconomic long-term power purchase agreements with
nonutility generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related
actions as a result of its ongoing strategic planning activities. Responding
to its assessment that competition in the electric utility industry is likely
to accelerate, GPU proceeded to implement two major organizational changes as
well as other programs designed to reduce costs and strengthen GPU's
competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the
non-nuclear generation facilities owned by the Company and its affiliates as
well as undertake responsibility to construct any new non-nuclear generation
F-66
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Jersey Central Power & Light Company
facilities which the Company and its affiliates may need in the future. By
forming GPU Generation Corporation (GPUGC), GPU will consolidate and
streamline the management of these generation facilities, and seek to apply
management and operating efficiency techniques similar to those employed in
more competitive industries. This initiative is intended to bring the
Company and its affiliates' generation costs more in line with projected
market prices. GPU Nuclear Corporation is engaging in a search for parallel
opportunities. The Company and its affiliates received regulatory approvals
to enter into an operating agreement with GPUGC from the NJBPU and
Pennsylvania Public Utility Commission. SEC authorization is expected to be
received in 1995.
The second part of the realignment includes the management combination of
the Company's affiliates, Metropolitan Edison Company and Pennsylvania
Electric Company. This action is intended to increase effectiveness and
lower costs of Pennsylvania customer operations and service functions.
Other organizational realignments, designed to streamline management and
reduce costs, were also implemented throughout the GPU System in 1994. In
addition, GPU expanded employee participation in its incentive compensation
program to tie pay increases more closely to business results and enhance
productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System
workforce accepted the Voluntary Enhanced Retirement Programs. Future
payroll and benefits savings, which are estimated to be $75 million annually
(of which the Company's share is $31 million), began in the third quarter and
reflect limiting the replacement of employees up to ten percent of those
retired. Retirement benefits will be substantially paid from pension and
postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the
electric utility industry that calls into question the assumptions regarding
the recovery of certain costs through ratemaking. As the utility industry
continues to experience an increasingly competitive environment, GPU is
attempting to assess the impact that these and other changes will have on the
Company and its affiliates' financial position. For additional information
regarding the other changes that may have an adverse effect on the Company,
see the Competition and the Changing Regulatory Environment section of Note 1
to the Financial Statements.
Due to the current availability of excess capacity in the marketplace,
the cost of near- to intermediate-term regional energy supply from existing
facilities, as evidenced by the results of the Company's all-source
competitive supply solicitation conducted in 1994, is less than the rates in
virtually all of the Company's nonutility generation agreements. In
addition, the projected cost of energy from new supply sources is now lower
than was expected in the recent past due to improvements in power plant
technologies and reduced fuel prices.
F-67
<PAGE>
Jersey Central Power & Light Company
The long-term nonutility generation agreements included in the Company's
supply plan have been entered into pursuant to the requirements of PURPA and
state regulatory directives. The Company intends to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company is also attempting to renegotiate, and in some cases buy out,
existing high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility
generation costs from customers by the NJBPU, there can be no assurance that
the Company will continue to recover these costs throughout the terms of the
related agreements. The Company currently estimates that in 1998, when all
of these nonutility generation projects are scheduled to be in-service, above
market payments (benchmarked against the expected cost of electricity
produced by a new gas-fired combined cycle facility) will range from
$120 million to $190 million annually.
THE SUPPLY PLAN:
Under existing retail regulation, supply planning in the electric utility
industry is directly related to projected growth in the franchise service
territory. At this time, management cannot estimate the timing and extent to
which retail electric competition will affect the Company's supply plan. As
the Company prepares to operate in an increasingly competitive environment,
its supply plan currently focuses on maintaining the existing customer base
by offering competitively priced electricity.
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" market purchases, and
avoidance of long-term firm commitments.
Over the next five years, the Company is projected to experience an
average growth in sales to customers of about 2% annually. These increases
are expected to result from continued economic growth in the service
territory and a slight increase in customers. To meet this growth, assuming
the continuation of existing retail electric regulation, the Company's plan
consists of the continued utilization of existing generation facilities
combined with power purchases, the construction of a new facility, and the
utilization of capacity of its affiliates. The plan also includes the
continued promotion of economic energy-conservation and load-management
programs.
F-68
<PAGE>
Jersey Central Power & Light Company
The Company's present strategy includes minimizing the financial exposure
associated with new long-term purchase commitments and the construction of
new facilities by evaluating these options in terms of an unregulated power
market. The Company will take necessary actions to avoid adding 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.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility
generators, the replacement of expiring utility purchase contracts at lower
costs, and the construction of a new peaking unit. The supply plan also
includes the addition of approximately 265 MW of currently uncommitted
capacity. Additional capacity needs are principally related to the
expiration of existing commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility
generators under which a total of 882 MW of capacity is currently in service
and about an additional 294 MW are currently scheduled or anticipated to be
in service by 1998.
In January 1994, the Company issued an all-source solicitation for the
short- to intermediate-term supply of energy and capacity to determine and
evaluate the availability of competitively priced power supply options. The
Company is completing contract negotiations with three suppliers to purchase
about 350 MW of capacity beginning in 1996, increasing to approximately 700
MW by 1999, for terms of up to eight years. The Company will continue to
evaluate additional economic purchase opportunities as both demand and supply
market conditions evolve and conduct further solicitations to fulfill, if
warranted, a significant part of the uncommitted sources identified in GPU's
supply plan.
The Company has commenced construction of a 141 MW gas-fired combustion
turbine at its Gilbert Generating Station. The new facility is estimated to
cost $50 million and, coupled with the retirement of two older units, will
result in a net capacity increase of approximately 95 MW. The project is
expected to be in-service by mid-1996. Petitions have been filed with the
NJBPU by two organizations seeking, among other things, reconsideration of
the NJBPU's order which found that New Jersey's Electric Facility Need
Assessment Act is not applicable to this combustion turbine and that
construction of this facility, without a market test, is consistent with New
Jersey energy policies. This matter is pending.
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially
reduce above-market payments for energy supplied by nonutility generators.
The Company will also continue to take legal, regulatory and legislative
F-69
<PAGE>
Jersey Central Power & Light Company
initiatives to avoid entering into any new power-supply agreements that are
either not needed or, if needed, are not consistent with competitive market
pricing. The following is a discussion of major nonutility generation
activities involving the Company.
In a 1993 order, the NJBPU directed all utilities to identify nonutility
generation contracts which were uneconomic and, therefore, candidates for
buyout or other remedial measures. The Company identified a proposed 100 MW
nonutility generation project as such a candidate, but was unable to
negotiate a buyout or contract repricing to a level consistent with prices of
replacement power. The NJBPU therefore ordered that hearings be held to
determine whether their order approving the agreement should be modified or
revoked. After hearings commenced in early 1994, the nonutility generator
filed a complaint with the U.S. District Court seeking to enjoin the NJBPU
proceedings on the grounds they were preempted by PURPA. The District Court
dismissed the complaint finding, among other things, that the federal courts
did not have jurisdiction to consider the matter. In January 1995, however,
the U.S. Court of Appeals for the Third Circuit overturned the District Court
decision. The Court of Appeals held, among other things, that once the NJBPU
approves a power purchase agreement under PURPA and approves the utility's
collection of costs from its customers, PURPA preempts the NJBPU from
altering its order approving the contract and the Company's recovery from
customers of its payment to the nonutility generator. The Court of Appeals
reached its decision despite the contract provision that if the NJBPU at any
time in the future disallowed any such rate recovery, the Company's payments
to the nonutility generator would be equally reduced. The Company, the NJBPU
and the New Jersey Division of Rate Advocate have each filed motions for
rehearing with the Court of Appeals.
In 1994, a nonutility generator requested that the NJBPU order the
Company to enter into a long-term agreement to buy capacity and energy. The
Company is contesting this request and the NJBPU has referred this matter to
an Administrative Law Judge for hearings.
In May 1994, the NJBPU issued an order granting two nonutility
generators, aggregating 200 MW, a final in-service date extension for
projects originally scheduled to be operational in 1997. In June 1994, the
Company appealed the NJBPU's decision to the Appellate Division of the New
Jersey Superior Court. The NJBPU order extends the in-service date for one
year plus the period until the Company's appeals are decided.
As part of the effort to reduce above-market payments under nonutility
generation agreements, the Company and its affiliates are seeking to
implement a program under which the natural gas fuel and transportation for
the Company and its affiliates' gas-fired facilities, as well as up to
approximately 1,100 MW of nonutility generation capacity, would be pooled and
managed by a nonaffiliated fuel manager. The Company and its affiliates
believe the plan has the potential to provide substantial savings for their
customers. The Company and its affiliates have begun initial discussions
with the nonutility generators who would be eligible to participate.
Requirements for approval of the plan by state and federal regulatory
agencies are being reviewed.
F-70
<PAGE>
Jersey Central Power & Light Company
Conservation and Load Management
The NJBPU continues to encourage the development of new conservation and
load-management programs. Because the benefits of some of these programs may
not offset program costs, the Company is working to mitigate the impacts
these programs can have on the Company's competitive position in the
marketplace.
The Company continues to conduct demand-side management (DSM) programs
approved in 1992 by the NJBPU. DSM includes utility-sponsored activities
designed to improve energy efficiency in customer electricity use and load-
management programs that reduce peak demand. These Company programs have
resulted in summer peak demand reductions of over 43 MW through 1994.
ENVIRONMENTAL ISSUES:
The Clean Air Act Amendments of 1990 (Clean Air Act) require substantial
reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000.
To comply with the Clean Air Act, the Company expects to spend up to $58
million by the year 2000 for pollution control equipment. Through December
31, 1994, the Company has made capital expenditures of approximately $16
million to comply with the Clean Air Act requirements.
In developing its least-cost plan to comply with the Clean Air Act, the
Company will continue to evaluate the risk of recovering capital investments
compared to increased participation in the emission allowance market and the
use of low-sulfur coal or the early retirement of facilities. These 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 plants are expected to be recoverable through
the current 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, approximately 2,100
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.
F-71
<PAGE>
Jersey Central Power & Light Company
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since
the regulatory process results in a time lag during which increased operating
expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry, the
Company does not plan to take any actions that would increase customers' base
rates over the next several years. Therefore, the control of operating and
capital costs will be essential. As competition and deregulation accelerate,
there can be no assurance as to the recovery of increased operating expense
or utility plant investments.
The Company is committed to long-term cost control and continues to seek
and implement measures to reduce or limit the growth of operating expenses
and capital expenditures, including the associated effects of inflation.
Though currently operating in a regulated environment, the Company's focus
will be less reliant on the ratemaking process, and geared toward continued
performance improvement and cost reduction to facilitate the competitive
pricing of its products and services.
F-72
<PAGE>
Jersey Central Power & Light Company
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1994* 1993 1994** 1993
Operating revenues $486 910 $448 634 $458 897 $463 354
Operating income 71 521 51 411 29 270 57 053
Net income 53 097 30 830 5 175 31 551
Earnings available
for common stock 49 398 26 124 1 476 26 845
In Thousands
Third Quarter Fourth Quarter
1994 1993 1994 1993***
Operating revenues $567 827 $576 268 $438 791 $447 653
Operating income 99 304 98 552 54 183 49 914
Net income 74 573 75 239 29 996 20 724
Earnings available
for common stock 70 875 71 540 26 297 17 025
* Results for the first quarter 1994 reflect an increase in earnings of
$7.4 million after-tax for interest income from refunds of previously
paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of
$30.4 million after-tax for costs related to the Voluntary Enhanced
Retirement Programs.
*** Results for the fourth quarter 1993 reflect a decrease in earnings of
$6.0 million after-tax for the write-off of the Duquesne transactions.
F-73
<PAGE>
Jersey Central Power & Light Company
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 schedule 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 schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedule 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, 1994 and 1993, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted accounting principles.
In addition, in our opinion, the financial statement schedule referred to
above, when considered in relation to the basic financial statements taken as
a whole, presents fairly, in all material respects, the information required
to be included therein.
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 ("TMI-2"). 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.
New York, New York COOPERS & LYBRAND L.L.P.
February 1, 1995
F-74
<PAGE>
Jersey Central Power & Light Company
STATEMENTS OF INCOME
(In Thousands)
For the Years Ended December 31, 1994 1993 1992
Operating Revenues $1 952 425 $1 935 909 $1 774 071
Operating Expenses:
Fuel 94 503 98 683 84 851
Power purchased and interchanged:
Affiliates 18 661 23 681 24 281
Others 579 948 578 131 616 418
Deferral of energy and capacity
costs, net (19 448) 28 726 4 232
Other operation and maintenance 526 623 460 128 424 285
Depreciation and amortization 191 042 182 945 167 022
Taxes, other than income taxes 231 070 228 690 215 507
Total operating expenses 1 622 399 1 600 984 1 536 596
Operating Income Before Income Taxes 330 026 334 925 237 475
Income taxes 75 748 77 995 43 621
Operating Income 254 278 256 930 193 854
Other Income and Deductions:
Allowance for other funds
used during construction 893 2 471 4 015
Other income, net 21 995 6 281 21 519
Income taxes (9 372) (2 847) (8 268)
Total other income and deductions 13 516 5 905 17 266
Income Before Interest Charges 267 794 262 835 211 120
Interest Charges:
Interest on long-term debt 93 477 100 246 92 942
Other interest 14 726 6 530 4 873
Allowance for borrowed funds
used during construction (3 250) (2 285) (4 056)
Total interest charges 104 953 104 491 93 759
Net Income 162 841 158 344 117 361
Preferred stock dividends 14 795 16 810 20 604
Earnings Available for Common Stock $ 148 046 $ 141 534 $ 96 757
The accompanying notes are an integral part of the financial statements.
F-75
<PAGE>
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands)
December 31, 1994 1993
ASSETS
Utility Plant:
In service, at original cost $4 119 617 $3 938 700
Less, accumulated depreciation 1 499 405 1 380 540
Net utility plant in service 2 620 212 2 558 160
Construction work in progress 136 884 102 178
Other, net 123 349 116 751
Net utility plant 2 880 445 2 777 089
Other Property and Investments:
Nuclear decommissioning trusts 165 511 139 279
Nuclear fuel disposal fund 82 920 82 095
Other, net 6 906 5 802
Total other property and investments 255 337 227 176
Current Assets:
Cash and temporary cash investments 1 041 17 301
Special deposits 4 608 7 124
Accounts receivable:
Customers, net 126 760 133 407
Other 16 936 31 912
Unbilled revenues 59 288 57 943
Materials and supplies, at average cost or less:
Construction and maintenance 95 937 102 659
Fuel 18 563 11 886
Deferred income taxes 10 454 28 650
Prepayments 45 880 58 057
Total current assets 379 467 448 939
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 138 294 146 284
Unamortized property losses 104 451 109 478
Deferred income taxes 122 944 110 794
Income taxes recoverable through
future rates 132 642 121 509
Other 323 208 327 886
Total deferred debits and other assets 821 539 815 951
Total Assets $4 336 788 $4 269 155
The accompanying notes are an integral part of the financial statements.
F-76
<PAGE>
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands)
December 31, 1994 1993
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 435 715 435 715
Retained earnings 772 240 724 194
Total common stockholder's equity 1 361 668 1 313 622
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 37 741 37 741
Long-term debt 1 168 444 1 215 674
Total capitalization 2 717 853 2 717 037
Current Liabilities:
Debt due within one year 47 439 60 008
Notes payable 110 356 -
Obligations under capital leases 102 059 89 631
Accounts payable:
Affiliates 34 283 34 538
Other 118 369 95 509
Taxes accrued 22 561 119 337
Deferred energy credits 148 23 633
Interest accrued 29 765 33 804
Other 75 159 50 950
Total current liabilities 540 139 507 410
Deferred Credits and Other Liabilities:
Deferred income taxes 598 843 569 966
Unamortized investment tax credits 72 928 79 902
Three Mile Island Unit 2 future costs 85 273 79 967
Other 321 752 314 873
Total deferred credits and
other liabilities 1 078 796 1 044 708
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 336 788 $4 269 155
The accompanying notes are an integral part of the financial statements.
F-77
<PAGE>
<TABLE>
Jersey Central Power & Light Company
STATEMENTS OF RETAINED EARNINGS
<CAPTION>
(In Thousands)
For the Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Balance at beginning of year $724 194 $644 899 $580 523
Add - Net income 162 841 158 344 117 361
Total 887 035 803 243 697 884
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
8% Series ($8.00 a share) - 1 000 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
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 3 760 2 258
Common stock (not declared on a
per share basis) 100 000 60 000 30 000
Total 114 795 76 810 50 604
Other adjustments, net - 2 239 2 381
Total 114 795 79 049 52 985
Balance at end of year $772 240 $724 194 $644 899
The accompanying notes are an integral part of the consolidated financial statements.
F-78</TABLE>
<PAGE>
<TABLE>
Jersey Central Power & Light Company
STATEMENT OF CAPITAL STOCK
<CAPTION>
December 31, 1994 (In Thousands)
<S> <C>
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, 1994.
(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, 1994.
(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 1995 through 1999, based on issues
outstanding at December 31, 1994, is $45 million. All redemptions are at stated
value of the shares, plus accrued dividends.
</FN>
The accompanying notes are an integral part of the financial statements.
F-79</TABLE>
<PAGE>
<TABLE>
Jersey Central Power & Light Company
STATEMENTS OF CASH FLOWS<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Activities:
Income before preferred stock dividends $ 162 841 $ 158 344 $ 117 361
Adjustments to reconcile income to cash provided:
Depreciation and amortization 209 823 199 201 177 245
Amortization of property under capital leases 27 876 34 333 35 137
Voluntary enhanced retirement program 46 862 - -
Nuclear outage maintenance costs, net (16 182) 1 323 9 144
Deferred income taxes and investment tax
credits, net 35 426 39 139 14 630
Deferred energy and capacity costs, net (19 166) 29 305 4 135
Accretion income (13 541) (14 500) (15 400)
Allowance for other funds used during construction (893) (2 471) (4 015)
Changes in working capital:
Receivables 24 579 (25 579) 934
Materials and supplies 1 221 10 218 (2 737)
Special deposits and prepayments 20 282 (24 672) (12 818)
Payables and accrued liabilities (103 485) (111 061) (3 687)
Other, net (19 537) (26 938) (22 682)
Net cash provided by operating activities 356 106 266 642 297 247
Investing Activities:
Cash construction expenditures (243 878) (197 059) (218 874)
Contributions to decommissioning trusts (17 237) (18 896) (19 008)
Other, net (15 417) (7 695) (15 660)
Net cash used for investing activities (276 532) (223 650) (253 542)
Financing Activities:
Issuance of long-term debt - 548 600 367 396
Increase (decrease) in notes payable, net 110 500 (5 700) (38 100)
Retirement of long-term debt (60 008) (408 527) (282 717)
Capital lease principal payments (31 531) (30 011) (38 029)
Issuance of preferred stock - - 50 000
Redemption of preferred stock - (52 375) (51 635)
Dividends paid on common stock (100 000) (60 000) (30 000)
Dividends paid on preferred stock (14 795) (17 818) (20 758)
Net cash required by financing activities (95 834) (25 831) (43 843)
Net (decrease) increase in cash and temporary
cash investments from above activities (16 260) 17 161 (138)
Cash and temporary cash investments, beginning of year 17 301 140 278
Cash and temporary cash investments, end of year $ 1 041 $ 17 301 $ 140
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 109 094 $ 129 868 $ 103 845
Income taxes paid $ 44 619 $ 42 605 $ 51 714
New capital lease obligations incurred $ 37 699 $ 18 919 $ 35 617
The accompanying notes are an integral part of the financial statements.
F-80</TABLE>
<PAGE>
<TABLE>
Jersey Central Power & Light Company
STATEMENT OF LONG-TERM DEBT
<CAPTION>
December 31, 1994 (In Thousands)
First Mortgage Bonds - Series as noted (a) & (b):
<S> <C> <C> <C> <C>
4 7/8% Series due 1995 $ 17 430 6.78% Series due 2005 $ 50 000
8.64% Series due 1995 5 000 8.25% Series due 2006 50 000
8.70% Series due 1995 25 000 7.90% Series due 2007 40 000
6 1/8% Series due 1996 25 701 7 1/8% Series due 2009 6 300
6.90% Series due 1997 30 000 7.10% Series due 2015 12 200
6 5/8% Series due 1997 25 874 9.20% Series due 2021 50 000
6.70% Series due 1997 20 000 8.55% Series due 2022 30 000
7 1/4% Series due 1998 24 191 8.82% Series due 2022 12 000
6.04% Series due 2000 40 000 8.85% Series due 2022 38 000
9% Series due 2002 50 000 8.32% Series due 2022 40 000
6 3/8% Series due 2003 150 000 7.98% Series due 2023 40 000
7 1/8% Series due 2004 160 000 7 1/2% Series due 2023 125 000
6 3/4% Series due 2025 150 000
Subtotal 1 216 696
Amount due within one year (a) (47 430) $1 169 266
Other long-term debt (net of $9 thousand due within one year) 3 067
Unamortized net discount on long-term debt (3 889)
Total long-term debt $1 168 444
<FN>
(a) For the years 1995, 1996, 1997, 1998 and 1999 the Company has long-term debt maturities
of $47.4 million, $25.7 million, $75.9 million $24.2 million and $.01 million,
respectively.
(b) Substantially all of the utility plant owned by the Company is subject to the lien of its
mortgage.
</FN>
The accompanying notes are an integral part of the financial statements.
F-81</TABLE>
<PAGE>
Jersey Central Power & Light Company
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 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 Energy Initiatives, Inc. (EI), and EI Power,
Inc., which develop, own and operate nonutility generating facilities. All of
the Company's affiliates are wholly owned subsidiaries of GPU. The Company
and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. 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. 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. At December 31, the Company's net
investment in TMI-1, TMI-2 and Oyster Creek, including nuclear fuel, was as
follows:
Net Investment (Millions)
TMI-1 TMI-2 Oyster Creek
1994 $162 $ 89 $817
1993 $173 $ 95 $784
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, 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 its nuclear
plants because of the prevailing design criteria 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 the
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 each plant's
useful life (whether scheduled or premature), the carrying costs of that
F-82
<PAGE>
Jersey Central Power & Light Company
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
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 accident cleanup program was completed in 1990. After receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100
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 and the suppliers of equipment and services to TMI-
2, and are pending in the United States District Court for the Middle District
of Pennsylvania. Some of the claims also seek recovery on the basis of
alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are
not covered by insurance and are not subject to the liability limitations of
the federal Price-Anderson Act ($560 million at the time of the accident),
punitive damage awards could have a material adverse effect on the financial
position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for premium charges deferred in whole or
in major part under such plan, and (c) an indemnity agreement with the NRC,
bringing their total primary and secondary insurance financial protection and
indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers under a reservation of rights with respect to any award of
punitive damages. However, in March 1994, the defendants in the TMI-2
litigation and the insurers agreed that the insurers would withdraw their
reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is likely to begin in 1996. 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
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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. In July 1994, the Court
granted defendants' motion for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals.
In an Order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
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 targets (in 1994 dollars) for TMI-1 is $157 million, of which the
Company's share is $39 million, and $189 million for Oyster Creek. Based on
NRC studies, a comparable funding target for TMI-2 has been developed which
takes the accident into account (see TMI-2 Future Costs). The NRC continues
to study 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 considered 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.
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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 $225 million to $309 million, of which the Company's share
would range from $56 million to $77 million, and $239 to $350 million,
respectively (adjusted to 1994 dollars). In addition, the studies estimated
the cost of removal of nonradiological structures and materials for TMI-1 and
Oyster Creek at $74 million, of which the Company's share is $18 million, and
$48 million, respectively (adjusted to 1994 dollars).
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 and its affiliates charge to expense and
contribute to external trusts amounts collected from customers for nuclear
plant decommissioning and nonradiological costs. In addition, the Company has
contributed amounts written off for TMI-2 nuclear plant decommissioning in
1990 to TMI-2's external trust. Amounts deposited in external trusts,
including the interest earned on these funds, are classified as Nuclear
Decommissioning Trusts on the balance sheet.
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, based on its share
($3.83 million) of an estimate of $15.3 million for TMI-1 and $31.6 million
for Oyster Creek adopted in rate orders issued in 1991 and 1993 by the New
Jersey Board of Public Utilities (NJBPU), for its share of the cost of removal
of nonradiological structures and materials. Collections from customers for
retirement expenditures are deposited in external trusts. Provision for the
future expenditures of these funds has been made in accumulated depreciation,
amounting to $17 million for TMI-1 and $100 million for Oyster Creek at
December 31, 1994. Oyster Creek and TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
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 current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target in
1994 dollars. The Company and its affiliates record escalations, when
applicable, in the liability based upon changes in the NRC funding target.
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The Company and its affiliates have also recorded a liability for incremental
costs specifically attributable to monitored storage. In addition, the Company
and its affiliates have recorded a liability for nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $2
million, of which the Company's share is $.5 million, as of December 31, 1994.
Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and
1993 for the Company are as follows:
(Millions) (Millions)
1994 1993
Radiological Decommissioning $63 $57
Nonradiological Cost of Removal 18 18
Incremental Monitored Storage 5 5
Total $86 $80
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At December 31, 1994, $45 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet,
and $51 million was recoverable from customers and included in Three Mile
Island Unit 2 Deferred Costs on the balance sheet. The Company has expensed
and made a nonrecoverable contribution of $15 million to an external
decommissioning trust. The Company's share of earnings on trust fund deposits
are offset against amounts shown on the balance sheet under Three Mile Island
Unit 2 Deferred Costs as collectible from customers. The NJBPU has granted
decommissioning revenues for the Company's share of the remainder of the NRC
funding target and allowances for the cost of removal of nonradiological
structures and materials. The Company 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 in late
1993, the Company and its affiliates are incurring incremental annual storage
costs of approximately $1 million, of which the Company's share is $.25
million. The Company and its affiliates estimate that the remaining annual
storage costs will total $19 million, of which the Company's share is $5
million, through 2014, the expected retirement date of TMI-1. The Company's
rates reflect its $5 million share of these costs.
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.
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The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station 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 for stabilization of
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 that
station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial 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 two operating reactors (TMI-2 is excluded under
an exemption received from the NRC in 1994), subject to an annual maximum
payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at its
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years beginning at $1.8 million for Oyster Creek and $2.6
million for TMI-1 per week for the first year, decreasing by 20 percent for
years two and three.
Under its insurance policies applicable to nuclear operations and
facilities, the GPU System is subject to retrospective premium assessments of
up to $69 million, of which the Company's share is $41 million, in any one
year, in addition to those payable (up to $20 million, of which the Company's
share is $13 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
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 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation," 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;
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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.
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 any
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 currently.
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 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 at the contract
price all of the power produced up to the contract limits. As of December 31,
1994, facilities covered by these agreements having 882 MW of capacity were in
service. Payments made pursuant to these agreements were $304 million, $292
million and $316 million for 1994, 1993 and 1992, respectively. For the years
1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are
estimated to aggregate $395 million, $556 million, $571 million, $587 million
and $607 million, respectively. These agreements, together with those for
facilities which are not yet in operation, provide for the purchase of
approximately 1,176 MW of capacity and energy by the Company by the mid-to-
late 1990s, at varying prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the GPU System's energy supply needs which has
caused the Company and its affiliates to change their supply strategy to now
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seek shorter-term agreements offering more flexibility (see Management's
Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current
availability of excess capacity in the market place, the cost of near- to
intermediate-term (i.e., one to eight years) energy supply from existing
generation facilities is currently competitively priced. The projected cost
of energy from new generation supply sources has also decreased due to
improvements in power plant technologies and reduced forecasted fuel prices.
As a result of these developments, the rates under virtually all of the
Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources. These agreements have been entered into pursuant to the requirements
of the federal Public Utility Regulatory Policies Act and state regulatory
directives. The Company's and its affiliates' have initiated lawful actions
which are intended to substantially reduce these above market payments. In
addition, the Company and its affiliates intend to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company and its affiliates are also attempting to renegotiate, and in some
cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the NJBPU and the
Pennsylvania Public Utility Commission (PaPUC), there can be no assurance that
the Company and its affiliates will continue to be able to recover these costs
throughout the term of the related agreements. The GPU System currently
estimates that in 1998, when substantially all of the these nonutility
generation projects are scheduled to be in service, above market payments
(benchmarked against the expected cost of electricity produced by a new gas-
fired combined cycle facility) will range from $300 million to $450 million
annually, of which the Company's share will range from $120 million to $190
million annually. Moreover, efforts to lower these costs have led to disputes
before both the NJBPU and the PaPUC, as well as to litigation, and may result
in claims against the Company and its affiliates for substantial damages.
There can be no assurance as to the outcome of these matters.
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, decommission or clean up waste disposal and other sites currently
or formerly used by it, including formerly owned manufactured gas plants and
mine refuse piles and generating facilities, 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.
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To comply with the federal Clean Air Act Amendments (Clean Air Act) of
1990, the Company expects to spend up to $58 million for air pollution control
equipment by the year 2000. In developing its least-cost plan to comply with
the Clean Air Act, the Company will continue to evaluate major capital
investments compared to participation in the emission allowance market and the
use of low-sulfur fuel or retirement of facilities.
The Company has been notified by the EPA and state environmental
authorities 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 7 hazardous and/or toxic waste sites. In
addition, the Company has been requested to voluntarily participate in the
remediation or 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 Company has also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
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.
The Company has entered into agreements with the New Jersey Department
of Environmental Protection 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. As of December
31, 1994, the Company has an estimated environmental liability of $32 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 1993, the NJBPU approved a mechanism similar to the Company's
Levelized Energy Adjustment Clause (LEAC) for the recovery of future
manufactured gas plant remediation costs when expenditures exceed prior
collections. The NJBPU 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. A final NJBPU order dated December
16, 1994 indicated that interest is to be accrued retroactive to June 1993.
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The Company is pursuing reimbursement of the above costs from its insurance
carriers. In November 1994, the Company filed a complaint with the Superior
Court of New Jersey against several of its insurance carriers, relative to
these manufactured gas plant sites. The Company requested the Court to order
the insurance carriers to reimburse the Company for all amounts it has paid,
or may be required to pay, in connection with the remediation of the sites.
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.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement
Programs (VERP) to certain employees. The enhanced retirement programs were
part of a corporate realignment undertaken in 1994. Approximately 82% of
eligible GPU System employees accepted the retirement programs, resulting in a
pre-tax charge to earnings of $127 million, of which the Company's share is
$47 million. These charges are included as Other Operation and Maintenance on
the income statement.
The Company's construction programs, for which substantial commitments
have been incurred and which extend over several years, contemplate
expenditures of $220 million during 1995. As a consequence of reliability,
licensing, environmental and other requirements, 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 such costs through the
ratemaking process, but recognizes that recovery is not assured.
The Company has entered into a long-term contract with a nonaffiliated
mining company for the purchase of coal for the Keystone generating station in
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 under the contract is based on
adjustments of indexed cost components. The Company's share of the cost of
coal purchased under this agreement is expected to aggregate $21 million for
1995.
The Company and its affiliates have entered into agreements and the
Company is completing contract negotiations with three other utilities to
purchase capacity and energy for various periods through 2004. These
agreements, including contracts under negotiation, will provide for up to
1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW by 2004. For the
years 1995, 1996, 1997, 1998, and 1999, the Company's share of payments
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pursuant to these agreements are estimated to aggregate $202 million, $175
million, $162 million, $145 million and $128 million, respectively. The
Company's contract negotiations are the result of its all-source solicitation
for competitively priced, short- to intermediate-term energy and capacity,
described in the New Energy Supplies section of Management's Discussion and
Analysis.
The NJBPU 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 Division of the Ratepayer Advocate (Ratepayer
Advocate), 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 1993, the Company and the other New Jersey electric utilities filed motions
for summary judgment with the NJBPU. Ratepayer Advocate 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 LEAC periods would be approximately $102 million. In 1994,
the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent
LEACs remain open for further investigation. This matter is pending before a
NJBPU Administrative Law Judge. Management estimates that the potential
exposure for LEAC periods subsequent to 1991 is approximately $67 million
through February 1996, the end of the next LEAC period. There can be no
assurance as to the outcome of this proceeding.
The Company's two operating nuclear units are subject to the NJBPU'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 $11 million. While a capacity
factor below 40% would generate no specific monetary charge, it would require
the issue to be brought before the NJBPU for review. The annual measurement
period, which begins in March of each year, coincides with that used for the
LEAC.
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 employees
alleging unlawful employment practices. It is not expected that the outcome
of these types of matters would have a material effect on the Company's
financial position or results of operations.
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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 (FERC) and adopted by the NJBPU. Certain reclassifications of
prior years' data have been made to conform with current presentation.
REVENUES
The Company recognizes electric operating revenues for services rendered
(including an estimate of unbilled revenues) to the end of the respective
accounting period.
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 which, on an aggregate composite basis,
resulted in annual rates of 3.62%, 3.59% and 3.51% for the years 1994, 1993
and 1992, 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 pre-tax 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 5.35%, 7.80% and 8.19% for the years 1994, 1993 and 1992,
respectively.
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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 2008. At December 31, 1994, $91 million is included
in Unamortized Property Losses on the balance sheet for the Company's 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 the damaged TMI-
2 facility and the cancelled Forked River project, these 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/(Expense), Net on
the income statement.
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, 1994 amounted to $25 million and is primarily reflected in
Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants
will contribute annually, based on an assessment computed on prior enrichment
purchases, over a 15-year period. The Company made its initial payment to
this fund in 1993, and is recovering the remaining amounts through its fuel
clause. At December 31, 1994, $27 million is recorded on the balance sheet 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, 1994, all of which relates to
spent nuclear fuel from nuclear generation through April 1983, amounted to
$114 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
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Jersey Central Power & Light Company
$28 million at December 31, 1994 in Deferred Debits and Other Assets - Other.
The rates presently charged to customers provide for the collection of these
costs, plus interest, over remaining periods of 12 years.
The Company is collecting one mill per kilowatt-hour from its customers
for spent nuclear fuel disposal costs resulting from nuclear generation
subsequent to April 1983. This amount is remitted quarterly to the DOE.
INCOME TAXES
The GPU System companies file a consolidated federal income tax return.
All participants are jointly and severally liable for the full amount of any
tax, including penalties and interest, which 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 liberalized
depreciation methods, deferred energy costs, decommissioning funds and
discounted Forked River and TMI-2 investments, 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 amounts 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 consolidated 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, 1994, the Company had $110 million of short-term notes
outstanding, of which $33 million was commercial paper and the remainder was
issued under bank lines of credit (credit facilities).
F-95
<PAGE>
Jersey Central Power & Light Company
GPU and the Company and its affiliates have $528 million of credit
facilities, which includes a Revolving Credit Agreement (Credit Agreement)
with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total
borrowings outstanding at any time and subject to various covenants and
acceleration under certain conditions. The Credit Agreement borrowing rates
and facility fee are dependent on the long-term debt ratings of the Company
and its affiliates.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
December 31, 1994 and 1993, are as follows:
(In Millions)
Carrying Fair
Amount Value
December 31, 1994:
Cumulative preferred stock
with mandatory redemption $ 150 $ 140
Long-term debt 1,168 1,051
December 31, 1993:
Cumulative preferred stock
with mandatory redemption $ 150 $ 161
Long-term debt 1,216 1,276
The fair values of the Company's long-term debt and preferred stock with
mandatory redemption 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 and credit qualities.
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.
As of December 31, 1994 and 1993, the balance sheet reflected $132 million and
$122 million, respectively, of income taxes recoverable through future rates,
(related to liberalized depreciation), and a regulatory liability for income
taxes refundable through future rates of $40 million and $43 million,
respectively, (related to unamortized ITC), substantially due to the
recognition of amounts not previously recorded.
F-96
<PAGE>
Jersey Central Power & Light Company
A summary of the components of deferred taxes as of December 31, 1994
and 1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993
Current: Current:
Unbilled revenue $ 10 $ 9
Revenue taxes - 12 Revenue taxes $ 18 $ -
Other - 8 Deferred energy - -
Total $ 10 $ 29 Total $ 18 $ -
Noncurrent: Noncurrent:
Unamortized ITC $ 40 $ 43 Liberalized
Decommissioning 25 19 depreciation:
Contribution in aid previously flowed
of construction 20 17 through $ 86 $ 80
Other 38 32 future revenue
Total $ 123 $111 requirements 46 42
Subtotal 132 122
Liberalized
depreciation 383 364
Forked River 54 30
Other 29 54
Total $ 598 $ 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)
1994 1993 1992
Net income $163 $158 $117
Income tax expense 85 81 52
Book income subject to tax $248 $239 $169
Federal statutory rate 35% 35% 34%
Other (1) (1) (3)
Effective income tax rate 34% 34% 31%
F-97
<PAGE>
Jersey Central Power & Light Company
Federal and state income tax expense is comprised of the following:
(In Millions)
1994 1993 1992
Provisions for taxes currently payable $ 50 $ 42 $ 37
Deferred income taxes:
Liberalized depreciation 13 19 24
Gain/Loss on reacquired debt 6 9 4
New Jersey revenue tax 32 32 3
Deferral of energy costs 9 (8) -
Abandonment loss - Forked River (5) (4) (4)
Nuclear outage maintenance costs 6 - (3)
Accretion income 6 6 6
Unbilled revenues 2 5 (2)
VERP (15) - -
Other (12) (14) (6)
Deferred income taxes, net 42 45 22
Amortization of ITC, net ( 7) ( 6) ( 7)
Income tax expense $ 85 $ 81 $ 52
In 1994, the GPU System and the Internal Revenue Service (IRS) reached
an agreement to settle the claim for 1986 that TMI-2 has been retired for tax
purposes. The Company and its affiliates have received net refunds totaling
$17 million, of which the Company's share is $4 million, which have been
credited to their customers. Also in 1994, the GPU System received net
interest from the IRS totaling $46 million, of which the Company's share is
$11.5 million, (before income taxes), associated with the refund settlement,
which was credited to income. The IRS has completed its examinations of the
GPU System's federal income tax returns through 1989. The years 1990 through
1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses
consisted of the following:
(In Millions)
1994 1993 1992
Maintenance $ 132 $135 $125
Other taxes:
New Jersey unit tax $ 204 $202 $197
Real estate and personal property 7 6 7
Other 20 21 12
Total $ 231 $229 $216
F-98
<PAGE>
Jersey Central Power & Light Company
For the years 1994, 1993 and 1992, the cost to the Company of services
rendered to it by GPUSC amounted to approximately $48 million, $39 million and
$37 million, respectively, of which approximately $37 million, $29 million and
$28 million, respectively, was charged to income. For the years 1994, 1993
and 1992, the cost to the Company of services rendered to it by GPUN amounted
to approximately $268 million, $227 million and $247 million, respectively of
which approximately $205 million, $184 million and $170 million, respectively
was charged to income. For the years 1994, 1993 and 1992, the Company
purchased $22 million, $23 million and $22 million, respectively, in energy
from a cogeneration project in which an affiliate has a 50 percent partnership
interest.
7. EMPLOYEE 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)
1994 1993 1992
Service cost-benefits earned during the period $ 8.8 $ 8.7 $ 8.1
Interest cost on projected benefit obligation 29.0 29.4 27.6
Less: Expected return on plan assets (33.3) (32.1) (29.1)
Amortization (.5) (.4) (.6)
Net periodic pension cost $ 4.0 $ 5.6 $ 6.0
The above 1994 amounts do not include a pre-tax charge to earnings of
$38 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992
were gains of $4.4 million, $48.0 million and $17.5 million, respectively.
The funded status of the plans and related assumptions at December 31,
1994 and 1993 were as follows:
F-99
<PAGE>
Jersey Central Power & Light Company
(In Millions)
1994 1993
Accumulated benefit obligation (ABO):
Vested benefits $ 335.9 $ 310.7
Nonvested benefits 34.3 36.2
Total ABO 370.2 346.9
Effect of future compensation levels 55.9 61.8
Projected benefit obligation (PBO) $ 426.1 $ 408.7
PBO $ (426.1) $ (408.7)
Plan assets at fair value 403.7 425.2
PBO (in excess of) less than plan assets (22.4) 16.5
Less: Unrecognized net loss (gain) 13.3 (10.1)
Unrecognized prior service cost 3.5 4.0
Unrecognized net transition asset (2.5) (4.3)
(Accrued) prepaid pension cost $ (8.1) $ 6.1
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
Annual increase in compensation levels 6.0 5.0
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the PBO
as of December 31, 1994. Also, in 1994, the PBO increased by $25 million as a
result of the VERP. 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 loss (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
and the unrecognized net transition asset arising out of the adoption of
Statement of Financial Accounting Standards No. 87, "Employers' Accounting for
Pensions," are being amortized as a charge or 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 1994, 1993 and 1992 were $2.4
million, $2.4 million and $2.1 million, respectively.
F-100
<PAGE>
Jersey Central Power & Light Company
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, the annual premium costs associated with providing these benefits
totaled approximately $4.5 million.
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 1994 and 1993 follows:
(In Millions)
1994 1993
Service cost-benefits attributed to service
during the period $ 3.3 $ 3.4
Interest cost on the accumulated postretirement
benefit obligation 9.4 10.4
Expected return on plan assets (1.7) (.7)
Amortization of transition obligation 5.2 5.7
Other amortization, net .4 -
Net periodic postretirement benefit cost 16.6 18.8
Less, deferred for future recovery (7.8) (9.6)
Postretirement benefit cost, net of deferrals $ 8.8 $ 9.2
The above 1994 amounts do not include a pre-tax charge to earnings of
$9 million relating to the VERP. The amount deferred for future recovery does
not include $6.1 million of allocated postretirement benefit costs from the
Company's affiliates for 1994.
The actual return on the plans' assets for the years 1994 and 1993 was a
gain of $.6 million and $.9 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as
follows:
F-101
<PAGE>
Jersey Central Power & Light Company
(In Millions)
1994 1993
Accumulated Postretirement Benefit Obligation:
Retirees $ 72.0 $ 52.7
Fully eligible active plan participants 24.7 28.8
Other active plan participants 47.1 58.2
Total accumulated postretirement
benefit obligation (APBO) $ 143.8 $ 139.7
APBO $(143.8) $(139.7)
Plan assets at fair value 26.0 10.3
APBO in excess of plan assets (117.8) (129.4)
Less: Unrecognized net loss 7.5 7.5
Unrecognized transition obligation 90.0 108.3
Accrued postretirement benefit liability $ (20.3) $ (13.6)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
The Company intends to continue funding amounts for postretirement
benefits with an independent trustee, as deemed appropriate from time to time.
The plan assets include equities and fixed income securities.
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $10 million decrease in the
APBO as of December 31, 1994. Also, in 1994, the APBO increased by $8 million
as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for
Medicare, then 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 31, 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 as of December 31, 1994 and the
aggregate of the service and interest cost components of net periodic
postretirement health-care cost by approximately $2 million.
In the Company's 1993 base rate proceeding, the NJBPU 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 (EITF) Issue 92-
12, "Accounting for OPEB Costs by Rate-Regulated Enterprises", the Company is
deferring the amounts above that level.
F-102
<PAGE>
Jersey Central Power & Light 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, 1994:
Balance (In Millions)
% Accumulated
Station Ownership Investment Depreciation
Three Mile Island Unit 1 25 $202.4 $ 63.1
Keystone 16.67 84.5 20.8
Yards Creek 50 26.4 6.7
9. LEASES
The Company's capital leases consist primarily of leases for nuclear
fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $99
million and $86 million, respectively (net of amortization of $68 million and
$44 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
presently 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, 1994, 1993 and 1992 these amounts were $28 million, $34 million
and $36 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 38 years, averages
approximately $3 million annually.
F-103<PAGE>
<TABLE>
Jersey Central Power & Light Company
JERSEY CENTRAL POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1994
Allowance for Doubtful
Accounts $1,143 $5,447 $1,972(a) $7,203(b) $1,359
Allowance for Inventory
Obsolescence - - 348(e) - 348
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
<FN>
(a) Recovery of accounts previously written off.
(b) Accounts receivable written off.
(c) Sale of inventory previously written off.
(d) Inventory written off.
(e) Reestablishment of zero value inventory.
</FN>
F-104</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
COMPANY STATISTICS
<CAPTION>
For The Years Ended December 31, 1994 1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Capacity at Company Peak (In MW):
Company owned 1 602 1 602 1 602 1 613 1 613 1 714
Contracted 499 676 609 677 501 315
Total capacity (a) 2 101 2 278 2 211 2 290 2 114 2 029
Hourly Peak Load (In MW):
Summer peak 2 000 1 944 1 845 1 978 1 773 1 763
Winter peak 1 954 1 940 1 834 1 842 1 772 1 852
Reserve at Company peak (%) 5.1 17.2 19.8 15.8 19.2 9.6
Load Factor (%) (b) 66.6 67.2 67.6 63.2 68.3 65.7
Sources of Energy:
Energy sales (In Thousands of MWH):
Net generation 8 035 7 300 8 333 7 738 7 767 8 880
Power purchases and interchange 3 949 5 021 4 652 4 612 4 272 2 809
Total sources of energy 11 984 12 321 12 985 12 350 12 039 11 689
Company use, line loss, etc. (660) (884) (479) (982) (856) (1 043)
Total 11 324 11 437 12 506 11 368 11 183 10 646
Energy mix (%):
Coal 38 35 37 39 41 43
Nuclear 27 24 27 23 22 31
Utility purchases and interchange 19 28 26 28 28 20
Nonutility purchases 14 13 10 9 7 4
Other (gas, hydro and oil) 2 - - 1 2 2
Total 100 100 100 100 100 100
Energy cost (In Mills per KWH):
Coal 15.62 14.85 14.97 18.19 17.25 16.68
Nuclear 6.09 5.45 5.61 6.54 6.52 6.63
Utility purchases and interchange 34.80 32.46 32.89 36.57 33.86 32.24
Nonutility purchases 60.85 58.76 58.21 57.66 55.10 56.32
Other (gas and oil) 56.84 58.46 69.54 53.27 64.15 46.13
Average 22.93 23.29 21.43 24.29 22.36 18.59
Electric Energy Sales (In Thousands of MWH):
Residential 3 921 3 800 3 567 3 542 3 383 3 296
Commercial 2 921 2 794 2 638 2 618 2 506 2 396
Industrial 3 861 3 664 3 589 3 502 3 496 3 588
Other 211 284 329 320 333 338
Sales to customers 10 914 10 542 10 123 9 982 9 718 9 618
Sales to other utilities 410 895 2 383 1 386 1 465 1 028
Total 11 324 11 437 12 506 11 368 11 183 10 646
Operating Revenues (In Millions):
Residential $ 327 $ 322 $ 306 $ 301 $ 271 $ 259
Commercial 215 209 201 197 177 166
Industrial 215 207 213 209 193 190
Other 12 18 22 21 20 20
Revenues from customers 769 756 742 728 661 635
Sales to other utilities 12 27 63 45 44 30
Total electric revenues 781 783 805 773 705 665
Other revenues 20 18 17 15 15 16
Total $ 801 $ 801 $ 822 $ 788 $ 720 $ 681
Price per KWH (In Cents):
Residential 8.39 8.42 8.60 8.45 8.01 7.86
Commercial 7.38 7.46 7.63 7.51 7.07 6.93
Industrial 5.55 5.68 5.95 5.96 5.50 5.31
Total sales to customers 7.07 7.16 7.34 7.27 6.80 6.61
Total sales 6.92 6.83 6.45 6.78 6.30 6.25
Kilowatt-hour Sales per Residential Customer 9 741 9 573 9 139 9 203 8 921 8 863
Customers at Year-End (In Thousands) 458 451 445 437 431 424
<FN>
(a) Summer ratings at December 31, 1994 of owned and contracted capacity
were 1,602 MW and 729 MW, respectively.
(b) The ratio of the average hourly load in kilowatts supplied during the
year to the peak load occurring during the year.
</FN>
F-105
</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
SELECTED FINANCIAL DATA
<CAPTION> (In Thousands)
For The Years Ended December 31, 1994* 1993 1992 1991** 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 801 303 $ 801 487 $ 821 823 $ 788 462 $ 719 387 $ 680 458
Other operation and
maintenance expense 258 656 210 822 208 756 224 315 207 044 207 292
Net income 731 77 875 73 077 62 341 93 191 90 164
Earnings available
for common stock (2 229) 70 915 62 788 52 052 82 902 79 875
Net utility plant
in service 1 437 250 1 361 409 1 290 628 1 226 436 1 152 815 1 063 929
Cash construction
expenditures 159 717 142 380 130 641 121 840 121 673 110 753
Total assets 2 236 279 2 172 543 1 811 689 1 726 388 1 619 920 1 577 606
Long-term debt 529 783 546 319 496 440 386 404 427 468 389 299
Long-term obligations
under capital leases 2 174 3 557 2 643 2 555 2 497 2 472
Preferred securities
of subsidiary 100 000 - - - - -
Return on average
common equity (0.4%) 12.2% 11.8% 9.4% 16.0% 15.5%
<FN>
* Results for 1994 reflect a net decrease in earnings of $79.9 million after
-tax due to a write-off of certain TMI-2 future COSTS ($72.8 million);
charges for costs related to the Voluntary Enhanced Retirement Programs
($20.1 million); and interest income from refunds of previously paid
federal income taxes related to the tax retirement of TMI-2 ($13.0
million).
** Results for 1991 reflect an increase in earnings of $14.9 million after-
tax for an accounting change recognizing unbilled revenues and a
decrease in earnings of $33.5 million after-tax for estimated TMI-2 costs.
</FN>
F-106</TABLE>
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings available for common stock decreased $73.1 million
resulting in a net loss of $2.2 million. The 1994 earnings decrease was
principally attributable to a second quarter write-off of $72.8 million after-
tax from an unfavorable Pennsylvania Commonwealth Court order disallowing the
collection of revenues for certain Three Mile Island Unit 2 (TMI-2) retirement
costs and a $20.1 million after-tax charge to earnings for costs related to
the Voluntary Enhanced Retirement Programs. The effect of these charges was
partially offset by first quarter interest income of $13 million after-tax
from refunds of previously paid federal income taxes related to the tax
retirement of TMI-2.
Also contributing to the 1994 earnings decrease was increased other
operation and maintenance (O&M) expense, which included higher emergency and
winter storm repairs. Earnings were favorably affected by reduced reserve
capacity expense.
In 1993, earnings available for common stock increased $8.1 million to
$70.9 million. The increase in earnings was principally due to higher
kilowatt-hour sales due primarily to the significantly warmer summer
temperatures as compared with the mild weather in 1992. This increase was
partially offset by the write-off of $4.8 million after-tax of costs related
to the cancellation of proposed energy-related agreements, increased interest
charges and an increase in other O&M expense.
The Company's return on average common equity was (.4)% for 1994 as
compared to 12.2% for 1993.
OPERATING REVENUES:
Revenues in 1994 decreased slightly to $801.3 million after decreasing
2.5% to $801.5 million in 1993. The components of these changes are as
follows:
(In Millions)
1994 1993
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ .4 $ 12.4
Rate increases - .5
Energy revenues (2.2) (35.7)
Other revenues 1.6 2.5
Decrease in revenues $ (.2) $(20.3)
F-107
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
Kilowatt-hour revenues
1994
The increase in KWH revenues was due principally to an increase in
nonweather-related customer usage and an increase in the average number of
customers. New customer growth occurred primarily in the residential sector.
The increase was partially offset by lower sales to other utilities.
1993
KWH revenues increased due principally to an increase in weather-
related sales and an increase in the average number of customers, partially
offset by a decrease in nonweather-related customer usage. New customer
growth, which occurred in the commercial and residential sectors, was
partially offset by a slight reduction in the number of industrial customers.
Energy revenues
1994 and 1993
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 decreased in 1994 primarily from lower electric
sales to other utilities offset partially by higher sales to ultimate
customers. The 1993 decrease in energy revenues is due principally to lower
electric sales to other utilities and lower energy cost rates in effect.
Other revenues
1994 and 1993
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.
OPERATING EXPENSES:
Power purchased and interchanged
1994 and 1993
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Company's energy cost rate.
The 1994 decrease was primarily attributable to reductions in reserve capacity
expense and energy purchases from other utilities, offset partially by an
increase in nonutility generation purchases. The reduction in reserve
capacity expense favorably affected earnings since these costs are not
recovered through energy revenues. Power purchased and interchanged increased
in 1993 primarily as a result of increases in nonutility generation purchases.
Other operation and maintenance
1994
The increase in other O&M expense was primarily attributable to a $35.2
million pre-tax charge for costs related to the Voluntary Enhanced Retirement
F-108
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
Programs. Increases were also attributable to higher emergency and winter
storm repairs and the accrual of additional payroll expense under an expanded
employee incentive compensation program designed to tie pay increases more
closely to business results and enhance productivity.
1993
Other O&M expense increased primarily due to emergency and storm-
related activities and increased costs related to fossil plant outages.
Depreciation and amortization
1993
Depreciation and amortization expense decreased in 1993 due to
decreases in the amortization relating to TMI-2, partially offset by additions
to utility plant. Additions to utility plant primarily consist of additions
to existing generating facilities to maintain system reliability and additions
to the transmission and distribution system related to new customer growth.
Taxes, other than income taxes
1994 and 1993
Generally, changes in taxes other than income taxes do not
significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income/(expense), net
1994
The increase in other expense is related principally to the second
quarter write-off of future TMI-2 retirement costs. The effect of this write-
off was partially offset by first quarter interest income resulting from
refunds of previously paid federal income taxes related to the tax retirement
of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993
Pennsylvania Public Utility Commission (PaPUC) order that permitted the
Company to recover estimated TMI-2 retirement costs from customers. As a
result, second quarter charges were taken totaling $127.6 million pre-tax.
These charges were comprised of $117.6 million for retirement costs and $10
million for monitored storage costs.
The tax retirement of TMI-2 resulted in a refund for the tax years
after TMI-2 was retired. The effect on pre-tax earnings was an increase of
$29.8 million in interest income.
1993
The reduction in other income was principally due to the write-off of
$8.1 million pre-tax of costs related to the cancellation of proposed power
supply and transmission facilities agreements between the Company and its
affiliates and Duquesne Light Company.
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INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Interest charges
1994
Other interest expense was higher due primarily to the tax retirement
of TMI-2, which resulted in a $7 million pre-tax increase in interest expense
on additional amounts owed for tax years in which depreciation deductions with
respect to TMI-2 had been taken.
1993
Interest on long-term debt increased 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.
Dividends on preferred securities of subsidiary
1994
The increase is attributable to the payment of dividends on the Monthly
Income Preferred Securities issued by the Company's special-purpose finance
subsidiary, Met-Ed Capital L.P.
PREFERRED STOCK DIVIDENDS:
1994 and 1993
Preferred stock dividends decreased in 1994 and 1993 due to the
redemption of $35 million and $81 million stated value of preferred stock,
respectively.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs were $160 million in 1994, consisting of
cash construction expenditures. During 1994, construction funds were used
primarily to maintain and improve existing generation facilities and the
transmission and distribution system, proceed with various clean air
compliance projects, and build a new generation facility. For 1995,
construction expenditures are estimated to be $115 million, consisting mainly
of $96 million for ongoing system development and $18 million for clean air
requirements. The 1995 estimated reduction is largely due to the completion
in 1994 of a significant portion of clean air compliance requirements and a
new generation facility. Expenditures for maturing debt are expected to be
$41 million for 1995 and $15 million for 1996. In the late 1990s,
construction expenditures are expected to include substantial amounts for
clean air requirements and other Company needs. Management estimates that
approximately one-half of the Company's 1995 capital needs will be satisfied
through internally generated funds.
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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 $125 million of nuclear
fuel costs may be outstanding at any one time for TMI-1. The Company's share
of the nuclear fuel capital leases at December 31, 1994 totaled $33 million.
When consumed, portions of the presently leased material will be replaced by
additional leased material at a rate of approximately $16 million annually.
In the event the needed nuclear fuel cannot be leased, the associated capital
requirements would have to be met by other means.
FINANCING:
In 1994, the Company issued $100 million of Monthly Income Preferred
Securities (carried on the balance sheet as Preferred securities of
subsidiary) through its special-purpose finance subsidiary, and an aggregate
of $50 million principal amount of long-term debt. A portion of these
proceeds was used to refinance long-term debt and redeem more costly preferred
stock amounting to $26 million and $35 million, respectively.
GPU has requested regulatory authorization from the Securities and
Exchange Commission (SEC) to issue up to five million shares of additional
common stock through 1996. The proceeds from the sale of such additional
common stock would be used to increase the Company and its affiliates' common
equity ratios and reduce GPU short-term debt. GPU will monitor the capital
markets as well as its capitalization ratios relative to its targets to
determine whether, and when, to issue such shares.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), which may be issued as secured medium-term notes, and preferred
stock through 1995. Under existing authorization, the Company may issue
senior securities in the amount of $250 million, of which $100 million may
consist of preferred stock. The Company, through its special-purpose finance
subsidiary, has remaining regulatory authority to issue an additional $25
million of Monthly Income Preferred Securities. 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 bond indenture and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Company may issue. As a result of the TMI-2 retirement costs
write-offs, together with certain other costs recognized in the second quarter
of 1994, the Company will be unable to meet the interest and preferred
dividend coverage requirements of its indenture and charter, respectively,
until the third quarter of 1995. Therefore, the Company's ability to issue
senior securities through June 1995 will be limited to the issuance of FMBs on
the basis of $65 million of previously issued and retired bonds. The
Company's ability to issue its remaining authorized Monthly Income Preferred
Securities, which have no such coverage restrictions, is not affected by these
write-offs.
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Metropolitan Edison Company and Subsidiary Companies
The Company's cost of capital and ability to obtain external financing
is affected by its security ratings, which are periodically reviewed by the
three major credit rating agencies. Following a review that was prompted by
the Commonwealth Court's order denying recovery of TMI-2 retirement costs,
Moody's Investors Service (Moody's) and Standard & Poor's Corporation (S&P)
downgraded the Company's security ratings in August 1994 citing, among other
things, the Company's weakened financial flexibility resulting from the second
quarter 1994 write-offs. The Company's FMBs are currently rated at an
equivalent of a BBB+ or higher by the three major credit rating agencies,
while the preferred stock issues and Monthly Income Preferred Securities have
been assigned an equivalent of BBB or higher. In addition, the Company's
commercial paper is rated as having good to very good credit quality.
Although credit quality has been reduced, the Company's credit ratings remain
above investment grade.
In 1994, the S&P rating outlook, which is used to assess the potential
direction of an issuer's long-term debt rating over the intermediate- to
longer-term, was revised to "stable" from "negative" for the Company. The
outlook reflects S&P's judgment that the Company has manageable construction
spending, limited external financing requirements, regionally competitive
rates, and an emphasis on cost cutting to offset base rate relief requirements
during the next few years. Though its outlook was upgraded, S&P believed that
the Company risked some deterioration in its competitive position due to S&P's
judgment that there are substantial purchased power-related rate recovery
needs. S&P also assigned the Company a "low average" business position, a
financial benchmarking standard for rating the debt of electric utilities to
reflect the changing risk profiles resulting primarily from the intensifying
competitive pressures in the industry.
In June 1994, Moody's announced that it developed a new method to
calculate the minimum price an electric utility must charge its customers in
order to recover all of its generation costs. Moody's believes that an
assessment of relative cost position will become increasingly critical to the
credit analysis of electric utilities in a competitive marketplace. Specific
rating actions are not anticipated, however, until the pace and implications
of utility market deregulation are more certain.
Present plans call for the Company to issue long-term debt during the
next three years to finance construction activities, fund the redemption of
maturing senior securities, make contributions to decommissioning trust funds
and, depending on the level of interest rates, refinance outstanding senior
securities.
CAPITALIZATION:
The Company targets capitalization ratios that should warrant sufficient
credit quality ratings to permit capital market access at reasonable costs.
Recent evaluations of the industry by credit rating agencies indicate that the
Company may have to increase its equity ratio to maintain its current
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Metropolitan Edison Company and Subsidiary Companies
credit ratings. GPU's financing plans contemplate security issuances in 1995
to strengthen the equity component of the Company and its affiliates' capital
structures. The Company's targets and actual capitalization ratios are as
follows:
Capitalization
Target Range 1994 1993 1992
Common equity 46-49% 46% 48% 46%
Preferred equity 8-10 10 5 12
Notes payable and
long-term debt 46-41 44 47 42
100% 100% 100% 100%
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated
monopolies. Over the last few years, however, market forces combined with
state and federal actions, have laid the foundation for the continued
development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of
competition in Pennsylvania's electric utility industry and solicited comments
on various issues. The Company and Pennsylvania Electric Company (Penelec)
jointly filed responses in November 1994 suggesting, among other things, that
the PaPUC provide for the equitable recovery of stranded investments, enable
utilities to offer flexible pricing to customers with competitive
alternatives, and address regulatory requirements that impose costs unequally
on Pennsylvania utilities as compared with unregulated or out-of-state
suppliers. At the end of the investigation, which is expected to be concluded
in early 1995, the PaPUC will decide whether to conduct a rulemaking
proceeding.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking regarding the recovery by utilities of
legitimate and verifiable stranded costs. Costs incurred by a utility to
provide integrated electric service to a franchise customer become stranded
when that customer subsequently purchases power from another supplier using
the utility's transmission services. Among other things, the FERC proposed
that utilities be allowed under certain circumstances to recover such stranded
costs associated with existing wholesale customer contracts, but not under new
wholesale contracts unless expressly provided for in the contract. While it
stated a "strong" policy preference that state regulatory agencies address
recovery of stranded retail costs, the FERC also set forth alternative
proposals for how it would address the matter if the states failed to do so.
Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of
Appeals for the District of Columbia, in an unrelated case, questioned the
FERC's authority to permit utilities to recover stranded costs. The Court
remanded the matter to the FERC for it to conduct an evidentiary hearing in
the case to determine whether, among other things, permitting stranded cost
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Metropolitan Edison Company and Subsidiary Companies
recovery was so inherently anticompetitive that it violates antitrust laws.
While largely supported by the electric utility industry, the Proposed
Rulemaking has been strongly opposed by other groups. There can be no
assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing
for electric transmission services. The policy statement contains five
principles that will provide the foundation for the FERC's analyses of all
subsequent transmission rate proposals. Recognizing the evolution of a more
competitive marketplace, the FERC contends that it is critical that
transmission services be priced in a manner that appropriately compensates
transmission owners and creates adequate incentives for efficient system
expansion.
In 1994, the SEC issued for public comment a Concept Release regarding
modernization of the Public Utility Holding Company Act of 1935 (Holding
Company Act). GPU regards the Holding Company Act as a significant impediment
to competition and supports its repeal. In addition, GPU believes that the
Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally
reformed given the burdens being placed on electric utilities by PURPA
mandated uneconomic long-term power purchase agreements with nonutility
generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related
actions as a result of its ongoing strategic planning activities. Responding
to its assessment that competition in the electric utility industry is likely
to accelerate, GPU proceeded to implement two major organizational changes as
well as other programs designed to reduce costs and strengthen GPU's
competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the
non-nuclear generation facilities owned by the Company and its affiliates as
well as undertake responsibility to construct any new non-nuclear generation
facilities which the Company and its affiliates may need in the future. By
forming GPU Generation Corporation (GPUGC), GPU will consolidate and
streamline the management of these generation facilities, and seek to apply
management and operating efficiency techniques similar to those employed in
more competitive industries. This initiative is intended to bring the Company
and its affiliates' generation costs more in line with projected market
prices. GPU Nuclear Corporation is engaging in a search for parallel
opportunities. The Company and its affiliates received regulatory approvals
to enter into an operating agreement with GPUGC from the PaPUC and New Jersey
Board of Public Utilities. SEC authorization is expected to be received in
1995.
The second part of the realignment includes the management combination
of the Company and its affiliate, Penelec. This action is intended to
increase effectiveness and lower costs of Pennsylvania customer operations and
service functions.
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Metropolitan Edison Company and Subsidiary Companies
Other organizational realignments, designed to streamline management and
reduce costs, were also implemented throughout the GPU System in 1994. In
addition, GPU expanded employee participation in its incentive compensation
program to tie pay increases more closely to business results and enhance
productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU
System workforce accepted the Voluntary Enhanced Retirement Programs. Future
payroll and benefits savings, which are estimated to be $75 million annually
(of which the Company's share is $18 million), began in the third quarter and
reflect limiting the replacement of employees up to ten percent of those
retired. Retirement benefits will be substantially paid from pension and
postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the
electric utility industry that calls into question the assumptions regarding
the recovery of certain costs through ratemaking. As the utility industry
continues to experience an increasingly competitive environment, GPU is
attempting to assess the impact that these and other changes will have on the
Company and its affiliates' financial position. For additional information
regarding the other changes that may have an adverse effect on the Company,
see the Competition and the Changing Regulatory Environment section of Note 1
to the Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace,
the cost of near- to intermediate-term regional energy supply from existing
facilities, as evidenced by the results of an all-source competitive supply
solicitation conducted by the Company's New Jersey affiliate in 1994, is less
than the rates in virtually all of the Company's nonutility generation
agreements. In addition, the projected cost of energy from new supply sources
is now lower than was expected in the recent past due to improvements in power
plant technologies and reduced fuel prices.
The long-term nonutility generation agreements included in the Company's
supply plan have been entered into pursuant to the requirements of PURPA and
state regulatory directives. The Company intends to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company is also attempting to renegotiate, and in some cases buy out, existing
high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility
generation costs from customers by the PaPUC, there can be no assurance that
the Company will continue to recover these costs throughout the terms of the
related agreements. The Company currently estimates that in 1998, when
substantially all of these nonutility generation projects are scheduled to be
in-service, above market payments (benchmarked against the expected cost of
electricity produced by a new gas-fired combined cycle facility) will range
from $90 million to $140 million annually.
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Metropolitan Edison Company and Subsidiary Companies
THE SUPPLY PLAN:
Under existing retail regulation, supply planning in the electric
utility industry is directly related to projected growth in the franchise
service territory. At this time, management cannot estimate the timing and
extent to which retail electric competition will affect the Company's supply
plan. As the Company prepares to operate in an increasingly competitive
environment, its supply plan currently focuses on maintaining the existing
customer base by offering competitively priced electricity.
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" market purchases, and
avoidance of long-term firm commitments.
Over the next five years, the Company is projected to experience an
average growth in sales to customers of about 2% annually. These increases
are expected to result from continued economic growth in the service territory
and a slight increase in customers. To meet this growth, assuming the
continuation of existing retail electric regulation, the Company's plan
consists of the continued utilization of existing generation facilities
combined with present commitments for power purchases, and the continued
promotion of economic energy-conservation and load-management programs.
The Company's present strategy includes minimizing the financial
exposure associated with new long-term purchase commitments and the
construction of new facilities by evaluating these options in terms of an
unregulated power market. The Company will take necessary actions to avoid
adding 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.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility
generators and the operation of a new company-owned peaking unit. Additional
capacity needs are principally related to the expiration of existing
commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility
generators under which a total of 239 MW of capacity is currently in service
and about an additional 607 MW are currently scheduled or anticipated to be in
service by 1998.
In October 1994, the Company completed construction on a 134 MW gas-
fired combustion turbine located adjacent to its Portland Generating Station
at a cost of approximately $50 million. After completing operational testing,
the new unit was placed in-service in January 1995 and is expected to produce
power at a lower cost than similar peaking units now in operation.
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Metropolitan Edison Company and Subsidiary Companies
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially
reduce above-market payments for energy supplied by nonutility generators.
The Company will also continue to take legal, regulatory and legislative
initiatives to avoid entering into any new power-supply agreements that are
either not needed or, if needed, are not consistent with competitive market
pricing. The following is a discussion of major nonutility generation
activities involving the Company.
In 1994, a nonutility generator requested that the PaPUC order the
Company to enter into a long-term agreement to buy capacity and energy. The
Company sought to dismiss the request based on a May 1994 PaPUC order, which
granted a Company petition to obtain additional nonutility purchases through
competitive bidding until new PaPUC regulations have been adopted. In
September 1994, the Commonwealth Court granted the PaPUC's application to
revise its May 1994 order for the purpose of reevaluating the nonutility
generator's right to sell power to the Company. The PaPUC subsequently
ordered that hearings be held in this matter.
As part of the effort to reduce above-market payments under nonutility
generation agreements, the Company and its affiliates are seeking to implement
a program under which the natural gas fuel and transportation for the Company
and its affiliates' gas-fired facilities, as well as up to approximately 1,100
MW of nonutility generation capacity, would be pooled and managed by a
nonaffiliated fuel manager. The Company and its affiliates believe the plan
has the potential to provide substantial savings for their customers. The
Company and its affiliates have begun initial discussions with the nonutility
generators who would be eligible to participate. Requirements for approval of
the plan by state and federal regulatory agencies are being reviewed.
Conservation and Load Management
The PaPUC continues to encourage the development of new conservation and
load-management programs. Because the benefits of some of these programs may
not offset program costs, the Company is working to mitigate the impacts these
programs can have on the Company's competitive position in the marketplace.
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of DSM costs and directed utilities to implement DSM programs. The Company
subsequently filed a DSM program that was expected to be approved by the PaPUC
in the first quarter of 1995. However, an industrial intervenor had contested
the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed
the PaPUC order. As a result, the nature and scope of the Company's DSM
program is uncertain at this time.
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Metropolitan Edison Company and Subsidiary Companies
ENVIRONMENTAL ISSUES:
The Clean Air Act Amendments of 1990 (Clean Air Act) require substantial
reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year
2000. The Company's current plan includes installing and operating emission
control equipment at some of its coal-fired facilities as well as switching to
lower sulfur coal at other coal-fired facilities.
To comply with the Clean Air Act, the Company expects to spend up to
$145 million by the year 2000 for air pollution control equipment. During
1994, the first of two scrubbers was installed at the jointly owned Conemaugh
Generating Station. The second scrubber is scheduled to be installed in
November 1995. When operational, these scrubbers are expected to reduce
sulfur dioxide emissions by 95%. The Company's share of the total project
cost is estimated to be $55 million. Through December 31, 1994, the Company
has made capital expenditures of approximately $88 million (including the
first Conemaugh scrubber mentioned above) to comply with the Clean Air Act
requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of
representatives of 12 northeast states (including New Jersey and Pennsylvania)
and the District of Columbia proposed reductions in NOx emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Company expects that the U.S.
Environmental Protection Agency will approve the proposal, and that as a
result, the Company will spend an estimated $10 million, beginning in 1997, to
meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Company is unable to
determine what, if any, additional costs will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the
Company will continue to evaluate the risk of recovering capital investments
compared to increased participation in the emission allowance market and the
use of low-sulfur coal or the early retirement of facilities. These 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 plants are expected to be recoverable through the current
ratemaking process, but management recognizes that recovery is not assured.
For more information, see the Environmental Matters section of Note 1 to
the Consolidated Financial Statements.
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Metropolitan Edison Company and Subsidiary Companies
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately 2,100
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 Consolidated Financial Statements.
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since
the regulatory process results in a time lag during which increased operating
expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry,
the Company does not plan to take any actions that would increase customers'
base rates over the next several years. Therefore, the control of operating
and capital costs will be essential. As competition and deregulation
accelerate, there can be no assurance as to the recovery of increased
operating expense or utility plant investments.
The Company is committed to long-term cost control and continues to seek
and implement measures to reduce or limit the growth of operating expenses and
capital expenditures, including the associated effects of inflation. Though
currently operating in a regulated environment, the Company's focus will be
less reliant on the ratemaking process, and geared toward continued
performance improvement and cost reduction to facilitate the competitive
pricing of its products and services.
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Metropolitan Edison Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1994* 1993 1994** 1993
Operating revenues $213 159 212 399 $196 674 $191 773
Operating income 39 914 38 371 8 808 28 716
Net income 37 802 27 058 (75 109) 17 385
Earnings available
for common stock 36 894 24 486 (76 017) 14 813
In Thousands
Third Quarter Fourth Quarter
1994 1993 1994 1993***
Operating revenues $204 903 $202 482 $186 567 $194 833
Operating income 32 258 36 166 30 516 24 681
Net income 20 453 24 696 17 585 8 736
Earnings available
for common stock 19 545 23 788 17 349 7 828
* Results for the first quarter 1994 reflect an increase in earnings of
$13.0 million after-tax for interest income from refunds of previously
paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of
$92.9 million after-tax due to a write-off of certain TMI-2 future costs
($72.8 million); and charges for costs related to the Voluntary Enhanced
Retirement Programs ($20.1 million).
*** Results for the fourth quarter of 1993 reflect a decrease in earnings of
$5.1 million after-tax for the write-off of the Duquesne transactions.
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Metropolitan Edison Company and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Metropolitan Edison Company
Reading, Pennsylvania
We have audited the consolidated financial statements and financial
statement schedule of Metropolitan Edison Company and Subsidiary Companies as
listed in the index on page F-1 of this Form 10-K. These financial statements
and financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule 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 consolidated financial position of
Metropolitan Edison Company and Subsidiary Companies as of December 31, 1994
and 1993, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
As more fully discussed in Note 1 to the consolidated financial
statements, the Company and its affiliates are unable to determine the
ultimate consequences of certain contingencies which have resulted from the
accident at Unit 2 of the Three Mile Island Nuclear Generating Station
("TMI-2"). The matters which remain uncertain are (a) the extent to which the
retirement costs of TMI-2 could exceed amounts currently recognized for
ratemaking purposes or otherwise accrued, and (b) 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 consolidated 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.
COOPERS & LYBRAND L.L.P.
New York, New York
February 1, 1995
F-121
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<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Revenues $801 303 $801 487 $821 823
Operating Expenses:
Fuel 94 260 82 037 92 851
Power purchased and interchanged:
Affiliates 17 834 15 298 10 915
Others 162 693 187 723 171 893
Deferral of energy costs, net (15 518) (12 179) 35 987
Other operation and maintenance 258 656 210 822 208 756
Depreciation and amortization 86 063 86 490 88 472
Taxes, other than income taxes 51 817 53 834 51 623
Total operating expenses 655 805 624 025 660 497
Operating Income Before Income Taxes 145 498 177 462 161 326
Income taxes 34 002 49 528 47 994
Operating Income 111 496 127 934 113 332
Other Income and Deductions:
Allowance for other funds used during
construction 1 978 1 491 1 591
Other income/(expense), net (98 953) (5 581) 3 229
Income taxes 42 748 2 480 (1 421)
Total other income and deductions (54 227) (1 610) 3 399
Income Before Interest Charges and
Dividends on Preferred Securities 57 269 126 324 116 731
Interest Charges and Dividends on Preferred Securities:
Interest on long-term debt 43 270 42 887 38 882
Other interest 11 937 6 990 6 039
Allowance for borrowed funds used during
construction (1 869) (1 428) (1 267)
Dividends on preferred securities of subsidiary 3 200 - -
Total interest charges and dividends
on preferred securities 56 538 48 449 43 654
Net Income 731 77 875 73 077
Preferred stock dividends 2 960 6 960 10 289
Earnings Available for Common Stock $ (2 229) $ 70 915 $ 62 788
The accompanying notes are an integral part of the consolidated financial statements.
F-122</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $2 137 996 $2 004 639
Less, accumulated depreciation 700 746 643 230
Net utility plant in service 1 437 250 1 361 409
Construction work in progress 105 035 83 783
Other, net 37 275 52 136
Net utility plant 1 579 560 1 497 328
Other Property and Investments:
Nuclear decommissioning trusts 65 100 55 242
Other, net 9 567 9 067
Total other property and investments 74 667 64 309
Current Assets:
Cash and temporary cash investments 9 246 938
Special deposits 1 896 1 433
Accounts receivable:
Customers, net 53 421 54 866
Other 16 736 18 825
Unbilled revenues 25 112 27 075
Materials and supplies, at average cost or less:
Construction and maintenance 39 365 37 953
Fuel 16 843 19 200
Deferred income taxes 4 720 12 241
Prepayments 7 522 2 613
Total current assets 174 861 175 144
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 5 534 128 750
Deferred income taxes 149 892 69 504
Income taxes recoverable through future rates 201 679 199 055
Other 50 086 38 453
Total deferred debits and other assets 407 191 435 762
Total Assets $2 236 279 $2 172 543
The accompanying notes are an integral part of the consolidated financial statements.
F-123
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<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 66 273 $ 66 273
Capital surplus 341 616 345 200
Retained earnings 190 742 229 677
Total common stockholder's equity 598 631 641 150
Cumulative preferred stock 23 598 58 659
Preferred securities of subsidiary 100 000 -
Long-term debt 529 783 546 319
Total capitalization 1 252 012 1 246 128
Current Liabilities:
Debt due within one year 40 517 16
Notes payable - 81 600
Obligations under capital leases 33 810 44 155
Accounts payable:
Affiliates 14 571 10 359
Other 96 061 71 338
Taxes accrued 40 435 6 709
Deferred energy credits 1 950 14 201
Interest accrued 19 006 22 830
Other 21 636 21 573
Total current liabilities 267 986 272 781
Deferred Credits and Other Liabilities:
Deferred income taxes 371 841 355 873
Unamortized investment tax credits 35 470 38 431
Three Mile Island Unit 2 future costs 170 593 159 933
Nuclear fuel disposal fee 25 836 24 801
Other 112 541 74 596
Total deferred credits and other liabilities 716 281 653 634
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 236 279 $2 172 543
The accompanying notes are an integral part of the consolidated financial statements.
F-124
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<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C>
Balance at beginning of year $229 677 $182 569 $164 781
Add - Net income 731 77 875 73 077
Total 230 408 260 444 237 858
Deduct - Cash dividends on capital stock:
Cumulative preferred stock
(at the annual rates
indicated below):
3.90% Series ($3.90 a share) 459 459 459
4.35% Series ($4.35 a share) 145 145 145
3.85% Series ($3.85 a share) 112 112 112
3.80% Series ($3.80 a share) 69 69 69
4.45% Series ($4.45 a share) 159 159 159
8.12% Series ($8.12 a share) - 649 1 299
7.68% Series G ($7.68 a share) 2 016 2 688 2 688
8.32% Series H ($8.32 a share) - 1 040 2 080
8.12% Series I ($8.12 a share) - 1 015 2 030
8.32% Series J ($8.32 a share) - 624 1 248
Common stock (not declared on a
per share basis) 35 000 20 000 45 000
Total 37 960 26 960 55 289
Other adjustments, net 1 706 3 807 -
Total 39 666 30 767 55 289
Balance at end of year $190 742 $229 677 $182 569
The accompanying notes are an integral part of the consolidated financial statements.
F-125</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED STATEMENT OF CAPITAL STOCK AND PREFERRED SECURITIES
<CAPTION>
December 31, 1994 (In Thousands)
<S> <C>
Cumulative preferred stock, no par value, 10,000,000 shares authorized, 233,912 shares
issued and outstanding (without mandatory redemption) (a):
3.90% Series, 117,729 shares outstanding, callable at $105.625 a share $ 11 773
4.35% Series, 33,249 shares outstanding, callable at $104.25 a share 3 325
3.85% Series, 29,175 shares outstanding, callable at $104.00 a share 2 917
3.80% Series, 18,122 shares outstanding, callable at $104.70 a share 1 812
4.45% Series, 35,637 shares outstanding, callable at $104.25 a share 3 564
Subtotal 23 391
Premium on cumulative preferred stock 207
Total preferred stock $ 23 598
Common stock, no par value, 900,000 shares authorized, 859,500 shares
issued and outstanding $ 66 273
Cumulative Monthly Income Preferred Securities, 9.00% Series A, without
par value, 5,000,000 securities authorized, 4,000,000 securities
issued and outstanding (b) (c): $100 000
<FN>
(a) If dividends upon any shares of preferred stock are in arrears in an amount equal to the
annual dividend, 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. During 1994, the Company redeemed its 7.68% Series G (aggregate stated
value $35 million) cumulative preferred stock. The Company's total cost of redemption
was $36 million, which resulted in a $1.2 million charge to retained earnings. During
1993, the Company redeemed all of its outstanding 8.12% Series, 8.32% Series H, 8.12%
Series I and 8.32% Series J of cumulative preferred stock (aggregate stated value of
$81 million) at a total cost of $85.3 million. This resulted in a net charge of
$3.8 million to retained earnings. No other shares of capital stock have been sold or
redeemed during the three years ended December 31, 1994. Stated value of the Company's
cumulative preferred stock is $100 per share.
(b) In 1994 Met-Ed Capital L.P., a special purpose finance subsidiary of the Company, issued
$100 million of Monthly Income Preferred Securities. The proceeds from the issuance of
the Monthly Income Preferred Securities were then loaned to the Company which in turn
issued deferrable interest subordinated debentures to its special purpose finance
subsidiary. The Company is taking a tax deduction for the interest paid on the
subordinated debentures while gaining some preferred equity recognition from the credit
rating agencies for the Monthly Income Preferred Securities.
(c) The issued and outstanding Monthly Income Preferred Securities of Med-Ed Capital L.P.
mature in 2043 and are redeemable after August 23, 1999, or if the Company loses its tax
deduction for interest paid on its subordinated debentures, at 100% of the principal
amount. Interest on the Monthly Income Preferred Securities is paid monthly but can be
deferred for a period of up to 60 months. However, the Company may not pay dividends on
any shares of its preferred or common stock until deferred interest on its subordinated
debentures is paid in full.
The accompanying notes are an integral part of the consolidated financial statements.
</FN>
F-126</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Activities:
Income before preferred stock dividends $ 731 $ 77 875 $ 73 077
Adjustments to reconcile income to cash provided:
Depreciation and amortization 80 501 77 372 80 357
Amortization of property under capital leases 14 795 13 903 16 051
Three Mile Island Unit 2 costs 127 640 - -
Voluntary enhanced retirement program 35 246 - -
Nuclear outage maintenance costs, net 5 895 (4 394) 5 060
Deferred income taxes and investment
tax credits, net (53 993) 12 371 (16 376)
Deferred energy costs, net (15 518) (12 179) 35 987
Accretion income (1 114) (1 486) (3 500)
Allowance for other funds used during construction (1 978) (1 491) (1 591)
Changes in working capital:
Receivables 5 498 (3 537) 5 581
Materials and supplies 944 (3 604) (942)
Special deposits and prepayments (4 593) 602 2 220
Payables and accrued liabilities 28 364 (5 989) (17 232)
Other, net 7 753 (9 114) (1 300)
Net cash provided by operating activities 230 171 140 329 177 392
Investing Activities:
Cash construction expenditures (159 717) (142 380) (130 641)
Contributions to decommissioning trusts (10 633) (46 239) (2 567)
Other, net 79 8 183 -
Net cash used for investing activities (170 271) (180 436) (133 208)
Financing Activities:
Issuance of long-term debt 49 687 268 170 109 270
(Decrease) increase in notes payable, net (81 600) 69 800 (56 569)
Retirement of long-term debt (26 016) (221 015) (25 414)
Redemption of preferred stock (36 595) (85 346) -
Capital lease principal payments (15 168) (12 524) (16 574)
Issuance of preferred securities of subsidiary 96 732 - -
Contributions from parent corporation - 50 000 -
Dividends paid on common stock (35 000) (20 000) (45 000)
Dividends paid on preferred stock (3 632) (8 624) (10 289)
Net cash (required) provided by financing
activities (51 592) 40 461 (44 576)
Net increase (decrease) in cash and temporary cash
investments from above activities 8 308 354 (392)
Cash and temporary cash investments, beginning of year 938 584 976
Cash and temporary cash investments, end of year $ 9 246 $ 938 $ 584
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 77 636 $ 41 372 $ 43 267
Income taxes paid $ 15 179 $ 55 539 $ 63 966
New capital lease obligations incurred $ 3 126 $ 24 780 $ 3 998
The accompanying notes are an integral part of the consolidated financial statements.
F-127</TABLE>
<PAGE>
<TABLE>
Metropolitan Edison Company and Subsidiary Companies
CONSOLIDATED STATEMENT OF LONG-TERM DEBT
<CAPTION>
December 31, 1994 (In Thousands)
First mortgage bonds - Series as noted (a)(b):
<S> <C> <C> <C> <C>
4 5/8% due 1995 $12 000 9 1/10% due 2003 $ 30 000
10 1/2% due 1995 28 500 6.34% due 2004 40 000
5 3/4% due 1996 15 000 7.35% due 2005 20 000
7.47% due 1997 20 000 6.36% due 2006 17 000
9 1/5% due 1997 20 000 6.40% due 2006 33 000
7.05% due 1999 30 000 6% due 2008 8 700
6.2% due 2000 30 000 8.6% due 2022 30 000
9.48% due 2000 20 000 8.8% due 2022 30 000
6.6% due 2003 20 000 6.97% due 2023 30 000
7.22% due 2003 40 000 7.65% due 2023 30 000
8.15% due 2023 60 000
Subtotal $564 200
Amount due within one year (40 500) $523 700
Other long-term debt (net of $17 thousand due within one Year) 6 134
Unamortized net discount on long-term debt (51)
Total long-term debt $529 783
<FN>
(a) Substantially all of the properties of the Company are subject to the lien of the
mortgage.
(b) For the years 1995, 1996, 1997, 1998 and 1999, the Company has long-term debt
maturities of $40.5 million, $15.0 million, $40.0 million, $0 million and
$30.0 million, respectively.
The accompanying notes are an integral part of the consolidated financial statements.
</FN>
F-128
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<PAGE>
Metropolitan Edison Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Metropolitan Edison Company (the Company), a Pennsylvania corporation,
incorporated in 1922, 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 owns all of the common stock of York
Haven Power Company, the owner of a small hydroelectric generating station and
Met-Ed Preferred Capital, Inc., which is the general partner of Met-Ed Capital
L.P., a special purpose finance subsidiary. The Company's business is the
generation, transmission, distribution and sale of electricity. The Company
is affiliated with Jersey Central Power & Light Company (JCP&L) and
Pennsylvania Electric Company (Penelec). The Company, JCP&L 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 Energy Initiatives, Inc. (EI), and EI
Power, Inc., which develop, own and operate nonutility generating facilities.
All of the Company's affiliates are wholly owned subsidiaries of GPU. The
Company and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. are referred to
as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in two major nuclear projects -- Three
Mile Island Unit 1 (TMI-1) which is an operational generating facility, and
Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident.
TMI-1 and TMI-2 are jointly owned by the Company, JCP&L and Penelec in the
percentages of 50%, 25% and 25%, respectively. At December 31, the Company's
net investment in TMI-1 and TMI-2, including nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2
1994 $311 $ 6
1993 $332 $11
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, 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 its nuclear
plants because of the prevailing design criteria 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 the
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 each plant's
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Metropolitan Edison Company and Subsidiary Companies
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
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 accident cleanup program was completed in 1990. After receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100
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 and the suppliers of equipment and services to TMI-
2, and are pending in the United States District Court for the Middle District
of Pennsylvania. Some of the claims also seek recovery on the basis of
alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are
not covered by insurance and are not subject to the liability limitations of
the federal Price-Anderson Act ($560 million at the time of the accident),
punitive damage awards could have a material adverse effect on the financial
position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for premium charges deferred in whole or
in major part under such plan, and (c) an indemnity agreement with the NRC,
bringing their total primary and secondary insurance financial protection and
indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers under a reservation of rights with respect to any award of
punitive damages. However, in March 1994, the defendants in the TMI-2
litigation and the insurers agreed that the insurers would withdraw their
reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is likely to begin in 1996. 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
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Metropolitan Edison Company and Subsidiary Companies
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. In July 1994, the Court
granted defendants' motion for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals.
In an Order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
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 TMI-1 by 2014, the end of the plant's license term. 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 1994 dollars) for TMI-1 is $157 million,
of which the Company's share is $79 million. Based on NRC studies, a
comparable funding target for TMI-2 has been developed which takes the
accident into account (see TMI-2 Future Costs). The NRC continues to study
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 considered 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.
F-131
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
In 1988, a consultant to GPUN performed a site-specific study of TMI-1
that considered various decommissioning plans and estimated the cost of
decommissioning the radiological portions of TMI-1 to range from approximately
$225 million to $309 million, of which the Company's share would range from
$113 million to $155 million (adjusted to 1994 dollars). In addition, the
study estimated the cost of removal of nonradiological structures and
materials for TMI-1 at $74 million, of which the Company's share is $37
million (adjusted to 1994 dollars).
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 and its affiliates charge to expense and
contribute to external trusts amounts collected from customers for nuclear
plant decommissioning and nonradiological costs. In addition, the Company has
contributed amounts written off for TMI-2 nuclear plant decommissioning in
1991 to TMI-2's external trust and will await resolution of the case pending
before the Pennsylvania Supreme Court before making any further contributions
for amounts written off by the Company in 1994. Amounts deposited in external
trusts, including the interest earned on these funds, are classified as
Nuclear Decommissioning Trusts on the balance sheet.
TMI-1:
In 1993, the Pennsylvania Public Utility Commission (PaPUC) granted the
Company revenues for decommissioning costs of TMI-1 based on its share of the
NRC funding target and nonradiological cost of removal as estimated in the
site-specific study. Collections from customers for retirement expenditures
are deposited in external trusts. Provision for the future expenditures of
these funds has been made in accumulated depreciation, amounting to
$21 million at December 31, 1994. TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 retirement costs, in excess of those
currently recognized for ratemaking purposes, should be recoverable through
the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target in
1994 dollars. The Company and its affiliates record escalations, when
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Metropolitan Edison Company and Subsidiary Companies
applicable, in the liability based upon changes in the NRC funding target.
The Company and its affiliates have also recorded a liability for incremental
costs specifically attributable to monitored storage. In addition, the Company
and its affiliates have recorded a liability for nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $2
million, of which the Company's share is $1 million, as of December 31, 1994.
Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and
1993 for the Company are as follows:
(Millions) (Millions)
1994 1993
Radiological Decommissioning $125 $115
Nonradiological Cost of Removal 36 35
Incremental Monitored Storage 9 10
Total $170 $160
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At December 31, 1994, $43 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet.
In 1993, a PaPUC rate order for the Company allowed for the future
recovery of certain TMI-2 retirement costs. The Pennsylvania Office of
Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's
1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order.
In December 1994, the Pennsylvania Supreme Court granted the Company's request
to review that decision. As a consequence of the Commonwealth Court decision,
the Company recorded pre-tax charges totaling $127.6 million during 1994.
These charges appear in the Other Income and Deductions section of the Income
Statement and are composed of $82.6 million for radiological decommissioning
costs, $35 million for the nonradiological cost of removal and $10 million for
incremental monitored storage costs. The Company will await resolution of the
case pending before the Pennsylvania Supreme Court before making any
nonrecoverable funding contributions to external trusts for its share of these
costs. The Company will be similarly required to charge to expense its share
of future increases in the estimate of the costs of retiring TMI-2. Future
earnings on trust fund deposits for the Company will be recorded as income.
Prior to the Commonwealth Court's decision, the Company expensed and
contributed $40 million to external trusts relating to its nonrecoverable
share of the accident-related portion of the decommissioning liability.
As a result of TMI-2's entering long-term monitored storage in late
1993, the Company and its affiliates are incurring incremental annual storage
costs of approximately $1 million, of which the Company's share is $.50
million. The Company and its affiliates estimate that the remaining annual
storage costs will total $19 million, of which the Company's share is $9
million, through 2014, the expected retirement date of TMI-1.
F-133
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
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 totals $2.7 billion. In
accordance with NRC regulations, these insurance policies generally require
that proceeds first be used for stabilization of 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 that station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial 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 two operating reactors (TMI-2 is excluded under
an exemption received from the NRC in 1994), subject to an annual maximum
payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at its
nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the
outage and continues for three years beginning at $2.6 million per week for
the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and
facilities, the GPU System is subject to retrospective premium assessments of
up to $69 million, of which the Company's share is $19 million, in any one
year, in addition to those payable (up to $20 million, of which the Company's
share is $5 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
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
F-134
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Metropolitan Edison Company and Subsidiary Companies
toward a combination of competition and a modified regulatory environment. In
accordance with Statement of Financial Accounting Standards No. 71 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation," 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.
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 any
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 currently.
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 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 at the contract
price all of the power produced up to the contract limits. As of December 31,
1994, facilities covered by these agreements having 239 MW of capacity were in
service and 28 MW were scheduled to commence operation in 1995. Payments made
pursuant to these agreements were $101 million, $95 million and $78 million
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Metropolitan Edison Company and Subsidiary Companies
for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998,
and 1999, payments pursuant to these agreements are estimated to aggregate
$114 million, $170 million, $280 million, $415 million and $418 million,
respectively. These agreements, together with those for facilities which are
not yet in operation, provide for the purchase of approximately 846 MW of
capacity and energy by the Company by the mid-to-late 1990s, at varying
prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the GPU System's energy supply needs which has
caused the Company and its affiliates to change their supply strategy to now
seek shorter-term agreements offering more flexibility (see Management's
Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current
availability of excess capacity in the market place, the cost of near- to
intermediate-term (i.e., one to eight years) energy supply from existing
generation facilities is currently competitively priced. The projected cost
of energy from new generation supply sources has also decreased due to
improvements in power plant technologies and reduced forecasted fuel prices.
As a result of these developments, the rates under virtually all of the
Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources. These agreements have been entered into pursuant to the requirements
of the federal Public Utility Regulatory Policies Act and state regulatory
directives. The Company and its affiliates have initiated lawful actions
which are intended to substantially reduce these above market payments. In
addition, the Company and its affiliates intend to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company and its affiliates are also attempting to renegotiate, and in some
cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the PaPUC and the New
Jersey Board of Public Utilities (NJBPU), there can be no assurance that the
Company and its affiliates will continue to be able to recover these costs
throughout the term of the related agreements. The GPU System currently
estimates that in 1998, when substantially all of the these nonutility
generation projects are scheduled to be in service, above market payments
(benchmarked against the expected cost of electricity produced by a new gas-
fired combined cycle facility) will range from $300 million to $450 million
annually, of which the Company's share will range from $90 million to $140
million annually. Moreover, efforts to lower these costs have led to disputes
before both the PaPUC and the NJPBU, as well as to litigation, and may result
in claims against the Company and its affiliates for substantial damages.
There can be no assurance as to the outcome of these matters.
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Metropolitan Edison Company and Subsidiary Companies
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, decommission or clean up waste disposal and other sites currently
or formerly used by it, including formerly owned manufactured gas plants and
mine refuse piles and generating facilities, 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.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of
1990, the Company expects to spend up to $145 million for air pollution
control equipment by the year 2000. In developing its least-cost plan to
comply with the Clean Air Act, the Company will continue to evaluate major
capital investments compared to participation in the emission allowance market
and the use of low-sulfur fuel or retirement of facilities. In September
1994, the Ozone Transport Commission (OTC), consisting of representatives of
12 northeast states (including New Jersey and Pennsylvania) and the District
of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Company expects that the U.S.
Environmental Protection Agency (EPA) will approve the proposal, and that as a
result, the Company will spend an estimated $10 million, beginning in 1997, to
meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Company and its affiliates
are unable to determine what, if any, additional costs will be incurred.
The Company has been notified by the EPA and state environmental
authorities 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 5 hazardous and/or toxic waste sites. In
addition, the Company has been requested to voluntarily participate in the
remediation or 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 Company has also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
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.
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Metropolitan Edison Company and Subsidiary Companies
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.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement
Programs (VERP) to certain employees. The enhanced retirement programs were
part of a corporate realignment undertaken in 1994. Approximately 82% of
eligible GPU System employees accepted the retirement programs, resulting in a
pre-tax charge to earnings of $127 million, of which the Company's share is
$35 million. These charges are included as Other Operation and Maintenance on
the income statement.
The Company's construction programs, for which substantial commitments
have been incurred and which extend over several years, contemplate
expenditures of $115 million during 1995. As a consequence of reliability,
licensing, environmental and other requirements, 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 such costs through the
ratemaking process, but recognizes that recovery is not assured.
The Company has entered into long-term contracts with nonaffiliated
mining companies for the purchase of coal for certain generating stations in
which it has ownership interests. The contracts, which expire between 1995
and the end of the expected service lives of the generating stations, require
the purchase of either fixed or minimum amounts of the stations' coal
requirements. The price of the coal under the contracts is based on
adjustments of indexed cost components. The Company's share of the cost of
coal purchased under these agreements is expected to aggregate $27 million for
1995.
At the request of the PaPUC, the Company, as well as the other
Pennsylvania utilities, has supplied the PaPUC with proposals for the
establishment of a nuclear performance standard. The Company expects the
PaPUC to adopt a generic nuclear performance standard as a part of its energy
cost rate (ECR) clause in 1995.
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 employees
alleging unlawful employment practices. It is not expected that the outcome
of these types of matters would have a material effect on the Company's
financial position or results of operations.
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Metropolitan Edison Company and Subsidiary Companies
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. Certain reclassifications of prior
years' data have been made to conform with current presentation. The
Company's accounting records are maintained in accordance with the Uniform
System of Accounts prescribed by the Federal Energy Regulatory Commission
(FERC) and adopted by the PaPUC.
REVENUES
The Company recognizes electric operating revenues for services rendered
(including an estimate of unbilled revenues) to the end of the respective
accounting period.
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 which, on an aggregate composite basis,
resulted in annual rates of 3.04%, 2.91% and 2.80% for the years 1994, 1993
and 1992, 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 pre-tax 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
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Metropolitan Edison Company and Subsidiary Companies
recognized in rates. On an aggregate composite basis, the annual rates
utilized were 7.31%, 7.48% and 8.58% for the years 1994, 1993 and 1992,
respectively.
AMORTIZATION POLICIES
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, 1994 amounted to $10 million and is primarily reflected in
Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants
will contribute annually, based on an assessment computed on prior enrichment
purchases, over a 15-year period. The Company made its initial payment to
this fund in 1993, and is recovering the remaining amounts through its fuel
clause. At December 31, 1994, $13 million is recorded on the balance sheet 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 TMI-1 in accordance with the Nuclear Waste Policy Act of 1982.
The Company entered into a contract in 1983 with the DOE for the disposal of
spent nuclear fuel. The total liability under this contract, including
interest, at December 31, 1994, all of which relates to spent nuclear fuel
from nuclear generation through April 1983, amounted to $26 million, and is
reflected in Deferred Credits and Other Liabilities - Other. The rates
presently charged to customers provide for the collection of these costs, plus
interest, over a remaining period of 13 years.
The Company is collecting one mill per kilowatt-hour from its customers
for spent nuclear fuel disposal costs resulting from nuclear generation
subsequent to April 1983. This amount is remitted quarterly to the DOE.
INCOME TAXES
The GPU System companies file a consolidated federal income tax return.
All participants are jointly and severally liable for the full amount of any
tax, including penalties and interest, which 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
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Metropolitan Edison Company and Subsidiary Companies
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 liberalized
depreciation methods, deferred energy costs and decommissioning funds, 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 amounts 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 consolidated 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, 1994, the Company had no outstanding issues under bank
lines of credit (credit facilities).
GPU and the Company and its affiliates have $528 million of credit
facilities, which includes a Revolving Credit Agreement (Credit Agreement)
with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total
borrowings outstanding at any time and subject to various covenants and
acceleration under certain conditions. The Credit Agreement borrowing rates
and facility fee are dependent on the long-term debt ratings of the Company
and its affiliates.
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Metropolitan Edison Company and Subsidiary Companies
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
December 31, 1994 and 1993, are as follows:
(In Millions)
Carrying Fair
Amount Value
December 31, 1994:
Preferred securities
of subsidiary $ 100 $ 98
Long-term debt 530 485
December 31, 1993:
Long-term debt $ 546 $ 585
The fair values of the Company's long-term debt and preferred securities
of subsidiary 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 and credit qualities.
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 $2 million and an increase in the
deferred tax liabilities of $12 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.
As of December 31, 1994 and 1993, the balance sheet reflected $202 million and
$199 million, respectively, of income taxes recoverable through future rates,
(related to liberalized depreciation), and a regulatory liability for income
taxes refundable through future rates of $30 million and $29 million,
respectively, (related to unamortized ITC), substantially due to the
recognition of amounts not previously recorded.
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Metropolitan Edison Company and Subsidiary Companies
A summary of the components of deferred taxes as of December 31, 1994
and 1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993
Noncurrent:
Current: Liberalized
Unbilled revenue $ 3 $ 4 depreciation:
Deferred energy - 6 previously flowed
Other 2 2 through $ 116 $ 114
Total $ 5 $ 12 future revenue
Noncurrent: requirements 86 85
Unamortized ITC $ 30 $ 29
Decommissioning 71 19 Subtotal 202 199
Contribution in aid Liberalized
of construction 2 2 depreciation 163 154
Other 47 19 Other 7 3
Total $150 $ 69 Total $ 372 $ 356
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)
1994 1993 1992
Net income $ 1 $ 78 $ 73
Income tax expense (9) 47 49
Book income subject to tax $ (8) $125 $122
Federal statutory rate 35% 35% 34%
State tax, net of federal benefit 32 6 7
Amortization of ITC 22 (2) (2)
Other 20 (1) 1
Effective income tax rate 109% 38% 40%
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Metropolitan Edison Company and Subsidiary Companies
Federal and state income tax expense is comprised of the following:
(In Millions)
1994 1993 1992
Provisions for taxes currently payable $ 45 $ 35 $ 65
Deferred income taxes:
Liberalized depreciation 6 8 3
Deferral of energy costs 6 4 (15)
Accretion income - - 2
Decommissioning (52) - -
VERP (15) - -
Unbilled revenue 2 - 1
Other 2 3 (4)
Deferred income taxes, net (51) 15 (13)
Amortization of ITC, net (3) (3) (3)
Income tax expense $ (9) $ 47 $ 49
In 1994, the GPU System and the Internal Revenue Service (IRS) reached
an agreement to settle the claim for 1986 that TMI-2 has been retired for tax
purposes. The Company and its affiliates have received net refunds totaling
$17 million, of which the Company's share is $9 million, which have been
credited to their customers. Also in 1994, the GPU System received net
interest from the IRS totaling $46 million, of which the Company's share is
$23 million, (before income taxes), associated with the refund settlement,
which was credited to income. The IRS has completed its examinations of the
GPU System's federal income tax returns through 1989. The years 1990 through
1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses
consisted of the following: (In Millions)
1994 1993 1992
Maintenance $ 59 $ 59 $ 56
Other taxes:
Pennsylvania state gross receipts $ 32 $ 32 $ 32
Real estate and personal property 6 7 7
Capital stock 7 8 8
Other 7 6 4
Total $ 52 $ 53 $ 51
For the years 1994, 1993 and 1992, the cost to the Company of services
rendered to it by GPUSC amounted to approximately $27 million, $23 million and
$23 million, respectively, of which approximately $22 million, $19 million and
$18 million, respectively, were charged to income. For the years 1994, 1993,
and 1992, the cost to the company of services rendered to it by GPUN amounted
to approximately $77 million, $88 million and $75 million, respectively, of
which approximately $65 million, $74 million and $61 million, respectively,
were charged to income.
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Metropolitan Edison Company and Subsidiary Companies
7. EMPLOYEE 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)
1994 1993 1992
Service cost-benefits earned during the period $ 4.7 $ 4.9 $ 4.4
Interest cost on projected benefit obligation 17.7 18.8 18.5
Less: Expected return on plan assets (19.1) (19.3) (18.3)
Amortization (0.3) (0.3) (0.3)
Net periodic pension cost $ 3.0 $ 4.1 $ 4.3
The above 1994 amounts do not include a pre-tax charge to earnings of
$26 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992
were gains of $2.5 million, $29.2 million and $10.7 million, respectively.
The funded status of the plans and related assumptions at December 31,
1994 and 1993 were as follows:
(In Millions)
1994 1993
Accumulated benefit obligation (ABO):
Vested benefits $ 212.4 $ 201.1
Nonvested benefits 19.7 21.6
Total ABO 232.1 222.7
Effect of future compensation levels 30.9 36.6
Projected benefit obligation (PBO) $ 263.0 $ 259.3
PBO $ (263.0) $ (259.3)
Plan assets at fair value 234.6 255.4
PBO in excess of plan assets (28.4) (3.9)
Less: Unrecognized net loss 15.9 6.6
Unrecognized prior service cost 2.3 (1.1)
Unrecognized net transition asset (1.4) (1.8)
Accrued pension liability $ (11.6) $ (0.2)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
Annual increase in compensation levels 6.0 5.0
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Metropolitan Edison Company and Subsidiary Companies
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $9 million decrease in the PBO
as of December 31, 1994. Also, in 1994, the PBO increased by $19 million as a
result of the VERP. 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 loss 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
and the unrecognized net transition asset arising out of the adoption of
Statement of Financial Accounting Standards No. 87, "Employers' Accounting for
Pensions," are being amortized as a charge or 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 1994, 1993 and 1992 were $2.2
million, $1.8 million and $1.6 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, the annual premium costs associated with providing these benefits
totaled approximately $3.7 million.
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 1994 and 1993 follows:
(In Millions)
1994 1993
Service cost-benefits attributed to service
during the period $ 2.3 $ 2.2
Interest cost on the accumulated postretirement
benefit obligation 7.1 7.4
Expected return on plan assets (1.2) (0.7)
Amortization of transition obligation 3.4 3.9
Other amortization, net .5 -
Net periodic postretirement benefit cost 12.1 12.8
Less, deferred for future recovery (8.3) (7.8)
Postretirement benefit cost, net of deferrals $ 3.8 $ 5.0
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Metropolitan Edison Company and Subsidiary Companies
The above 1994 amounts do not include a pre-tax charge to earnings of
$9 million relating to the VERP. The amount deferred for future recovery does
not include $2.6 million of allocated postretirement benefit costs from the
Company's affiliates for 1994.
The actual return on the plans' assets for the years 1994 and 1993 was a
gain of $.4 million and $.7 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as
follows:
(In Millions)
1994 1993
Accumulated Postretirement Benefit Obligation:
Retirees $ 65.0 $ 54.0
Fully eligible active plan participants 11.3 14.6
Other active plan participants 30.9 41.2
Total accumulated postretirement
benefit obligation (APBO) $ 107.2 $ 109.8
APBO $(107.2) $(109.8)
Plan assets at fair value 14.1 8.2
APBO in excess of plan assets (93.1) (101.6)
Less: Unrecognized net loss 11.7 18.1
Unrecognized transition obligation 59.6 74.5
Accrued postretirement benefit liability $ (21.8) $ ( 9.0)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
The Company intends to continue funding amounts for postretirement
benefits with an independent trustee, as deemed appropriate from time to time.
The plan assets include equities and fixed income securities.
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $7 million decrease in the APBO
as of December 31, 1994. Also, in 1994, the APBO increased by $7 million as a
result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for
Medicare, then 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 31, 1995. The effect of a 1% annual increase in these assumed
cost trend rates would increase the accumulated postretirement benefit
obligation by approximately $9 million as of December 31, 1994 and the
aggregate of the service and interest cost components of net periodic
postretirement health-care cost by approximately $1 million.
The Company began deferring the incremental postretirement benefit costs,
charged to expense, associated with the adoption of FAS 106 and in accordance
with Emerging Issues Task Force Issue 92-12 "Accounting for OPEB Costs by
Rate-Regulated Enterprises," as authorized by the PaPUC in its 1993 base rate
order.
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Metropolitan Edison Company and Subsidiary Companies
In 1994, the Pennsylvania Commonwealth Court reversed the PaPUC's
decision concerning an unaffiliated Pennsylvania utility's deferral of such
costs, stating that FAS 106 expense incurred after January 1, 1993 (the
effective date for the accounting change) but prior to its next base rate case
could not be deferred for future recovery, and that to assure such future
recovery constituted retroactive ratemaking. The Company believes that the
Commonwealth Court ruling does not affect it because it received PaPUC
authorization as part of its 1993 retail base rate order to defer incremental
FAS 106 expense.
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, 1994:
Balance (In Millions)
% Accumulated
Station Ownership Investment Depreciation
Conemaugh 16.45 $138.9 $ 27.9
Three Mile Island Unit 1 50 412.1 139.9
9. LEASES
The Company's capital leases consist primarily of leases for nuclear
fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled
$33 million and $43 million, respectively (net of amortization of $29 million
and $17 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 $125 million of nuclear fuel
costs may be outstanding at any one time for TMI-1. It is contemplated that
when consumed, portions of the presently 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, 1994, 1993 and 1992 these
amounts were $15 million, $25 million and $30 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.
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Metropolitan Edison Company and Subsidiary Companies
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 38 years, averages
approximately $3 million annually.
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<TABLE>
Metropolitan Edison Company and Subsidiary Companies
METROPOLITAN EDISON COMPANY
AND SUBSIDIARY COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1994
Allowance for Doubtful
Accounts $4,889 $5,525 $1,573(a) $7,098(b) $4,889
Allowance for Inventory
Obsolescence 5,681 - 466(c) 1,572(d) 4,575
Year Ended December 31, 1993
Allowance for Doubtful
Accounts $4,889 $5,260 $1,308(a) $6,568(b) $4,889
Allowance for Inventory
Obsolescence 5,946 80 24(c) 369(d) 5,681
Year Ended December 31, 1992
Allowance for Doubtful
Accounts $3,201 $6,581 $1,119(a) $6,012(b) $4,889
Allowance for Inventory
Obsolescence 6,755 286 159(c) 1,254(d) 5,946
<FN>
(a) Recovery of accounts previously written off.
(b) Accounts receivable written off.
(c) Sale of inventory previously written off.
(d) Inventory written off.
</FN>
F-150</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
COMPANY STATISTICS
<CAPTION>
For The Years Ended December 31, 1994 1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Capacity at Company Peak (In MW):
Company owned 2 369 2 369 2 371 2 512 2 512 2 512
Contracted 778 636 418 224 199 256
Total capacity (a) 3 147 3 005 2 789 2 736 2 711 2 768
Hourly Peak Load (In MW):
Summer peak 2 309 2 208 2 140 2 153 2 078 2 079
Winter peak 2 514 2 342 2 355 2 325 2 282 2 415
Reserve at Company peak (%) 25.2 28.3 18.4 17.7 18.8 14.6
Load factor (%) (b) 69.4 70.5 69.3 70.6 71.4 67.5
Sources of Energy:
Energy sales (In Thousands of MWH):
Net generation 12 030 12 264 13 134 12 635 13 426 14 355
Power purchases and interchange 4 704 4 159 4 186 3 417 2 462 2 135
Total sources of energy 16 734 16 423 17 320 16 052 15 888 16 490
Company use, line loss, etc. (2 248) (2 256) (2 289) (1 992) (2 065) (2 342)
Total 14 486 14 167 15 031 14 060 13 823 14 148
Energy mix (%):
Coal 61 65 65 70 76 75
Nuclear 10 9 10 9 8 11
Utility purchases and interchange 15 14 16 14 13 11
Nonutility purchases 13 12 8 7 2 2
Other (gas, hydro, & oil) 1 - 1 - 1 1
Total 100 100 100 100 100 100
Energy cost (In Mills per KWH):
Coal 15.92 16.25 14.84 15.09 15.73 14.83
Nuclear 6.09 5.44 5.61 6.46 6.46 6.57
Utility purchases and interchange 32.22 27.91 29.77 33.83 34.16 33.69
Nonutility purchases 55.19 53.58 52.84 50.20 51.78 58.19
Other (gas & oil) 59.00 81.46 78.14 85.68 74.26 61.73
Average 21.85 20.85 18.89 18.82 17.23 15.81
Electric Energy Sales (In Thousands of MWH):
Residential 3 773 3 715 3 590 3 553 3 489 3 466
Commercial 3 794 3 651 3 488 3 475 3 150 3 070
Industrial 4 449 4 346 4 589 4 718 5 058 4 935
Other 958 568 585 666 524 482
Sales to customers 12 974 12 280 12 252 12 412 12 221 11 953
Sales to other utilities 1 512 1 887 2 779 1 648 1 602 2 195
Total 14 486 14 167 15 031 14 060 13 823 14 148
Operating Revenues (In Millions):
Residential $ 321 $ 308 $ 298 $ 290 $ 274 $ 271
Commercial 279 261 248 244 215 208
Industrial 237 227 233 236 236 231
Other 45 31 27 32 29 28
Revenues from customers 882 827 806 802 754 738
Sales to other utilities 36 52 62 43 43 56
Total electric revenues 918 879 868 845 797 794
Other revenues 27 29 28 21 21 23
Total $ 945 $ 908 $ 896 $ 866 $ 818 $ 817
Price per KWH (In Cents):
Residential 8.51 8.30 8.27 8.16 7.86 7.82
Commercial 7.34 7.17 7.11 7.01 6.83 6.80
Industrial 5.32 5.24 5.08 4.99 4.66 4.68
Total sales to customers 6.80 6.74 6.58 6.46 6.17 6.18
Total Sales 6.34 6.21 5.77 6.00 5.77 5.61
Kilowatt-hour Sales per Residential Customer 7 678 7 607 7 393 7 369 7 278 7 271
Customers at Year-End (In Thousands) 567 563 559 555 551 547
<FN>
(a) Winter ratings at December 31, 1994 of owned and contracted capacity were
2,365 MW and 772 MW, respectively.
(b) The ratio of the average hourly load in kilowatts supplied during the year
to the peak load occurring during the year.
</FN>
F-151
</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
SELECTED FINANCIAL DATA
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994* 1993 1992 1991** 1990 1989
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 944 744 $ 908 280 $ 896 337 $ 865 552 $ 817 923 $ 816 627
Other operation and
maintenance expense 294 316 241 252 226 179 234 648 230 461 234 410
Net income 31 799 95 728 99 744 106 595 108 712 104 488
Earnings available
for common stock 28 862 90 741 94 080 100 406 99 898 95 674
Net utility plant
in service 1 621 818 1 542 276 1 473 293 1 419 726 1 392 332 1 336 968
Cash construction
expenditures 174 464 150 252 110 629 101 328 97 578 99 268
Total assets 2 381 054 2 301 340 1 892 715 1 862 249 1 801 522 1 786 725
Long-term debt 616 490 524 491 582 647 542 392 536 402 547 196
Long-term obligations
under capital leases 6 741 7 745 7 691 8 260 7 724 7 230
Preferred securities
of subsidiaries 105 000 - - - - -
Return on average
common equity 4.2% 13.5% 14.5% 15.1% 16.4% 16.2%
<FN>
* Results for 1994 reflect a net decrease in earnings of $61.8 million after-tax due to a write-off of
certain TMI-2 future costs ($32.1 million); charges for costs related to the Voluntary Enhanced Retirement
Programs ($25.6 million); a write-off of postretirement benefit costs not considered likely to be recovered
in rates ($10.6 million), and interest income from refunds of previously paid federal income taxes related
to the tax retirement of TMI-2 ($6.5 million).
** Results for 1991 reflect an increase in earnings of $16.2 million after-tax for an accounting change
recognizing unbilled revenues and a decrease in earnings of $16.8 million after-tax for estimated TMI-2 costs.
</FN>
F-152
</TABLE>
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings available for common stock decreased $61.9 million to
$28.9 million. The earnings decrease was principally attributable to a second
quarter write-off of $32.1 million after-tax from an unfavorable Pennsylvania
Commonwealth Court order disallowing the collection of revenues for certain
Three Mile Island Unit 2 (TMI-2) retirement costs, a $25.6 million after-tax
charge to earnings for costs related to the Voluntary Enhanced Retirement
Programs, and a $10.6 million after-tax write-off of postretirement benefit
costs not considered likely to be recovered through ratemaking. The effect of
these charges was partially offset by first quarter interest income of $6.5
million after-tax from refunds of previously paid federal income taxes related
to the tax retirement of TMI-2.
Also contributing to the 1994 earnings decrease was increased other
operation and maintenance (O&M) expense, which included higher emergency and
winter storm repairs.
In 1993, earnings available for common stock decreased $3.4 million to
$90.7 million. The decrease in earnings was principally the result of higher
other O&M expense, the write-off of approximately $4.4 million after-tax of
costs related to the cancellation of proposed energy-related agreements, and
increased depreciation expense. These decreases were partially offset by
higher KWH revenues, the recovery of prior period transmission service
revenues and lower reserve capacity expense.
The Company's return on average common equity was 4.2% for 1994 as
compared to 13.5% for 1993.
OPERATING REVENUES:
Revenues increased 4.0% to $944.7 million in 1994 after increasing 1.3%
in 1993 to $908.3 million. The components of these changes are as follows:
(In Millions)
1994 1993
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ 1.6 $ 6.3
Energy revenues 39.7 (5.2)
Other revenues (4.9) 10.8
Increase in revenues $36.4 $11.9
F-153
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
Kilowatt-hour revenues
1994
The increase in KWH revenues was due principally to an increase in the
average number of commercial and wholesale customers, and higher usage by
wholesale customers. In 1993, the Company successfully negotiated power
supply agreements with wholesale customers previously served by the Company's
affiliates. This was in response to offers made by other utilities seeking to
provide electric service at rates lower than those of Metropolitan Edison
Company (Met-Ed) or Jersey Central Power & Light Company. These increases
were mostly offset by decreased industrial customer usage and decreased
capacity sales to affiliated companies.
1993
KWH revenues increased primarily from higher KWH usage by residential and
commercial customers and higher capacity sales to affiliated companies.
Revenues also increased because of new sales to the Company's principal
wholesale customer. These increases were partially offset by decreased
industrial customer usage. One of the most significant reductions occurred
because of the phase out of operations by the Company's largest industrial
customer.
Energy revenues
1994
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 primarily from higher energy cost rates
in effect and the reclassification in 1993 of certain transmission service
revenues.
1993
Energy revenues decreased as a result of decreased sales to other
utilities and the reclassification of certain transmission service revenues to
other revenues. The reclassification resulted from a favorable Pennsylvania
Public Utility Commission (PaPUC) order allowing the Company to exclude these
transmission service revenues from the Company's energy cost rate. Partially
offsetting these decreases was increased energy revenues resulting from higher
energy cost rates in effect.
Other revenues
1994
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. The decrease in other revenues was primarily due to a one-time benefit
resulting from the recognition in 1993 of prior period transmission service
revenues.
1993
Other revenues increased primarily from increased wheeling revenues and a
one-time benefit resulting from the recognition of prior period transmission
service revenues.
F-154
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
OPERATING EXPENSES:
Power purchased and interchanged
1994
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Company's energy cost rate.
The increase in power purchased and interchanged was primarily attributable to
increased nonutility generation purchases.
1993
Power purchased and interchanged from affiliated companies decreased
primarily as a result of lower reserve capacity costs. The decrease in
expense favorably affected earnings because reserve capacity costs are not
recovered through energy revenues. Power purchased and interchanged from
nonaffiliated companies increased primarily from increased nonutility
generation purchases. This increase was partially offset by lower purchases
from other utilities.
Other operation and maintenance
1994
The increase in other O&M expense was primarily attributable to a
$44.9 million pre-tax charge for costs related to the Voluntary Enhanced
Retirement Programs. Increases were also due to higher emergency and winter
storm repairs and the accrual of additional payroll expense under an expanded
employee incentive compensation program designed to tie pay increases more
closely to business results and enhance productivity.
1993
The increase was due largely to higher outage activity at several of the
Company's coal fired generating stations, and higher payroll and tree trimming
expenses. These increases were partially offset by the recognition of
proceeds from the settlement of a property insurance claim.
Depreciation and amortization
1994
The decrease in depreciation and amortization expense was due largely to
lower TMI-2 amortization and the recognition in 1993 of TMI-2 non-radiological
retirement costs. The lower TMI-2 amortization was attributable to the
Company completing, in 1993, its recovery of the TMI-2 investment from retail
customers.
1993
Depreciation and amortization expense increased primarily from higher
cost of removal charges and a $3.6 million pre-tax charge for TMI-2 non-
radiological retirement costs not considered likely to be recovered through
ratemaking.
F-155
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
Taxes, other than income taxes
1994 and 1993
Generally, changes in taxes other than income taxes do not significantly
affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income/(expense), net
1994
The increase in other expense was principally related to the second
quarter write-off of future TMI-2 retirement costs and postretirement benefit
costs. The effect of these write-offs was partially offset by first quarter
interest income resulting from refunds of previously paid federal income taxes
related to the tax retirement of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993 PaPUC
order that permitted Met-Ed to recover estimated TMI-2 retirement costs from
customers. As a result, the Company recorded second quarter charges of $56.3
million pre-tax for its share of such costs. These charges were comprised of
$51.6 million for retirement costs and $4.7 million for monitored storage
costs.
Also in the second quarter of 1994, the Company wrote off $14.6 million
pre-tax in deferred postretirement benefit costs related to the adoption of
Statement of Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." This was a result of a
Commonwealth Court decision reversing a PaPUC order that allowed a
nonaffiliated utility, outside a base rate case, to defer certain
postretirement benefit costs for future recovery from customers. The Company
had deferred such costs under a similar accounting order issued by the PaPUC.
In addition, the Company recognized a $4 million pre-tax charge for the
remaining transition obligation related to postretirement benefit costs for
the employees who participated in the Voluntary Enhanced Retirement Programs.
The tax retirement of TMI-2 resulted in a refund for the tax years after
TMI-2 was retired. The effect on pre-tax earnings was an increase of
$14.9 million in interest income.
1993
The reduction in other income was due principally to the write-off of
$7.3 million pre-tax which represents the Company's share of costs related to
the cancellation of proposed power supply and transmission facilities
agreements between the Company and its affiliates and Duquesne Light Company.
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Interest charges
1994
Other interest expense was higher due primarily to the tax retirement of
TMI-2, which resulted in a $3.5 million pre-tax increase in interest expense
F-156
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
on additional amounts owed for tax years in which depreciation deductions with
respect to TMI-2 had been taken.
1993
Interest on long-term debt increased primarily from 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
decreased primarily as a result of lower interest rates and lower interest on
energy cost rate overcollections resulting from the reclassification in 1993
of certain transmission service revenues (See "Energy revenues").
Dividends on preferred securities of subsidiary
1994
The increase was attributable to the payment of dividends on the Monthly
Income Preferred Securities issued by the Company's special-purpose finance
subsidiary, Penelec Capital L.P.
PREFERRED STOCK DIVIDENDS:
1994 and 1993
Preferred stock dividends decreased in 1994 and 1993 due to the
redemption in both periods of $25 million stated value of preferred stock.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs were $244 million in 1994, consisting of cash
construction expenditures of $174 million and amounts for maturing obligations
of $70 million. During 1994, construction funds were used primarily to
maintain and improve existing generation facilities and the transmission and
distribution system, and proceed with various clean air compliance projects.
For 1995, construction expenditures are estimated to be $144 million,
consisting mainly of $103 million for ongoing system development, $20 million
for the repowering of an existing generation facility, and $19 million for
clean air compliance projects. The 1995 estimated reduction is largely due to
the completion in 1994 of a significant portion of clean air compliance
requirements. While the Company has no long-term debt maturing in 1995,
expenditures for maturing debt are expected to be $75 million in 1996. In the
late 1990s, construction expenditures are expected to include substantial
amounts for clean air requirements and other Company needs. Management
estimates that approximately three-fourths of the Company's 1995 capital needs
will be satisfied through internally generated funds.
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 $125 million of nuclear
fuel costs may be outstanding at any one time for TMI-1. The Company's share
of the nuclear fuel capital leases at December 31, 1994 totaled $16 million.
F-157
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
When consumed, portions of the presently leased material will be replaced by
additional leased material at a rate of approximately $8 million annually. In
the event the needed nuclear fuel cannot be leased, the associated capital
requirements would have to be met by other means.
FINANCING:
In 1994, the Company issued $105 million of Monthly Income Preferred
Securities (carried on the balance sheet as Preferred securities of
subsidiaries) through its special-purpose finance subsidiary, and an aggregate
of $130 million principal amount of long-term debt. A portion of these
proceeds was used to refinance long-term debt and redeem more costly preferred
stock amounting to $38 million and $25 million, respectively. In addition,
the Company issued $30 million of long-term debt in February 1995. The net
proceeds from this issuance will be used to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and
Exchange Commission (SEC) to issue up to five million shares of additional
common stock through 1996. The proceeds from the sale of such additional
common stock would be used to increase the Company and its affiliates' common
equity ratios and reduce GPU short-term debt. GPU will monitor the capital
markets as well as its capitalization ratios relative to its targets to
determine whether, and when, to issue such shares.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), 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 $260 million, of which $100 million may
consist of preferred stock. The Company, through its special-purpose finance
subsidiary, has remaining regulatory authority to issue an additional $20
million of Monthly Income Preferred Securities. 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 bond indenture and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Company may issue. As a result of the TMI-2 retirement costs
write-offs, together with certain other costs recognized in the second quarter
of 1994, the Company has sufficient coverage to issue only approximately
$49 million of FMBs through June 1995, depending on interest rates at the time
of issuance, plus $38 million of FMBs on the basis of previously issued and
retired bonds. In addition, the Company will be unable to meet coverage
requirements for issuing preferred stock until the third quarter of 1995. The
Company's ability to issue its remaining authorized Monthly Income Preferred
Securities, which have no such coverage restrictions, is not affected by these
write-offs.
The Company's cost of capital and ability to obtain external financing is
affected by its security ratings, which are periodically reviewed by the three
major credit rating agencies. Following a review that was prompted by the
Commonwealth Court's order denying recovery of TMI-2 retirement costs, Moody's
Investors Service (Moody's) and Standard & Poor's Corporation (S&P) downgraded
F-158
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
the Company's security ratings in August 1994 citing, among other things, the
Company's weakened financial flexibility resulting from the second quarter
1994 write-offs. The Company's FMBs are currently rated at an equivalent of
an A- or higher by the three major credit rating agencies, while the preferred
stock issues and Monthly Income Preferred Securities have been assigned an
equivalent of BBB+ or higher. In addition, the Company's commercial paper is
rated as having good to high credit quality. Although credit quality has been
reduced, the Company's credit ratings remain above investment grade.
In 1994, the S&P rating outlook, which is used to assess the potential
direction of an issuer's long-term debt rating over the intermediate- to
longer-term, was revised to "stable" from "negative" for the Company. The
outlook reflects S&P's judgment that the Company has manageable construction
spending, limited external financing requirements, regionally competitive
rates, and an emphasis on cost cutting to offset base rate relief requirements
during the next few years. S&P also assigned the Company an "average"
business position, a financial benchmarking standard for rating the debt of
electric utilities to reflect the changing risk profiles resulting primarily
from the intensifying competitive pressures in the industry.
In June 1994, Moody's announced that it developed a new method to
calculate the minimum price an electric utility must charge its customers in
order to recover all of its generation costs. Moody's believes that an
assessment of relative cost position will become increasingly critical to the
credit analysis of electric utilities in a competitive marketplace. Specific
rating actions are not anticipated, however, until the pace and implications
of utility market deregulation are more certain.
Present plans call for the Company to issue long-term debt during the
next three years to finance construction activities, fund the redemption of
maturing senior securities, make contributions to decommissioning trust funds
and, depending on the level of interest rates, refinance outstanding senior
securities.
CAPITALIZATION:
The Company targets capitalization ratios that should warrant sufficient
credit quality ratings to permit capital market access at reasonable costs.
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. GPU's financing plans contemplate security issuances in 1995 to
strengthen the equity component of the Company and its affiliates' capital
structures. The Company's targets and actual capitalization ratios are as
follows:
Capitalization
Target Range 1994 1993 1992
Common equity 45-48% 43% 48% 46%
Preferred equity 8-10 9 4 7
Notes payable and
long-term debt 47-42 48 48 47
100% 100% 100% 100%
F-159
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated
monopolies. Over the last few years, however, market forces combined with
state and federal actions, have laid the foundation for the continued
development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of
competition in Pennsylvania's electric utility industry and solicited comments
on various issues. The Company and Met-Ed jointly filed responses in November
1994 suggesting, among other things, that the PaPUC provide for the equitable
recovery of stranded investments, enable utilities to offer flexible pricing
to customers with competitive alternatives, and address regulatory
requirements that impose costs unequally on Pennsylvania utilities as compared
with unregulated or out-of-state suppliers. At the end of the investigation,
which is expected to be concluded in early 1995, the PaPUC will decide whether
to conduct a rulemaking proceeding.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking regarding the recovery by utilities of
legitimate and verifiable stranded costs. Costs incurred by a utility to
provide integrated electric service to a franchise customer become stranded
when that customer subsequently purchases power from another supplier using
the utility's transmission services. Among other things, the FERC proposed
that utilities be allowed under certain circumstances to recover such stranded
costs associated with existing wholesale customer contracts, but not under new
wholesale contracts unless expressly provided for in the contract. While it
stated a "strong" policy preference that state regulatory agencies address
recovery of stranded retail costs, the FERC also set forth alternative
proposals for how it would address the matter if the states failed to do so.
Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of
Appeals for the District of Columbia, in an unrelated case, questioned the
FERC's authority to permit utilities to recover stranded costs. The Court
remanded the matter to the FERC for it to conduct an evidentiary hearing in
the case to determine whether, among other things, permitting stranded cost
recovery was so inherently anticompetitive that it violates antitrust laws.
While largely supported by the electric utility industry, the Proposed
Rulemaking has been strongly opposed by other groups. There can be no
assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing
for electric transmission services. The policy statement contains five
principles that will provide the foundation for the FERC's analyses of all
subsequent transmission rate proposals. Recognizing the evolution of a more
competitive marketplace, the FERC contends that it is critical that
transmission services be priced in a manner that appropriately compensates
transmission owners and creates adequate incentives for efficient system
expansion.
F-160
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
In 1994, the SEC issued for public comment a Concept Release regarding
modernization of the Public Utility Holding Company Act of 1935 (Holding
Company Act). GPU regards the Holding Company Act as a significant impediment
to competition and supports its repeal. In addition, GPU believes that the
Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally
reformed given the burdens being placed on electric utilities by PURPA
mandated uneconomic long-term power purchase agreements with nonutility
generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related
actions as a result of its ongoing strategic planning activities. Responding
to its assessment that competition in the electric utility industry is likely
to accelerate, GPU proceeded to implement two major organizational changes as
well as other programs designed to reduce costs and strengthen GPU's
competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the
non-nuclear generation facilities owned by the Company and its affiliates as
well as undertake responsibility to construct any new non-nuclear generation
facilities which the Company and its affiliates may need in the future. By
forming GPU Generation Corporation (GPUGC), GPU will consolidate and
streamline the management of these generation facilities, and seek to apply
management and operating efficiency techniques similar to those employed in
more competitive industries. This initiative is intended to bring the Company
and its affiliates' generation costs more in line with projected market
prices. GPU Nuclear Corporation is engaging in a search for parallel
opportunities. The Company and its affiliates received regulatory approvals
to enter into an operating agreement with GPUGC from the PaPUC and New Jersey
Board of Public Utilities. SEC authorization is expected to be received in
1995.
The second part of the realignment includes the management combination
of the Company and its affiliate, Met-Ed. This action is intended to increase
effectiveness and lower costs of Pennsylvania customer operations and service
functions.
Other organizational realignments, designed to streamline management and
reduce costs, were also implemented throughout the GPU System in 1994. In
addition, GPU expanded employee participation in its incentive compensation
program to tie pay increases more closely to business results and enhance
productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU
System workforce accepted the Voluntary Enhanced Retirement Programs. Future
payroll and benefits savings, which are estimated to be $75 million annually
(of which the Company's share is $26 million), began in the third quarter and
reflect limiting the replacement of employees up to ten percent of those
retired. Retirement benefits will be substantially paid from pension and
postretirement plan trusts.
F-161
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the
electric utility industry that calls into question the assumptions regarding
the recovery of certain costs through ratemaking. As the utility industry
continues to experience an increasingly competitive environment, GPU is
attempting to assess the impact that these and other changes will have on the
Company and its affiliates' financial position. For additional information
regarding the other changes that may have an adverse effect on the Company,
see the Competition and the Changing Regulatory Environment section of Note 1
to the Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace,
the cost of near- to intermediate-term regional energy supply from existing
facilities, as evidenced by the results of an all source competitive supply
solicitation conducted by the Company's New Jersey affiliate in 1994, is less
than the rates in virtually all of the Company's nonutility generation
agreements. In addition, the projected cost of energy from new supply sources
is now lower than was expected in the recent past due to improvements in power
plant technologies and reduced fuel prices.
The long-term nonutility generation agreements included in the Company's
supply plan have been entered into pursuant to the requirements of PURPA and
state regulatory directives. The Company intends to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company is also attempting to renegotiate, and in some cases buy out, existing
high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility
generation costs from customers by the PaPUC, there can be no assurance that
the Company will continue to recover these costs throughout the terms of the
related agreements. The Company currently estimates that in 1998, when
substantially all of these nonutility generation projects are scheduled to be
in-service, above market payments (benchmarked against the expected cost of
electricity produced by a new gas-fired combined cycle facility) will range
from $90 million to $120 million annually.
THE SUPPLY PLAN:
Under existing retail regulation, supply planning in the electric
utility industry is directly related to projected growth in the franchise
service territory. At this time, management cannot estimate the timing and
extent to which retail electric competition will affect the Company's supply
plan. As the Company prepares to operate in an increasingly competitive
environment, its supply plan currently focuses on maintaining the existing
customer base by offering competitively priced electricity.
F-162
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
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" market purchases, and
avoidance of long-term firm commitments.
Over the next five years, the Company is projected to experience an
average growth in sales to customers of about 2% annually. These increases
are expected to result from continued economic growth in the service territory
and a slight increase in customers. To meet this growth, assuming the
continuation of existing retail electric regulation, the Company's plan
consists of the continued utilization of existing generation facilities
combined with present commitments for power purchases, and the continued
promotion of economic energy-conservation and load-management programs.
The Company's present strategy includes minimizing the financial
exposure associated with new long-term purchase commitments and the
construction of new facilities by evaluating these options in terms of an
unregulated power market. The Company will take necessary actions to avoid
adding 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.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility
generators and the repowering of an existing generation facility. Additional
capacity needs are principally related to the expiration of existing
commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility
generators under which a total of 295 MW of capacity is currently in service
and about an additional 279 MW are currently scheduled or anticipated to be in
service by 1999.
The Company's supply plan also includes a repowering project at its
Warren Generating Station that combines a coal-fueled combustion turbine with
an existing generator. The repowering project will enable the station to
comply with state and federal standards for reduced emissions and increase
electrical output to approximately 100 MW. While the U.S. Department of
Energy has agreed to fund 50% of the $146 million project cost as part of its
Clean Coal Technology Program, management is unable to determine what effect
recent federal budget cut proposals will have on Congressional appropriation
of this funding. The project is in the early stages of development and is
estimated to be in-service in 1996.
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially
reduce above-market payments for energy supplied by nonutility generators.
The Company will also continue to take legal, regulatory and legislative
F-163
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
initiatives to avoid entering into any new power-supply agreements that are
either not needed or, if needed, are not consistent with competitive market
pricing. The following is a discussion of major nonutility generation
activities involving the Company.
In November 1994, the Company requested the Pennsylvania Supreme Court
to review a Commonwealth Court decision upholding a PaPUC order requiring the
Company to purchase a total of 160 MW from two nonutility generators. The
PaPUC had ordered the Company in 1993 to enter into power purchase agreements
with the nonutility generators for 80 MW of power each under long-term
contracts commencing in 1997 or later. In August 1994, the Commonwealth Court
denied the Company's appeal of the PaPUC order. The Company's petition to the
Supreme Court contends that the Commonwealth Court imposed unnecessary and
excessive costs on the Company's customers by finding that the Company had a
need for capacity. The petition also questions the Commonwealth Court's
upholding of the PaPUC's determination that the nonutility generators had
incurred a legal obligation entitling them to payments under PURPA.
As part of the effort to reduce above-market payments under nonutility
generation agreements, the Company and its affiliates are seeking to implement
a program under which the natural gas fuel and transportation for the Company
and its affiliates' gas-fired facilities, as well as up to approximately 1,100
MW of nonutility generation capacity, would be pooled and managed by a
nonaffiliated fuel manager. The Company and its affiliates believe the plan
has the potential to provide substantial savings for their customers. The
Company and its affiliates have begun initial discussions with the nonutility
generators who would be eligible to participate. Requirements for approval of
the plan by state and federal regulatory agencies are being reviewed.
Conservation and Load Management
The PaPUC continues to encourage the development of new conservation and
load-management programs. Because the benefits of some of these programs may
not offset program costs, the Company is working to mitigate the impacts these
programs can have on the Company's competitive position in the marketplace.
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of DSM costs and directed utilities to implement DSM programs. The Company
subsequently filed a DSM program that was expected to be approved by the PaPUC
in the first quarter of 1995. However, an industrial intervenor had contested
the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed
the PaPUC order. As a result, the nature and scope of the Company's DSM
program is uncertain at this time.
ENVIRONMENTAL ISSUES:
The Clean Air Act Amendments of 1990 (Clean Air Act) require substantial
reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year
2000. The Company's current plan includes installing and operating emission
control equipment at some of its coal-fired facilities as well as switching to
lower sulfur coal at other coal-fired facilities.
F-164
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
To comply with the Clean Air Act, the Company expects to spend up to
$177 million by the year 2000 for air pollution control equipment. Through
December 31, 1994, the Company has made capital expenditures of approximately
$75 million to comply with the Clean Air Act requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of
representatives of 12 northeast states (including New Jersey and Pennsylvania)
and the District of Columbia proposed reductions in NOx emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Company expects that the U.S.
Environmental Protection Agency will approve the proposal, and that as a
result, the Company will spend an estimated $50 million, beginning in 1997, to
meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Company is unable to
determine what, if any, additional costs will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the
Company will continue to evaluate the risk of recovering capital investments
compared to increased participation in the emission allowance market and the
use of low-sulfur coal or the early retirement of facilities. These 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 plants are expected to be recoverable through the current
ratemaking process, but management recognizes that recovery is not assured.
For more information, see the Environmental Matters section of Note 1 to
the Consolidated Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately 2,100
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 Consolidated Financial Statements.
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since
the regulatory process results in a time lag during which increased operating
expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry,
the Company does not plan to take any actions that would increase customers'
base rates over the next several years. Therefore, the control of operating
and capital costs will be essential. As competition and deregulation
accelerate, there can be no assurance as to the recovery of increased
operating expense or utility plant investments.
F-165
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
The Company is committed to long-term cost control and continues to seek
and implement measures to reduce or limit the growth of operating expenses and
capital expenditures, including the associated effects of inflation. Though
currently operating in a regulated environment, the Company's focus will be
less reliant on the ratemaking process, and geared toward continued
performance improvement and cost reduction to facilitate the competitive
pricing of its products and services.
F-166
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1994* 1993 1994** 1993
Operating revenues $247 180 $231 148 $227 122 $219 232
Operating income 46 017 45 279 8 749 32 357
Net income 38 965 33 212 (46 671) 20 246
Earnings available
for common stock 38 057 31 796 (47 580) 18 830
In Thousands
Third Quarter Fourth Quarter
1994 1993 1994 1993***
Operating revenues $240 267 $229 447 $230 175 $228 453
Operating income 38 238 42 835 33 228 26 566
Net income 24 351 31 714 15 154 10 556
Earnings available
for common stock 23 617 30 467 14 768 9 648
* Results for the first quarter 1994 reflect an increase in earnings of
$6.5 million after-tax for income from refunds of previously paid federal
income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of
$68.3 million after-tax due to a write-off of certain TMI-2 future costs
($32.1 million); charges for costs related to the Voluntary Enhanced
Retirement Programs ($25.6 million); and a write-off of postretirement
benefit costs not considered likely to be recovered in rates ($10.6
million).
*** Results for the fourth quarter of 1993 reflect a decrease in earnings of
$4.6 million after-tax for the write-off of the Duquesne transactions.
F-167
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Pennsylvania Electric Company
Reading, Pennsylvania
We have audited the consolidated financial statements and financial
statement schedule of Pennsylvania Electric Company and Subsidiary Companies
as listed in the index on page F-1 of this Form 10-K. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule 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 consolidated financial position of
Pennsylvania Electric Company and Subsidiary Companies as of December 31, 1994
and 1993, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
As more fully discussed in Note 1 to consolidated financial statements,
the Company and its affiliates are unable to determine the ultimate
consequences of certain contingencies which have resulted from the accident at
Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The
matters which remain uncertain are (a) the extent to which the retirement
costs of TMI-2 could exceed amounts currently recognized for ratemaking
purposes or otherwise accrued, and (b) 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 consolidated 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.
Coopers & Lybrand L.L.P.
New York, New York
February 1, 1995
F-168
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Revenues $944 744 $908 280 $896 337
Operating Expenses:
Fuel 175 071 182 923 178 528
Power purchased and interchanged:
Affiliates 6 310 3 606 15 078
Others 151 919 131 791 113 333
Deferral of energy costs, net 5 941 (23 145) (44)
Other operation and maintenance 294 316 241 252 226 179
Depreciation and amortization 76 600 90 463 84 227
Taxes, other than income taxes 66 058 61 697 61 177
Total operating expenses 776 215 688 587 678 478
Operating Income Before Income Taxes 168 529 219 693 217 859
Income taxes 42 297 72 656 70 551
Operating Income 126 232 147 037 147 308
Other Income and Deductions:
Allowance for other funds used during
construction 1 841 869 -
Other income (expense), net (71 287) (7 021) (179)
Income taxes 31 369 3 420 (6)
Total other income and deductions (38 077) (2 732) (185)
Income Before Interest Charges and Dividends
on Preferred Securities 88 155 144 305 147 123
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 46 439 44 714 42 615
Other interest 7 421 5 255 6 415
Allowance for borrowed funds used during
construction (1 996) (1 392) (1 651)
Dividends on preferred securities
of subsidiary 4 492 - -
Total interest charges and dividends
on preferred securities 56 356 48 577 47 379
Net Income 31 799 95 728 99 744
Preferred stock dividends 2 937 4 987 5 664
Earnings Available for Common Stock $ 28 862 $ 90 741 $ 94 080
The accompanying notes are an integral part of the consolidated financial statements.
F-169</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $2 549 316 $2 429 557
Less, accumulated depreciation 927 498 887 281
Net utility plant in service 1 621 818 1 542 276
Construction work in progress 98 329 81 420
Other, net 27 717 35 614
Net utility plant 1 747 864 1 659 310
Other Property and Investments:
Nuclear decommissioning trusts 29 871 24 657
Other, net 4,596 4,338
Total other property and investments 34 467 28 995
Current Assets:
Cash and temporary cash investments 1 191 1 622
Special deposits 3 242 2 622
Accounts receivable:
Customers, net 68 547 64 913
Other 21 897 9 824
Unbilled revenues 29 181 28 942
Materials and supplies, at average cost or less:
Construction and maintenance 49 342 46 994
Fuel 20 092 20 590
Deferred energy costs 10 826 17 047
Deferred income taxes 3 157 790
Prepayments 4 726 6 630
Total current assets 212 201 199 974
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 13 214 64 638
Deferred income taxes 114 231 64 577
Income taxes recoverable through future rates 227 177 234 026
Other 31 900 49 820
Total deferred debits and other assets 386 522 413 061
Total Assets $2 381 054 $2 301 340
The accompanying notes are an integral part of the consolidated financial statements.
F-170</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED BALANCE SHEETS
<CAPTION>
(In Thousands)
December 31, 1994 1993
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 105 812 $ 105 812
Capital surplus 261 671 265 486
Retained earnings 290 786 328 290
Total common stockholder's equity 658 269 699 588
Cumulative preferred stock 36 777 61 842
Preferred securities of subsidiary 105 000 -
Long-term debt 616 490 524 491
Total capitalization 1 416 536 1 285 921
Current Liabilities:
Debt due within one year 9 70 008
Notes payable 111 052 102 356
Obligations under capital leases 17 957 23 333
Accounts payable:
Affiliates 10 668 6 025
Others 62 642 85 254
Taxes accrued 13 347 11 978
Interest accrued 16 356 15 369
Vacations accrued 12 004 11 956
Other 13 311 13 511
Total current liabilities 257 346 339 790
Deferred Credits and Other Liabilities:
Deferred income taxes 454 026 455 076
Unamortized investment tax credits 47 864 51 775
Three Mile Island Unit 2 future costs 85 273 79 967
Nuclear fuel disposal fee 12 918 12 401
Other 107 091 76 410
Total deferred credits and other liabilities 707 172 675 629
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 381 054 $2 301 340
The accompanying notes are an integral part of the consolidated financial statements.
F-171</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Balance at beginning of year $328 290 $278 482 $289 402
Add - Net income 31 799 95 728 99 744
Total 360 089 374 210 389 146
Deduct - Cash dividends on capital stock:
Cumulative preferred stock (at the
annual rates indicated below):
4.40% Series B ($ 4.40 a share) 250 250 250
3.70% Series C ($ 3.70 a share) 359 359 359
4.05% Series D ($ 4.05 a share) 258 258 258
4.70% Series E ($ 4.70 a share) 135 135 135
4.50% Series F ($ 4.50 a share) 193 193 194
4.60% Series G ($ 4.60 a share) 349 349 348
8.36% Series H ($ 8.36 a share) 1 393 2 090 2 090
8.12% Series I ($ 8.12 a share) - 1 353 2 030
Common stock (not declared on
a per share basis) 65 000 40 000 105 000
Total 67 937 44 987 110 664
Other adjustments, net 1 366 933 -
Total 69 303 45 920 110 664
Balance at end of year $290 786 $328 290 $278 482
The accompanying notes are an integral part of the consolidated financial statements.
F-172</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED STATEMENT OF CAPITAL STOCK AND PREFERRED SECURITIES
<CAPTION>
December 31, 1994 (In Thousands)
<S> <C>
Cumulative preferred stock, without par value, 11,435,000 shares
authorized, 365,000 shares issued and outstanding, without
mandatory redemption (a)(b):
56 810 shares, 4.40% Series B (callable at $108.25 per share) $ 5 681
97 054 shares, 3.70% Series C (callable at $105.00 per share) 9 705
63 696 shares, 4.05% Series D (callable at $104.53 per share) 6 370
28 739 shares, 4.70% Series E (callable at $105.25 per share) 2 874
42 969 shares, 4.50% Series F (callable at $104.27 per share) 4 297
75 732 shares, 4.60% Series G (callable at $104.25 per share) 7 573
Subtotal - Cumulative preferred stock issued 36 500
Premium on cumulative preferred stock 277
Total cumulative preferred stock 36 777
Cumulative Monthly Income Preferred Securities, 8.75% Series A,
without par value, 5,000,000 securities authorized, 4,200,000
securities issued and outstanding (c)(d): $105 000
Common stock, par value $20 per share, 5,400,000 shares
authorized, 5,290,596 shares issued and outstanding $105 812
<FN>
(a) If dividends upon any shares of preferred stock are in arrears in an amount
equal to the annual dividend, 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.
(b) No shares of capital stock have been sold during the three years ended
December 31, 1994. During 1994, the Company redeemed its 8.36% Series H
(aggregated stated value $25 million) cumulative preferred stock. The
Company's total cost of redemption was $26 million, which resulted in a
$1.1 million charge to retained earnings. During 1993, the Company
redeemed its 8.12% Series I (aggregated stated value $25 million)
cumulative preferred stock. The Company's total cost of redemption was
$25.9 million, which resulted in a $0.9 million charge to retained
earnings. No shares of capital stock were redeemed or repurchased during
1992.
(c) In 1994, Penelec Capital L.P., a special purpose finance subsidiary of the
Company, issued $105 million of Monthly Income Preferred Securities. The
proceeds from the issuance of the Monthly Income Preferred Securities were
then loaned to the Company which in turn issued deferrable interest
subordinated debentures to its special purpose fiance subsidiary. The
Company is taking tax deductions for the interest paid on the subordinated
debentures while gaining some preferred equity recognition from the credit
rating agencies for the Monthly Income Preferred Securities.
(d) The issued and outstanding Monthly Income Preferred Securities of Penelec
Capital L.P. mature in 2043 and are redeemable after July 4, 1999, or if
the Company loses its tax deduction for interest paid on it subordinated
debentures, at 100% of the principal amount. Interest on the Monthly
Income Preferred Securities is paid monthly but can be deferred for a
period of up to 60 months. However, the Company may not pay dividends on
any shares of its preferred or common stock until deferred interest on its
subordinated debentures is paid in full.
</FN>
The accompanying notes are an integral part of the consolidated financial statements.
F-173</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
(In Thousands)
For The Years Ended December 31, 1994 1993 1992
<S> <C> <C> <C>
Operating Activities:
Income before preferred stock dividends $ 31 799 $ 95 728 $ 99 744
Adjustments to reconcile income to cash provided:
Depreciation and amortization 69 615 82 951 78 431
Amortization of property under capital leases 8 553 8 183 9 226
Three Mile Island Unit 2 costs 56 304 - -
Voluntary enhanced retirement program 44 856 - -
Nuclear outage maintenance costs, net 2 862 (2 195) 2 532
Deferred income taxes and investment tax
credits, net (50 451) 18 612 10 376
Deferred energy costs, net 6 221 (23 097) 867
Accretion income (200) (800) (1 600)
Allowance for other funds used
during construction (1 842) (869) -
Changes in working capital:
Receivables (15 945) (7 894) 12 370
Materials and supplies (1 849) 13 664 1 899
Special deposits and prepayments 1 644 (1 777) 6 766
Payables and accrued liabilities (12 804) 1 356 (23 158)
Other, net 12 803 (5 798) (3 906)
Net cash provided by operating activities 151 566 178 064 193 547
Investing Activities:
Cash construction expenditures (174 464) (150 252) (110 629)
Contributions to decommissioning trusts (5 705) (19 411) (1 139)
Other, net 134 5 806 (191)
Net cash used for investing activities (180 035) (163 857) (111 959)
Financing Activities:
Issuance of long-term debt 129 100 119 220 109 288
Increase in notes payable, net 8 774 54 205 3 493
Capital lease principal payments (8 734) (7 492) (8 431)
Issuance of preferred securities of subsidiary 101 185 - -
Retirement of long-term debt (108 008) (108 008) (75 207)
Redemption of preferred stock (26 168) (26 013) -
Dividends paid on common stock (65 000) (40 000) (105 000)
Dividends paid on preferred stock (3 111) (5 156) (5 664)
Net cash provided (required) by
financing activities 28 038 (13 244) (81 521)
Net (decrease) increase in cash and temporary
cash investments from above activities (431) 963 67
Cash and temporary cash investments, beginning
of year 1 622 659 592
Cash and temporary cash investments, end of year $ 1 191 $ 1 622 $ 659
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 55 221 $ 45 939 $ 46 370
Income taxes paid $ 59 881 $ 52 565 $ 65 762
New capital lease obligations incurred $ 2 400 $ 13 317 $ 3 098
The accompanying notes are an integral part of the consolidated financial statements.
F-174</TABLE>
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
CONSOLIDATED STATEMENT OF LONG-TERM DEBT
<CAPTION>
December 31, 1994 (In Thousands)
First Mortgage Bonds-Series as noted (a)(b):
<S> <C> <S> <C> <C>
6 1/4%, due 1996 $25 000 7.48 %, due 2004 $40 000
6.80 %, due 1996 20 000 6.10 %, due 2004 30 000
7.45 %, due 1996 30 000 6.35 %, due 2006 40 000
6 1/4%, due 1997 26 000 7 3/4%, due 2006 12 000
8.72 %, due 1999 30 000 8.05 %, due 2006 10 000
6.15 %, due 2000 30 000 6 1/8%, due 2007 16 420
8.70 %, due 2001 30 000 6.55 %, due 2009 50 000
7.40 %, due 2002 10 000 8 3/8%, due 2015 20 000 (c)
7.43 %, due 2002 30 000 6 1/2%, due 2016 25 000 (d)
7.92 %, due 2002 10 000 8.33 %, due 2022 20 000
7.40 %, due 2003 10 000 7.49 %, due 2023 30 000
6.60 %, due 2003 30 000 8.38%, due 2024 40 000
Subtotal $614 420
Amounts due within one year ( - ) $614 420
Other long-term debt (net of $9 thousand due within one year) 3 067
Unamortized net discount on long-term debt ( 997)
Total long-term debt $616 490
<FN>
(a) Substantially all of the properties owned by the Company are subject to the
lien of the mortgage.
(b) For the years 1996, 1997 and 1999, the Company has total long-term debt
maturities of $75.0 million, $26.0 million and $30.0 million, respectively.
The Company has no long-term debt maturities in 1995 and 1998.
(c) Effective as of any June 1 or December 1, the interest rate may be converted,
at the option of the registered holder thereof, to a variable rate. Outstanding
at December 31, 1994 was $19.640 million at the fixed rate of 8 3/8% and
$.360 million at the variable rate of 5 1/2%.
(d) Effective as of any June 1 or December 1, the interest rate may be converted,
at the option of the registered holder thereof, to a variable rate. Outstanding
at December 31, 1994 was $1.875 million at the fixed rate of 6 1/2% and
$23.125 million at the variable rate of 5%.
The accompanying notes are an integral part of the consolidated financial statements.
</FN>
F-175</TABLE>
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pennsylvania Electric Company (the Company), a Pennsylvania corporation
incorporated in 1919, 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 owns all of the common stock of
Penelec Preferred Capital, Inc., which is the general partner of Penelec
Capital L.P., a special purpose finance subsidiary. The Company also has two
minor wholly-owned subsidiaries. The Company is affiliated with Jersey
Central Power & Light Company (JCP&L) and Metropolitan Edison Company
(Met-Ed). The Company, JCP&L and Met-Ed 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 Energy Initiatives, Inc. (EI), and EI Power, Inc., which develop, own and
operate nonutility generating facilities. All of the Company's affiliates are
wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC,
GPUN, EI and EI Power, Inc. are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in two major nuclear projects -- Three
Mile Island Unit 1 (TMI-1) which is an operational generating facility, and
Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident.
TMI-1 and TMI-2 are jointly owned by the Company, JCP&L and Met-Ed in the
percentages of 25%, 25% and 50%, respectively. At December 31, the Company's
net investment in TMI-1 and TMI-2, including nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2
1994 $154 $8
1993 $165 $9
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, 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 its nuclear
plants because of the prevailing design criteria 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 the
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 each plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
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COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
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 accident cleanup program was completed in 1990. After receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100
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 and the suppliers of equipment and services to TMI-
2, and are pending in the United States District Court for the Middle District
of Pennsylvania. Some of the claims also seek recovery on the basis of
alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are
not covered by insurance and are not subject to the liability limitations of
the federal Price-Anderson Act ($560 million at the time of the accident),
punitive damage awards could have a material adverse effect on the financial
position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for premium charges deferred in whole or
in major part under such plan, and (c) an indemnity agreement with the NRC,
bringing their total primary and secondary insurance financial protection and
indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers under a reservation of rights with respect to any award of
punitive damages. However, in March 1994, the defendants in the TMI-2
litigation and the insurers agreed that the insurers would withdraw their
reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is likely to begin in 1996. 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
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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. In July 1994, the Court
granted defendants' motion for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals.
In an Order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
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 TMI-1 by 2014, the end of the plant's license term. 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 1994 dollars) for TMI-1 is $157 million,
of which the Company's share is $39 million. Based on NRC studies, a
comparable funding target for TMI-2 has been developed which takes the
accident into account (see TMI-2 Future Costs). The NRC continues to study
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 considered 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 a site-specific study of TMI-1
that considered various decommissioning plans and estimated the cost of
decommissioning the radiological portions of TMI-1 to range from approximately
$225 million to $309 million, of which the Company's share would range from
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$56 million to $77 million (adjusted to 1994 dollars). In addition, the study
estimated the cost of removal of nonradiological structures and materials for
TMI-1 at $74 million, of which the Company's share is $19 million (adjusted to
1994 dollars).
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 and its affiliates charge to expense and
contribute to external trusts amounts collected from customers for nuclear
plant decommissioning and nonradiological costs. In addition, the Company has
contributed amounts written off for TMI-2 nuclear plant decommissioning in
1991 to TMI-2's external trust and will await resolution of the case pending
before the Pennsylvania Supreme Court before making any further contributions
for amounts written off by the Company in 1994. Amounts deposited in external
trusts, including the interest earned on these funds, are classified as
Nuclear Decommissioning Trusts on the balance sheet.
TMI-1:
In 1993, the Pennsylvania Public Utility Commission (PaPUC) approved a
rate change for the Company that increased the collection of revenues for
decommissioning costs for TMI-1 based on its share of the NRC funding target.
Collections from customers for retirement expenditures are deposited in
external trusts. Provision for the future expenditures of these funds has
been made in accumulated depreciation, amounting to $8 million, at December
31, 1994. TMI-1 retirement costs are charged to depreciation expense over
the expected service life of each nuclear plant.
Management believes that any TMI-1 retirement costs, in excess of those
currently recognized for ratemaking purposes, should be recoverable through
the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target in
1994 dollars. 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 for incremental
costs specifically attributable to monitored storage. In addition, the Company
and its affiliates have recorded a liability for nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $2
million, of which the Company's share is $.5 million, as of December 31, 1994.
Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and
1993 for the Company are as follows:
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(Millions) (Millions)
1994 1993
Radiological Decommissioning $ 62 $ 57
Nonradiological Cost of Removal 18 18
Incremental Monitored Storage 5 5
Total $ 85 $ 80
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At December 31, 1994, $21 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet,
and $5 million was recoverable from wholesale customers and included in Three
Mile Island Unit 2 Deferred Costs on the balance sheet.
In 1993, a PaPUC rate order for Met-Ed allowed for the future recovery
of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer
Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate
order and in 1994, the Commonwealth Court reversed the PaPUC order. In
December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to
review that decision. The Company, which is also subject to PaPUC regulation,
recorded pre-tax charges of $56.3 million during 1994, for its share of such
costs applicable to its retail customers. These charges appear in the Other
Income and Deductions section of the Income Statement and are composed of
$38.4 million for radiological decommissioning costs, $13.2 million for the
nonradiological cost of removal and $4.7 million for incremental monitored
storage costs. The Company will await resolution of the case pending before
the Pennsylvania Supreme Court before making any nonrecoverable funding
contributions to external trusts for its share of these costs. The Company
will be similarly required to charge to expense its share of future increases
in the estimate of the costs of retiring TMI-2. Future earnings on trust fund
deposits for the Company will be recorded as income. Prior to the
Commonwealth Court's decision, the Company expensed and contributed
$20 million to external trusts relating to its nonrecoverable share of the
accident-related portion of the decommissioning liability.
As a result of TMI-2's entering long-term monitored storage in late
1993, the Company and its affiliates are incurring incremental annual storage
costs of approximately $1 million, of which the Company's share is $.25
million. The Company and its affiliates estimate that the remaining annual
storage costs will total $19 million, of which the Company's share is $5
million, through 2014, the expected retirement date of TMI-1.
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.
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The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station totals $2.7 billion. In
accordance with NRC regulations, these insurance policies generally require
that proceeds first be used for stabilization of 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 that station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial 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 two operating reactors (TMI-2 is excluded under
an exemption received from the NRC in 1994), subject to an annual maximum
payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at its
nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the
outage and continues for three years beginning at $2.6 million per week for
the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and
facilities, the GPU System is subject to retrospective premium assessments of
up to $69 million, of which the Company's share is $9 million, in any one
year, in addition to those payable (up to $20 million, of which the Company's
share is $2 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
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 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation," 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
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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.
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 any
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 currently.
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 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 at the contract
price all of the power produced up to the contract limits. As of December 31,
1994, facilities covered by these agreements having 295 MW of capacity were in
service and 102 MW were scheduled to commence operation in 1995. Payments made
pursuant to these agreements were $123 million, $104 million and $77 million
for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998,
and 1999, payments pursuant to these agreements are estimated to aggregate
$185 million, $192 million, $237 million, $302 million and $312 million,
respectively. These agreements, together with those for facilities which are
not yet in operation, provide for the purchase of approximately 574 MW of
capacity and energy by the Company by the mid-to-late 1990s, at varying
prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the GPU System's energy supply needs which has
caused the Company and its affiliates to change their supply strategy to now
seek shorter-term agreements offering more flexibility (see Management's
Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current
availability of excess capacity in the market place, the cost of near- to
intermediate-term (i.e., one to eight years) energy supply from existing
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generation facilities is currently competitively priced. The projected cost
of energy from new generation supply sources has also decreased due to
improvements in power plant technologies and reduced forecasted fuel prices.
As a result of these developments, the rates under virtually all of the
Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources. These agreements have been entered into pursuant to the requirements
of the federal Public Utility Regulatory Policies Act and state regulatory
directives. The Company and its affiliates have initiated lawful actions
which are intended to substantially reduce these above market payments. In
addition, the Company and its affiliates intend to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing. The
Company and its affiliates are also attempting to renegotiate, and in some
cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the PaPUC and the New
Jersey Board of Public Utilities (NJBPU), there can be no assurance that the
Company and its affiliates will continue to be able to recover these costs
throughout the term of the related agreements. The GPU System currently
estimates that in 1998, when substantially all of the these nonutility
generation projects are scheduled to be in service, above market payments
(benchmarked against the expected cost of electricity produced by a new gas-
fired combined cycle facility) will range from $300 million to $450 million
annually, of which the Company's share will range from $90 million to $120
million annually. Moreover, efforts to lower these costs have led to disputes
before both the PaPUC and the NJBPU, as well as to litigation, and may result
in claims against the Company and its affiliates for substantial damages.
There can be no assurance as to the outcome of these matters.
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, decommission or clean up waste disposal and other sites currently
or formerly used by it, including formerly owned manufactured gas plants and
mine refuse piles and generating facilities, 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.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of
1990, the Company expects to spend up to $177 million for air pollution
control equipment by the year 2000. In developing its least-cost plan to
comply with the Clean Air Act, the Company will continue to evaluate major
capital investments compared to participation in the emission allowance market
and the use of low-sulfur fuel or retirement of facilities. In September
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1994, the Ozone Transport Commission (OTC), consisting of representatives of
12 northeast states (including New Jersey and Pennsylvania) and the District
of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Company expects that the U.S.
Environmental Protection Agency (EPA) will approve the proposal, and that as a
result, the Company will spend an estimated $50 million, beginning in 1997, to
meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Company and its affiliates
are unable to determine what, if any, additional costs will be incurred.
The Company has been notified by the EPA and state environmental
authorities 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 3 hazardous and/or toxic waste sites. In
addition, the Company has been requested to voluntarily participate in the
remediation or 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 Company has also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
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.
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.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement
Programs (VERP) to certain employees. The enhanced retirement programs were
part of a corporate realignment undertaken in 1994. Approximately 82% of
eligible GPU System employees accepted the retirement programs, resulting in a
pre-tax charge to earnings of $127 million, of which the Company's share is
$45 million. These charges are included as Other Operation and Maintenance on
the income statement.
The Company's construction programs, for which substantial commitments
have been incurred and which extend over several years, contemplate
expenditures of $144 million during 1995. As a consequence of reliability,
licensing, environmental and other requirements, 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 such costs through the
ratemaking process, but recognizes that recovery is not assured.
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The Company has entered into long-term contracts with nonaffiliated
mining companies for the purchase of coal for certain generating stations in
which it has ownership interests. The contracts, which expire between 1995
and the end of the expected service lives of the generating stations, require
the purchase of either fixed or minimum amounts of the stations' coal
requirements. The price of the coal under the contracts is based on
adjustments of indexed cost components. One contract also includes a
provision for the payment of environmental and postretirement benefits. The
Company's share of the cost of coal purchased under these agreements is
expected to aggregate $50 million for 1995.
At the request of the PaPUC, the Company, as well as the other
Pennsylvania utilities, has supplied the PaPUC with proposals for the
establishment of a nuclear performance standard. The Company expects the
PaPUC to adopt a generic nuclear performance standard as a part of its energy
cost rate (ECR) clause in 1995.
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 employees
alleging unlawful employment practices. It is not expected that the outcome
of these types of matters would have a material effect on the Company's
financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The consolidated financial statements include the accounts of the
Company and its subsidiaries. Certain reclassifications of prior years' data
have been made to conform with current presentation. The Company's accounting
records are maintained in accordance with the Uniform System of Accounts
prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by
the PaPUC.
REVENUES
The Company recognizes electric operating revenues for services rendered
(including an estimate of unbilled revenues) to the end of the respective
accounting period.
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
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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 which, on an aggregate composite basis,
resulted in annual rates of 2.49%, 2.74% and 2.86% for the years 1994, 1993
and 1992, 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 pre-tax 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 7.19%, 4.91% and 4.15% for the years 1994, 1993 and 1992,
respectively.
AMORTIZATION POLICIES
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, 1994 amounted to $5 million and is primarily reflected in
Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants
will contribute annually, based on an assessment computed on prior enrichment
purchases, over a 15-year period. The Company made its initial payment to
this fund in 1993, and is recovering the remaining amounts through its fuel
clause. At December 31, 1994, $6 million is recorded on the balance sheet in
Deferred Debits and Other Assets - Other.
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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 TMI-1 in accordance with the Nuclear Waste Policy Act of 1982.
The Company entered into a contract in 1983 with the DOE for the disposal of
spent nuclear fuel. The total liability under this contract, including
interest, at December 31, 1994, all of which relates to spent nuclear fuel
from nuclear generation through April 1983, amounted to $10 million, and is
reflected in Deferred Credits and Other Liabilities - Other. The rates
presently charged to customers provide for the collection of these costs, plus
interest, over a remaining period of 3 years.
The Company is collecting one mill per kilowatt-hour from its customers
for spent nuclear fuel disposal costs resulting from nuclear generation
subsequent to April 1983. This amount is remitted quarterly to the DOE.
INCOME TAXES
The GPU System companies file a consolidated federal income tax return.
All participants are jointly and severally liable for the full amount of any
tax, including penalties and interest, which 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 liberalized
depreciation methods, deferred energy costs and decommissioning funds, 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 amounts of assets and
liabilities recognized for financial reporting purposes and the amounts
recognized for tax purposes.
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STATEMENTS OF CASH FLOWS
For the purpose of the consolidated 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, 1994, the Company had $111 million of short-term notes
outstanding, of which $27 million was commercial paper and the remainder was
issued under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $528 million of credit
facilities, which includes a Revolving Credit Agreement (Credit Agreement)
with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total
borrowings outstanding at any time and subject to various covenants and
acceleration under certain conditions. The Credit Agreement borrowing rates
and facility fee are dependent on the long-term debt ratings of the Company
and its affiliates.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
December 31, 1994 and 1993, are as follows:
(In Millions)
Carrying Fair
Amount Value
December 31, 1994:
Preferred Securities
of subsidiary $ 105 $ 101
Long-term debt 616 577
December 31, 1993:
Long-term debt $ 524 $ 551
The fair values of the Company's long-term debt and preferred securities
of subsidiary 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 and credit qualities.
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
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Pennsylvania Electric Company and Subsidiary Companies
increase in the deferred tax assets of $2 million and an increase in the
deferred tax liabilities of $16 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.
As of December 31, 1994 and 1993, the balance sheet reflected $228 million and
$234 million, respectively, of income taxes recoverable through future rates,
(related to liberalized depreciation), and a regulatory liability for income
taxes refundable through future rates of $36 million and $39 million,
respectively, (related to unamortized ITC), substantially due to the
recognition of amounts not previously recorded.
A summary of the components of deferred taxes as of December 31, 1994
and 1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993
Current: Current:
Unbilled revenue $ 3 $ 1
Other - - Deferred energy $ 4 $ 8
Total $ 3 $ 1 Total $ 4 $ 8
Noncurrent: Noncurrent:
Unamortized ITC $ 36 $ 39 Liberalized
Decommissioning 35 11 depreciation:
Contribution in aid previously flowed
of construction 3 3 through $ 131 $ 134
Other 40 12 future revenue
Total $114 $ 65 requirements 97 100
Subtotal 228 234
Liberalized
depreciation 217 205
Other 9 16
Total $ 454 $ 455
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)
1994 1993 1992
Net income $ 32 $ 96 $ 99
Income tax expense 11 69 71
Book income subject to tax $ 43 $165 $170
Federal statutory rate 35% 35% 34%
State tax, net of federal benefit 1 7 7
Other (10) - -
Effective income tax rate 26% 42% 41%
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Pennsylvania Electric Company and Subsidiary Companies
Federal and state income tax expense is comprised of the following:
(In Millions)
1994 1993 1992
Provisions for taxes currently payable $ 61 $ 51 $ 60
Deferred income taxes:
Liberalized depreciation 12 8 7
Deferral of energy costs (3) 11 (1)
Accretion income 5 - 1
Decommissioning (24) - -
VERP (21) - -
Other (15) 3 7
Deferred income taxes, net (46) 22 14
Amortization of ITC, net (4) (4) (3)
Income tax expense $ 11 $ 69 $ 71
In 1994, the GPU System and the Internal Revenue Service (IRS) reached
an agreement to settle the claim for 1986 that TMI-2 has been retired for tax
purposes. The Company and its affiliates have received net refunds totaling
$17 million, of which the Company's share is $4 million, which have been
credited to their customers. Also in 1994, the GPU System received net
interest from the IRS totaling $46 million, of which the Company's share is
$11.5 million, (before income taxes), associated with the refund settlement,
which was credited to income. The IRS has completed its examinations of the
GPU System's federal income tax returns through 1989. The years 1990 through
1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses
consisted of the following:
(In Millions)
1994 1993 1992
Maintenance $ 80 $ 81 $ 70
Other taxes:
Pennsylvania state gross receipts $ 38 $ 36 $ 35
Real estate and personal property 8 8 8
Capital stock 9 9 10
Other 11 9 8
Total $ 66 $ 62 $ 61
For the years 1994, 1993 and 1992, the cost to the Company of services
rendered to it by GPUSC amounted to approximately $40 million, $37 million and
$35 million, respectively, of which approximately $31 million, $25 million and
$24 million, respectively, were charged to income. For the years 1994, 1993
and 1992, the cost to the Company of services rendered to it by GPUN amounted
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Pennsylvania Electric Company and Subsidiary Companies
to approximately $40 million, $46 million and $40 million, respectively, of
which approximately $33 million, $38 million and $31 million, respectively,
were charged to income.
7. EMPLOYEE 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)
1994 1993 1992
Service cost-benefits earned during the period $ 10.2 $ 8.0 $ 6.9
Interest cost on projected benefit obligation 30.6 29.9 29.5
Less: Expected return on plan assets (32.4) (30.4) (28.9)
Amortization .5 0.1 -
Net periodic pension cost $ 8.9 $ 7.6 $ 7.5
The above 1994 amounts do not include a pre-tax charge to earnings of
$33 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992
were gains of $4.2 million, $46.1 million and $16.9 million, respectively.
The funded status of the plans and related assumptions at December 31,
1994 and 1993 were as follows:
(In Millions)
1994 1993
Accumulated benefit obligation (ABO):
Vested benefits $ 358.0 $ 315.8
Nonvested benefits 38.6 40.5
Total ABO 396.6 356.3
Effect of future compensation levels 57.0 63.6
Projected benefit obligation (PBO) $ 453.6 $ 419.9
PBO $( 453.6) $( 419.9)
Plan assets at fair value 401.3 402.9
PBO in excess of plan assets (52.3) (17.0)
Less: Unrecognized net loss 27.3 10.7
Unrecognized prior service cost 1.8 1.7
Unrecognized net transition obligation 3.5 4.0
Accrued pension liability $ (19.7) $ (.6)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
Annual increase in compensation levels 6.0 5.0
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Pennsylvania Electric Company and Subsidiary Companies
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the PBO
as of December 31, 1994. Also, in 1994, the PBO increased by $37 million as a
result of the VERP. 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 loss 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
and the unrecognized net transition obligation arising out of the adoption of
Statement of Financial Accounting Standards No. 87, "Employers' Accounting for
Pensions," are being amortized as a charge or 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 1994, 1993 and 1992 were $3.0
million, $3.0 million and $2.8 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, the annual premium costs associated with providing these benefits
totaled approximately $6.2 million.
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 1994 and 1993 follows:
(In Millions)
1994 1993
Service cost-benefits attributed to service
during the period $ 4.6 $ 3.6
Interest cost on the accumulated postretirement
benefit obligation 13.4 12.2
Expected return on plan assets (2.3) (1.2)
Amortization of transition obligation 6.5 6.5
Other amortization, net .8 -
Net periodic postretirement benefit cost 23.0 21.1
Net write-off (deferral) 9.0 (10.1)
Total postretirement benefit cost $32.0 $ 11.0
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<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
The above 1994 amounts do not include a pre-tax charge to earnings of
$12 million relating to the VERP.
The actual return on the plans' assets for the years 1994 and 1993 was a
gain of $.8 million and $1.3 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as
follows:
(In Millions)
1994 1993
Accumulated Postretirement Benefit Obligation:
Retirees $ 111.3 $ 83.8
Fully eligible active plan participants 21.4 23.0
Other active plan participants 67.2 75.7
Total accumulated postretirement
benefit obligation (APBO) $ 199.9 $ 182.5
APBO $(199.9) $(182.5)
Plan assets at fair value 53.1 18.6
APBO in excess of plan assets (146.8) (163.9)
Less: Unrecognized net loss 15.9 25.3
Unrecognized prior service cost 2.5 2.9
Unrecognized transition obligation 112.4 123.7
Accrued postretirement benefit liability $ (16.0) $ (12.0)
Principal actuarial assumptions (%):
Annual long-term rate of return on plan assets 8.5 8.5
Discount rate 8.0 7.5
The Company intends to continue funding amounts for postretirement
benefits with an independent trustee, as deemed appropriate from time to time.
The plan assets include equities and fixed income securities.
In 1994, changes in assumptions, primarily the increase in the discount
rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the
APBO as of December 31, 1994. Also, in 1994, the APBO increased by $13
million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible
for Medicare, then 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 31, 1995. The effect of a 1% annual increase in these
assumed cost trend rates would increase the accumulated postretirement benefit
obligation by approximately $19 million as of December 31, 1994 and the
aggregate of the service and interest cost components of net periodic
postretirement health-care cost by approximately $2 million.
F-193
<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
In 1993, the Company began deferring its FAS 106 incremental expense in
accordance with the PaPUC's generic policy statement permitting the deferral
of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the
PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of
such costs, stating that FAS 106 expense incurred after January 1, 1993 (the
effective date for the accounting change) but prior to its next base rate case
could not be deferred for future recovery, and that to assure such future
recovery constituted retroactive ratemaking. As a result of the Court's
decision, in the second quarter of 1994, the Company determined that deferred
incremental FAS 106 expense was not likely to be recovered and wrote off $14.6
million deferred since January 1993. In addition, $4 million of the Company's
unrecognized transition obligation resulting from employees who elected to
participate in the VERP was also written off during the second quarter of
1994. During the remainder of 1994, the Company continued to expense FAS 106
costs ($4.2 million) and anticipates annual charges to income of approximately
$9 million, beginning in 1995, which represents continued amortization of the
transition obligation along with current accruals of FAS 106 expense for
active employees.
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, 1994:
Balance (In Millions)
% Accumulated
Station Ownership Investment Depreciation
Homer City 50 $441.2 $158.7
Three Mile Island Unit 1 25 206.5 71.6
Seneca 20 16.4 4.5
9. LEASES
The Company's capital leases consist primarily of leases for nuclear
fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $16
million and $21 million, respectively (net of amortization of $15 million and
$8 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 $125 million of nuclear fuel
costs may be outstanding at any one time for TMI-1. It is contemplated that
when consumed, portions of the presently leased material will be replaced by
additional leased material. The Company and its affiliates are responsible
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<PAGE>
Pennsylvania Electric Company and Subsidiary Companies
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, 1994, 1993 and 1992 these
amounts were $7 million, $7 million and $8 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.
F-195
<PAGE>
<TABLE>
Pennsylvania Electric Company and Subsidiary Companies
PENNSYLVANIA ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1994
Allowance for doubtful
accounts $1,329 $3,133 $1,486(a) $4,766(b) $1,182
Allowance for inventory
obsolescence - - - - -
Year ended December 31, 1993
Allowance for doubtful
accounts $1,224 $3,234 $1,337(a) $4,466(b) $1,329
Allowance for inventory
obsolescence 365 - - 365(c) -
Year ended December 31, 1992
Allowance for doubtful
accounts $1,836 $3,018 $1,436(a) $5,066(b) $1,224
Allowance for inventory
obsolescence 3,726 - - 3,361(c) 365
<FN>
(a) Recovery of accounts previously written off.
(b) Accounts receivable written off.
(c) Inventory written off.
</FN>
F-196</TABLE>
<PAGE>
Exhibits to be Filed by EDGAR
3-A GPUSC By-Laws, as amended.
10-A General Public Utilities Corporation Restricted Stock Plan for
Outside Directors
10-B Retirement Plan for Outside Directors of General Public Utilities
Corporation
10-C Deferred Remuneration Plan for Outside Directors of General Public
Utilities Corporation
12 Statements Showing Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
A - Jersey Central Power & Light Company
B - Metropolitan Edison Company
C - Pennsylvania Electric Company
21 Subsidiaries of the Registrant
A - Metropolitan Edison Company
B - Pennsylvania Electric Company
23 Consent of Independent Accountants
A - General Public Utilities Corporation
B - Jersey Central Power & Light Company
C - Metropolitan Edison Company
D - Pennsylvania Electric Company
27 Financial Data Schedule
A - General Public Utilities Corporation
B - Jersey Central Power & Light Company
C - Metropolitan Edison Company
D - Pennsylvania Electric Company
<PAGE>
Exhibit 3-A
GPU SERVICE CORPORATION
_________________
By-Laws
(As Amended April 27, 1994)
_________________<PAGE>
(As Amended April 27, 1994)
GPU SERVICE CORPORATION
BY-LAWS
Offices
1. The principal office of the Corporation shall be in Parsippany,
New Jersey. The Corporation may also have offices at such other places as the
Board of Directors may from time to time designate or the business of the
Corporation may require.
Seal
2. The corporate seal shall have inscribed thereon the name of the
Corporation, the year of its organization, and the words "Corporate Seal" and
"Pennsylvania". If authorized by the Board of Directors, the corporate seal
may be affixed to any certificates of stock, bonds, debentures, notes or other
engraved, lithographed or printed instruments, by engraving, lithographing or
printing thereon such seal or a facsimile thereof, and such seal or facsimile
thereof so engraved, lithographed or printed thereon shall have the same force
and effect, for all purposes, as if such corporate seal had been affixed
thereto by indentation.
Stockholders' Meetings
3. All meetings of stockholders shall be held at the principal office
of the Corporation or at such other place as shall be stated in the notice of
the meeting. Such meetings shall be presided over by the chief executive
officer of the Corporation or, in his absence, by such other officer as shall
have been designated for the purpose by the Board of Directors, except when by
statute the election of a presiding officer is required.
4. Annual meetings of stockholders shall be held during the month of
May in each year on such day and at such time as shall be determined by the
Board of Directors and specified in the notice of the meeting. At the annual
meeting, the stockholders entitled to vote shall elect by ballot a Board of
Directors and transact such other business as may properly be brought before
the meeting. Prior to any meeting of stockholders at which an election of
directors is to be held, the Board of Directors shall appoint one judge of
election to serve at such meeting. If there be a failure to appoint a judge
or if such judge be absent or refuse to act or if his office becomes vacant,
the stockholders present at the meeting, by a per capita vote, shall choose
temporary judges of the number required. No director or officer of the
Corporation shall be eligible to appointment or election as a judge.
5. Except as otherwise provided by law or by the Articles of
Incorporation, as amended, the holders of a majority of the shares of stock of
the Corporation issued and outstanding and entitled to vote, present in person
or by proxy, shall be requisite for, and shall constitute a quorum at, any
meeting of the stockholders. If, however, the holders of a majority of such
shares of stock shall not be present or represented by proxy at any such
meeting, the stockholders entitled to vote thereat, present in person or by
proxy, shall have power, by vote of the holders of a majority of the shares of
1
<PAGE>
capital stock present or represented at the meeting, to adjourn the meeting
from time to time without notice other than announcement at the meeting, until
the holders of the amount of stock requisite to constitute a quorum, as
aforesaid, shall be present in person or by proxy. At any adjourned meeting
at which such quorum shall be present, in person or by proxy, any business may
be transacted which might have been transacted at the meeting as originally
noticed.
2
<PAGE>
6. At each meeting of stockholders each holder of record of shares of
capital stock then entitled to vote shall be entitled to vote in person, or by
proxy appointed by instrument executed in writing by such stockholder or by
his duly authorized attorney; but no proxy shall be valid after the expiration
of eleven months from the date of its execution unless the stockholder
executing it shall have specified therein the length of time it is to continue
in force, which shall be for some specified period. At all elections of
directors each holder of record of shares of capital stock then entitled to
vote, shall be entitled to as many votes as shall equal the number of votes
which (except for such provision) he would be entitled to cast for the
election of directors with respect to his shares of stock multiplied by the
number of directors to be elected, and he may cast all such votes for a single
director or may distribute them among the number to be voted for, or any two
or more of them, as he may see fit. Except as otherwise provided by law or by
the Articles of Incorporation, as amended, each holder of record of shares of
capital stock entitled to vote at any meeting of stockholders shall be
entitled to one vote for every share of capital stock standing in his name on
the books of the Corporation. Shares of capital stock of the Corporation,
belonging to the Corporation or to a corporation controlled by the Corporation
through stock ownership or through majority representation on the board of
directors thereof, shall not be voted. All elections shall be determined by a
plurality vote, and, except as otherwise provided by law or by the Articles of
Incorporation, as amended, all other matters shall be determined by a vote of
the holders of a majority of the shares of the capital stock present or
represented at a meeting and voting on such questions.
7. A complete list of the stockholders entitled to vote at any
meeting of stockholders, arranged in alphabetical order, with the residence of
each, and the number of shares held by each, shall be prepared by the
Secretary and filed in the principal office of the Corporation at least
fifteen days before the meeting, and shall be open to the examination of any
stockholder at all times prior to such meeting, during the usual hours for
business, and shall be available at the time and place of such meeting and
open to the examination of any stockholder.
8. Special meetings of the stockholders for any purpose or purposes,
unless otherwise prescribed by law, may be called by the Chairman or by the
President, and shall be called by the chief executive officer or Secretary at
the request in writing of any three members of the Board of Directors, or at
the request in writing of holders of record of ten percent of the shares of
capital stock of the Corporation issued and outstanding. Business transacted
at all special meetings of the stockholders shall be confined to the purposes
stated in the call.
9. (a) Notice of every meeting of stockholders, setting forth the
time and the place and briefly the purpose or purposes thereof, shall be
mailed, not less than ten nor more than fifty days prior to such meeting, to
each stockholder of record (at his address appearing on the stock books of the
Corporation, unless he shall have filed with the Secretary of the Corporation
a written request that notices intended for him be mailed to some other
address, in which case it shall be mailed to the address designated in such
request) as of a date fixed by the Board of Directors pursuant to Section 41
of the By-Laws. Except as otherwise provided by law, by the Articles of
Incorporation, as amended, or by the By-Laws, items of business, in addition
to those specified in the notice of meeting, may be transacted at the annual
meeting.
3
<PAGE>
(b) Whenever by any provision of law, the vote of stockholders
at a meeting thereof is required or permitted to be taken in connection with
any corporate action, the meeting and vote of stockholders may be dispensed
with, if all the stockholders who would have been entitled to vote upon the
action if such meeting were held, shall consent in writing to such corporate
action being taken, and all such consents shall be filed with the Secretary of
the Corporation. However, this section shall not be construed to alter or
modify any provision of law or of the Articles of Incorporation under which
4
<PAGE>
the written consent of the holders of less than all outstanding shares is
sufficient for corporate action.
Directors
10. The business and affairs of the Corporation shall be managed by
its Board of Directors, which shall consist of not less than five nor more
than nine directors as shall be fixed from time to time by a resolution
adopted by a majority of the entire Board of Directors; provided, however,
that no decrease in the number of directors constituting the entire Board of
Directors shall shorten the term of any incumbent director. Each director
shall be at least twenty-one years of age. Directors need not be stockholders
of the Corporation. Directors shall be elected at the annual meeting of
stockholders, or, if any such election shall not be held, at a stockholders'
meeting called and held in accordance with the provisions of the Business
Corporation Law of the Commonwealth of Pennsylvania. Each director shall
serve until the next annual meeting of stockholders and thereafter until his
successor shall have been elected and shall qualify.
11. In addition to the powers and authority by the By-Laws expressly
conferred upon it, the Board of Directors may exercise all such powers of the
Corporation and do all such lawful acts and things as are not by law or by the
Articles of Incorporation, as amended, or by the By-Laws directed or required
to be exercised or done by the stockholders.
12. Unless otherwise required by law, in the absence of fraud no
contract or transaction between the Corporation and one or more of its
directors or officers, or between the Corporation and any corporation,
partnership, association, or other organization in which one or more of its
directors or officers are directors or officers, or have a financial interest,
shall be void or voidable solely for such reason, or solely because the
director or officer is present at or participates in the meeting of the Board
of Directors which authorize the contract or transaction, or solely because
his votes are counted for such purpose if:
(a) The material facts as to his interest and as to the contract
or transaction are disclosed or are known to the Board of
Directors, and the Board in good faith authorizes the contract or
transaction by a vote sufficient for such purposes without
counting the vote of the interested director or directors; or
(b) The material facts as to his interest and as to the contract
or transaction are disclosed or known to the stockholders entitled
to vote thereon, and the contract or transaction is specifically
approved in good faith by vote of the stockholders; or
(c) The contract or transaction is fair as to the Corporation as
of the time it is authorized, approved or ratified by the Board of
Directors or the stockholders.
No director or officer shall be liable to account to the Corporation for
any profit realized by him from or through any such contract or transaction of
the Corporation by reason of his interest as aforesaid in such contract or
transaction if such contract or transaction shall be authorized, approved or
ratified as aforesaid.
5
<PAGE>
No contract or other transaction between the Corporation and any of its
affiliates shall in any case be void or voidable or otherwise affected because
of the fact that directors or officers of the Corporation are directors or
officers of such affiliate, nor shall any such director or officer, because of
such relation, be deemed interested in such contract or other transaction
under any of the provisions of this Section 12, nor shall any such director be
liable to account because of such relation. For the purpose of this Section
6
<PAGE>
12, the term "affiliate" shall mean any corporation which is an "affiliate" of
the Corporation within the meaning of the Public Utility Holding Company Act
of 1935, as said Act shall at the time be in effect.
Nothing herein shall create liability in any of the events described in
this Section 12 or prevent the authorization, ratification or approval, in any
other manner provided by law, of any contract or transaction described in this
Section 12.
Meetings of the Board of Directors
13. The first meeting of the Board of Directors, for the purpose of
organization, the election of officers, and the transaction of any other
business which may come before the meeting, shall be held on call of the
Chairman within one week after the annual meeting of stockholders. If the
Chairman shall fail to call such meeting, it may be called by the President or
by any director. Notice of such meeting shall be given in the manner
prescribed for Special Meetings of the Board of Directors.
14. Regular meetings of the Board of Directors may be held without
notice except for the purpose of taking action on matters as to which notice
is in the By-Laws required to be given, at such time and place as shall from
time to time be designated by the Board, but in any event at intervals of not
more than three months. Special meetings of the Board of Directors may be
called by the Chairman or by the President or in the absence or disability of
the Chairman and the President, by a Vice President, or by any two directors,
and may be held at the time and place designated in the call and notice of the
meeting.
15. Except as otherwise provided by the By-Laws, any item or business
may be transacted at any meeting of the Board of Directors, whether or not
such item of business shall have been specified in the notice of meeting.
Where notice of any meeting of the Board of Directors is required to be given
by the By-Laws, the Secretary or other officer performing his duties shall
give notice either personally or by telephone or telegraph at least
twenty-four hours before the meeting, or by mail at least three days before
the meeting. Meetings may be held at any time and place without notice if all
the directors are present or if those not present waive notice in writing
either before or after the meeting.
16. At all meetings of the Board of Directors a majority of the
directors in office shall be requisite for, and shall constitute, a quorum for
the transaction of business, and the act of a majority of the directors
present at any meeting at which there is a quorum shall be the act of the
Board of Directors, except as may be otherwise specifically provided by law or
by the Articles of Incorporation, as amended, or by the By-Laws.
17. Any regular or special meeting may be adjourned to any time or
place by a majority of the directors present at the meeting, whether or not a
quorum shall be present at such meeting, and no notice of the adjourned
meeting shall be required other than announcement at the meeting.
Committees
18. The Board of Directors may, by the vote of a majority of the
directors in office, create an Executive Committee, consisting of two or more
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members, of whom one shall be the chief executive officer of the Corporation.
The other members of the Executive Committee shall be designated by the Board
of Directors from their number, shall hold office for such period as the Board
of Directors shall determine and may be removed at any time by the Board of
Directors. When a member of the Executive Committee ceases to be a director,
he shall cease to be a member of the Executive Committee. The Executive
Committee shall have all the powers specifically granted to it by the By-Laws
and, between meetings of the Board of Directors, may also exercise all the
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powers of the Board of Directors except such powers as the Board of Directors
may exercise by virtue of Section 11 of the By-Laws. The Executive Committee
shall have no power to revoke any action taken by the Board of Directors, and
shall be subject to any restriction imposed by law, by the By-Laws, or by the
Board of Directors.
19. The Executive Committee shall cause to be kept regular minutes of
its proceedings, which may be transcribed in the regular minute book of the
Corporation, and all such proceedings shall be reported to the Board of
Directors at its next succeeding meeting, and the action of the Executive
Committee shall be subject to revision or alteration by the Board of
Directors, provided that no rights which, in the absence of such revision or
alteration, third persons would have had shall be affected by such revision or
alteration. A majority of the Executive Committee shall constitute a quorum
at any meeting. The Board of Directors may by vote of a majority of the total
number of directors provided for in Section 10 of the By-Laws fill any
vacancies in the Executive Committee. The Executive Committee shall designate
one of its number as Chairman of the Executive Committee and may, from time to
time, prescribe rules and regulations for the calling and conduct of meetings
of the Committee, and other matters relating to its procedure and the exercise
of its powers.
20. From time to time the Board of Directors may appoint any other
committee or committees for any purpose or purposes, which committee or
committees shall have such powers and such tenure of office as shall be
specified in the resolution of appointment. The chief executive officer of
the Corporation shall be a member ex officio of all committees of the Board.
Compensation and Reimbursement of Directors
and Members of the Executive Committee
21. Directors, other than salaried officers of the Corporation or its
affiliates, shall receive compensation and benefits for their services as
directors, at such rate or under such conditions as shall be fixed from time
to time by the Board, and all directors shall be reimbursed for their
reasonable expenses, if any, of attendance at each regular or special meeting
of the Board of Directors.
22. Directors, other than salaried officers of the Corporation or its
affiliates, who are members of any committee of the Board shall receive
compensation for their services as such members as shall be fixed from time to
time by the Board, and shall be reimbursed for their reasonable expenses, if
any, in attending meetings of the Executive Committee or such other Committees
of the Board and of otherwise performing their duties as members of such
Committees.
Officers
23. The officers of the Corporation shall be chosen by vote of a
majority of the directors in office and shall be a President, one or more Vice
Presidents, a Secretary and a Treasurer, and may include a Chairman, a
President - Fossil Generation, a Comptroller, one or more Assistant
Secretaries, one or more Assistant Treasurers, and one or more Assistant
Comptrollers. If a Chairman shall be chosen, the Board of Directors shall
designate either the Chairman or the President as chief executive officer of
the Corporation. If a Chairman shall not be chosen, the President shall be
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the chief executive officer of the Corporation. The Chairman and a President
who is designated chief executive officer of the Corporation shall be chosen
from among the directors. A President who is not chief executive officer of
the Corporation and none of the other officers need be a director. If a
Comptroller shall not be chosen, the Board of Directors shall designate
another officer as principal accounting officer of the Corporation who in his
capacity as such shall have the duties and responsibilities set forth in
Section 33 hereof. Any two offices may be occupied and the duties thereof may
be performed by one person, but no officer shall execute, acknowledge or
verify any instrument in more than one capacity.
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24. The salaries and other compensation of the officers of the
Corporation shall be determined from time to time by the chief executive
officer, subject, in the case of those officers who are also officers of
General Public Utilities Corporation, to the concurrence of the Board of
Directors of that Corporation.
25. The Board of Directors may appoint such officers and such
representatives or agents as shall be deemed necessary, who shall hold office
for such terms, exercise such powers, and perform such duties as shall be
determined from time to time by the Board of Directors.
26. The salary or other compensation of all employees other than
officers of the Corporation shall be fixed by the chief executive officer of
the Corporation or by such other officer as shall be designated for that
purpose by the Board of Directors.
27. The officers of the Corporation shall hold office until the first
meeting of the Board of Directors after the next succeeding annual meeting of
stockholders and until their respective successors are chosen and qualify.
Any officer elected pursuant to Section 23 of the By-Laws may be removed at
any time, with or without cause, by the vote of a majority of the directors in
office. Any other officer and any representative, employee or agent of the
Corporation may be removed at any time, with or without cause, by action of
the Board of Directors, or, in the absence of action by the Board of
Directors, by the Executive Committee, or the chief executive officer of the
Corporation, or such other officer as shall have been designated for that
purpose by the chief executive officer of the Corporation.
The Chairman
28. (a) If a Chairman shall be chosen by the Board of Directors, he
shall preside at all meetings of the Board at which he shall be present.
(b) If a Chairman shall be chosen by the Board of Directors and
if he shall be designated by the Board as chief executive officer of the
Corporation,
(i) he shall have supervision, direction and control of the
conduct of the business of the Corporation, subject,
however, to the control of the Board of Directors and the
Executive Committee, if there be one;
(ii) he may sign in the name and on behalf of the
Corporation any and all contracts, agreements or other
instruments pertaining to matters which arise in the
ordinary course of business of the Corporation, and, when
authorized by the Board of Directors or the Executive
Committee, if there be one, may sign in the name and on
behalf of the Corporation any and all contracts, agreements
or other instruments of any nature pertaining to the
business of the Corporation;
(iii) he may, unless otherwise directed by the Board of
Directors pursuant to Section 38 of the By-Laws, attend in
person or by substitute or proxy appointed by him and act
and vote on behalf of the Corporation at all meetings of
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stockholders of any corporation in which the Corporation
holds stock and grant any consent, waiver, or power of
attorney in respect of such stock;
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(iv) he shall, whenever it may in his opinion be necessary
or appropriate, prescribe the duties of officers and
employees of the Corporation whose duties are not otherwise
defined; and
(v) he shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the
By-Laws, or by the Board of Directors.
(c) If a Chairman shall be chosen by the Board of Directors and
if he shall not be designated by the Board as chief executive officer of the
Corporation,
(i) he may sign in the name and on behalf of the Corporation
any and all contracts, agreements or other instruments
pertaining to matters which arise in the ordinary course of
business of the Corporation and, when authorized by the
Board of Directors or the Executive Committee, if there be
one, may sign in the name and on behalf of the Corporation
any and all contracts, agreements or other instruments of
any nature pertaining to the business of the Corporation;
(ii) he shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the
By-Laws, or by the Board of Directors.
The President
29. (a) If a Chairman shall not be chosen by the Board of Directors,
the President shall preside at all meetings of the Board at which he shall be
present.
(b) If the President shall be designated by the Board of
Directors as chief executive officer of the Corporation,
(i) he shall have supervision, direction and control of the
conduct of the business of the Corporation, subject,
however, to the control of the Board of Directors and the
Executive Committee if there be one;
(ii) he may sign in the name and on behalf of the
Corporation any and all contracts, agreements or other
instruments pertaining to matters which arise in the
ordinary course of business of the Corporation, and, when
authorized by the Board of Directors or the Executive
Committee, if there be one, may sign in the name and on
behalf of the Corporation any and all contracts, agreements,
or other instruments of any nature pertaining to the
business of the Corporation;
(iii) he may, unless otherwise directed by the Board of
Directors pursuant to Section 38 of the By-Laws, attend in
person or by substitute or proxy appointed by him and act
and vote on behalf of the Corporation at all meetings of the
stockholders of any corporation in which the Corporation
holds stock and grant any consent, waiver, or power of
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attorney in respect of such stock;
(iv) he shall, whenever it may in his opinion be necessary
or appropriate, prescribe the duties of officers and
employees of the Corporation whose duties are not otherwise
defined; and
(v) he shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the
By-Laws, or by the Board of Directors.
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(c) If the Chairman shall be designated by the Board of
Directors as chief executive officer of the Corporation, the President,
(i) shall be the chief operating officer of the Corporation;
(ii) shall have supervision, direction and control of the
conduct of the business of the Corporation, in the absence
or disability of the Chairman, subject, however, to the
control of the Board of Directors and the Executive
Committee, if there be one;
(iii) may sign in the name and on behalf of the Corporation
any and all contracts, agreements or other instruments
pertaining to matters which arise in the ordinary course of
business of the Corporation, and, when authorized by the
Board of Directors or the Executive Committee, if there be
one, may sign in the name and on behalf of the Corporation
any and all contracts, agreements or other instruments of
any nature pertaining to the business of the Corporation;
(iv) at the request or in the absence or disability of the
Chairman, may, unless otherwise directed by the Board of
Directors pursuant to Section 38 of the By-Laws, attend in
person or by substitute or proxy appointed by him and act
and vote on behalf of the Corporation at all meetings of the
stockholders of any corporation in which the Corporation
holds stock and grant any consent, waiver, or power of
attorney in respect of such stock;
(v) at the request or in the absence or disability of the
Chairman, whenever in his opinion it may be necessary or
appropriate, shall prescribe the duties of officers and
employees of the Corporation whose duties are not otherwise
defined; and
(vi) shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the
By-Laws, or by the Board of Directors.
The President - Fossil Generation
29A. The President - Fossil Generation
(i) shall be the chief operating officer of the Fossil
Generation Division of the Corporation;
(ii) shall have supervision, direction and control of the
conduct of the business of the Fossil Generation Division of the
Corporation, subject, however, to the control of the President, the
Board of Directors and the Executive Committee, if there be one;
(iii) may sign in the name and on behalf of the Corporation
any and all contracts, agreements or other instruments pertaining to
matters which arise in the ordinary course of business of the Fossil
Generation Division of the Corporation, and, when authorized to do so by
the President, the Board of Directors or the Executive Committee, if
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there be one, may sign in the name and on behalf of the Fossil
Generation Division of the Corporation any and all contracts, agreements
or other instruments of any nature pertaining to the business of the
Fossil Generation Division of the Corporation; and
(iv) shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the By-Laws, or
by the Board of Directors.
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Vice President
30. (a) The Vice President shall, in the absence or disability of
the President, if the President has been designated chief executive officer of
the Corporation or if the President is acting pursuant to the provisions of
Subsection 29 (c) (ii) of the By-Laws, have supervision, direction and control
of the conduct of the business of the Corporation, subject, however, to the
control of the Directors and the Executive Committee, if there be one.
(b) He may sign in the name of and on behalf of the Corporation
any and all contracts, agreements or other instruments pertaining to matters
which arise in the ordinary course of business of the Corporation, and, when
authorized by the Board of Directors or the Executive Committee, if there be
one, except in cases where the signing thereof shall be expressly delegated by
the Board of Directors or the Executive Committee to some other officer or
agent of the Corporation.
(c) He may, if the President has been designated chief executive
officer of the Corporation or if the President is acting pursuant to the
provisions of Subsection 29 (c) (ii) of the By-Laws, at the request or in the
absence or disability of the President or in case of the failure of the
President to appoint a substitute or proxy as provided in Subsections 29 (b)
(iii) and 29 (c) (iv) of the By-Laws, unless otherwise directed by the Board
of Directors pursuant to Section 38 of the By-Laws, attend in person or by
substitute or proxy appointed by him and act and vote in behalf of the
Corporation at all meetings of the stockholders of any corporation in which
the Corporation holds stock and grant any consent, waiver or power of attorney
in respect of such stock.
(d) He shall have such other powers and perform such other
duties as may be prescribed from time to time by law, by the By-Laws, or by
the Board of Directors.
(e) If there be more than one Vice President, the Board of
Directors may designate one or more of such Vice Presidents as an Executive
Vice President. The Board of Directors may assign to such Vice Presidents
their respective duties and may, if the President has been designated chief
executive officer of the Corporation or if the President is acting pursuant to
the provisions of Subsection 29 (c) (ii) of the By-Laws, designate the order
in which the respective Vice Presidents shall have supervision, direction and
control of the business of the Corporation in the absence or disability of the
President.
The Secretary
31. (a) The Secretary shall attend all meetings of the Board of
Directors and all meetings of the stockholders and record all votes and the
minutes of all proceedings in books to be kept for that purpose; and he shall
perform like duties for the Executive Committee and any other committees
created by the Board of Directors.
(b) He shall give, or cause to be given, notice of all meetings
of the stockholders, the Board of Directors, or the Executive Committee of
which notice is required to be given by law or by the By-Laws.
(c) He shall have such other powers and perform such other
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duties as may be prescribed from time to time by law, by the By-Laws, or the
Board of Directors.
(d) Any records kept by the Secretary shall be the property of
the Corporation and shall be restored to the Corporation in case of his death,
resignation, retirement or removal from office.
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(e) He shall be the custodian of the seal of the Corporation
and, pursuant to Section 45 of the By-Laws and in other instances where the
execution of documents in behalf of the Corporation is authorized by the
By-Laws or by the Board of Directors, may affix the seal to all instruments
requiring it and attest the ensealing and the execution of such instruments.
(f) He shall have control of the stock ledger, stock certificate
book and all books containing minutes of any meeting of the stockholders,
Board of Directors, or Executive Committee or other committee created by the
Board of Directors, and of all formal records and documents relating to the
corporate affairs of the Corporation.
(g) Any Assistant Secretary or Assistant Secretaries shall
assist the Secretary in the performance of his duties, shall exercise his
powers and duties at his request or in his absence or disability, and shall
exercise such other powers and duties as may be prescribed by the Board of
Directors.
The Treasurer
32. (a) The Treasurer shall be responsible for the safekeeping of
the corporate funds and securities of the Corporation, and shall maintain and
keep in his custody full and accurate accounts of receipts and disbursements
in books belonging to the Corporation, and shall deposit all moneys and other
funds of the Corporation in the name and to the credit of the Corporation, in
such depositories as may be designated by the Board of Directors.
(b) He shall disburse the funds of the Corporation in such
manner as may be ordered by the Board of Directors, taking proper vouchers for
such disbursements.
(c) Pursuant to Section 45 of the By-Laws, he may, when
authorized by the Board of Directors, affix the seal to all instruments
requiring it and shall attest the ensealing and execution of said instruments.
(d) He shall exhibit at all reasonable times his accounts and
records to any director of the Corporation upon application during business
hours at the office of the Corporation where such accounts and records are
kept.
(e) He shall render an account of all his transactions as
Treasurer at all regular meetings of the Board of Directors, or whenever the
Board may require it, and at such other times as may be requested by the Board
or by any director of the Corporation.
(f) If required by the Board of Directors, he shall give the
Corporation a bond, the premium on which shall be paid by the Corporation, in
such form and amount and with such surety or sureties as shall be satisfactory
to the Board, for the faithful performance of the duties of his office, and
for the restoration to the Corporation in case of his death, resignation,
retirement or removal from office, of all books, papers, vouchers, money and
other property of whatever kind in his possession or under his control
belonging to the Corporation.
(g) He shall perform all duties generally incident to the office
of Treasurer, and shall have other powers and duties as from time to time may
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be prescribed by law, by the By-Laws, or by the Board of Directors.
(h) Any Assistant Treasurer or Assistant Treasurers shall assist
the Treasurer in the performance of his duties, shall exercise his powers and
duties at his request or in his absence or disability, and shall exercise such
other powers and duties as may be prescribed by the Board of Directors. If
required by the Board of Directors, any Assistant Treasurer shall give the
Corporation a bond, the premium on which shall be paid by the Corporation,
similar to that which may be required to be given by the Treasurer.
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Comptroller
33. (a) The Comptroller of the Corporation shall be the principal
accounting officer of the Corporation and shall be accountable and report
directly to the Board of Directors. If required by the Board of Directors,
the Comptroller shall give the Corporation a bond, the premium on which shall
be paid by the Corporation in such form and amount and with such surety or
sureties as shall be satisfactory to the Board, for the faithful performance
of the duties of his office.
(b) He shall keep or cause to be kept full and complete books of
account of all operations of the Corporation and of its assets and
liabilities.
(c) He shall have custody of all accounting records of the
Corporation other than the record of receipts and disbursements and those
relating to the deposit or custody of money or securities of the Corporation,
which shall be in the custody of the Treasurer.
(d) He shall exhibit at all reasonable times his books of
account and records to any director of the Corporation upon application during
business hours at the office of the Corporation where such books of account
and records are kept.
(e) He shall render reports of the operations and business and
of the condition of the finances of the Corporation at regular meetings of the
Board of Directors, and at such other times as he may be requested by the
Board or by any director of the Corporation, and shall render a full financial
report at the annual meeting of the stockholders, if called upon to do so.
(f) He shall receive and keep in his custody an original copy of
each written contract made by or on behalf of the Corporation.
(g) He shall receive periodic reports from the Treasurer of the
Corporation of all receipts and disbursements, and shall see that correct
vouchers are taken for all disbursements for any purpose.
(h) He shall perform all duties generally incident to the office
of Comptroller, and shall have such other powers and duties as from time to
time may be prescribed by law, by the By-Laws, or by the Board of Directors.
(i) Any Assistant Comptroller or Assistant Comptrollers shall
assist the Comptroller in the performance of his duties, shall exercise his
powers and duties at his request or in his absence or disability and shall
exercise such other powers and duties as may be conferred or required by the
Board of Directors. If required by the Board of Directors, any Assistant
Comptroller shall give the Corporation a bond, the premium on which shall be
paid by the Corporation, similar to that which may be required to be given by
the Comptroller.
Vacancies
34. If the office of any director becomes vacant by reason of death,
resignation, retirement, disqualification, or otherwise, the remaining
directors, by the vote of a majority of those then in office, at a meeting,
the notice of which shall have specified the filling of such vacancy as one of
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its purposes, may choose a successor, who shall hold office for the unexpired
term in respect of which such vacancy occurs. If the office of any officer of
the Corporation shall become vacant for any reason, the Board of Directors, at
a meeting, the notice of which shall have specified the filling of such
vacancy as one of its purposes, may choose a successor who shall hold office
for the unexpired term in respect of which such vacancy occurred. Pending
action by the Board of Directors at such meeting, the Board of Directors or
the Executive Committee may choose a successor temporarily to serve as an
officer of the Corporation.
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Resignations
35. Any officer or any director of the Corporation may resign at any
time, such resignation to be made in writing and transmitted to the Secretary.
Such resignation shall take effect from the time of its acceptance, unless
some time be fixed in the resignation, and then from that time. Nothing
herein shall be deemed to relieve any officer from liability for breach of any
contract of employment resulting from any such resignation.
Duties of Officers May be Delegated
36. In case of the absence or disability of any officer of the
Corporation, or for any other reason the Board of Directors may deem
sufficient, the Board, by vote of a majority of the total number of directors
provided for in Section 10 of the By-Laws may, notwithstanding any other
provisions of the By-Laws, delegate or assign, for the time being, the powers
or duties, or any of them, of such officer to any other officer or to any
director.
Indemnification of Directors, Officers and Employees
37. (a) A director shall not be personally liable for monetary
damages as such for any action taken, or any failure to take any action, on or
after January 27, 1987 unless the director has breached or failed to perform
the duties of his office under Section 8363 of the Pennsylvania Directors
Liability Act, and the breach or failure to perform constitutes self-dealing,
willful misconduct or recklessness. The provisions of this subsection (a)
shall not apply to the responsibility or liability of a director pursuant to
any criminal statute, or the liability of a director for the payment of taxes
pursuant to local, state or Federal law.
(b) The Corporation shall indemnify any person who was or is a
party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative
or investigative, whether formal or informal, and whether brought by or in the
right of the Corporation or otherwise, by reason of the fact that he was a
director, officer or employee of the Corporation (and may indemnify any person
who was an agent of the Corporation), or a person serving at the request of
the Corporation as a director, officer, partner, fiduciary or trustee of
another corporation, partnership, joint venture, trust, employee benefit plan
or other enterprise, to the fullest extent permitted by law, including without
limitation indemnification against expenses (including attorneys' fees and
disbursements), damages, punitive damages, judgments, penalties, fines and
amounts paid in settlement actually and reasonably incurred by such person in
connection with such proceeding unless the act or failure to act giving rise
to the claim for indemnification is finally determined by a court to have
constituted willful misconduct or recklessness.
(c) The Corporation shall pay the expenses (including attorneys'
fees and disbursements) actually and reasonably incurred in defending a civil
or criminal action, suit or proceeding on behalf of any person entitled to
indemnification under subsection (b) in advance of the final disposition of
such proceeding upon receipt of an undertaking by or on behalf of such person
to repay such amount if it shall ultimately be determined that he is not
entitled to be indemnified by the Corporation, and may pay such expenses in
advance on behalf of any agent on receipt of a similar undertaking. The
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financial ability of such person to make such repayment shall not be a
prerequisite to the making of an advance.
(d) For purposes of this Section:
(i) the Corporation shall be deemed to have requested an
officer, director, employee or agent to serve as fiduciary
with respect to an employee benefit plan where the
performance by such person of duties to the Corporation also
imposes duties on, or otherwise involves services by, such
person as a fiduciary with respect to the plan;
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(ii) excise taxes assessed with respect to any transaction
with an employee benefit plan shall be deemed "fines"; and
(iii) action taken or omitted by such person with respect to
an employee benefit plan in the performance of duties for a
purpose reasonably believed to be in the interest of the
participants and beneficiaries of the plan shall be deemed
to be for a purpose which is not opposed to the best
interests of the Corporation.
(e) To further effect, satisfy or secure the indemnification
obligations provided herein or otherwise, the Corporation may maintain
insurance, obtain a letter of credit, act as self-insurer, create a reserve,
trust, escrow, cash collateral or other fund or account, enter into
indemnification agreements, pledge or grant a security interest in any assets
or properties of the Corporation, or use any other mechanism or arrangement
whatsoever in such amounts, at such costs, and upon such other terms and
conditions as the Board of Directors shall deem appropriate.
(f) All rights of indemnification under this Section shall be
deemed a contract between the Corporation and the person entitled to
indemnification under this Section pursuant to which the Corporation and each
such person intend to be legally bound. Any repeal, amendment or modification
hereof shall be prospective only and shall not limit, but may expand, any
rights or obligations in respect of any proceeding whether commenced prior to
or after such change to the extent such proceeding pertains to actions or
failures to act occurring prior to such change.
(g) The indemnification, as authorized by this Section, shall
not be deemed exclusive of any other rights to which those seeking
indemnification or advancement of expenses may be entitled under any statute,
agreement, vote of shareholders, or disinterested directors or otherwise, both
as to action in an official capacity and as to action in any other capacity
while holding such office. The indemnification and advancement of expenses
provided by, or granted pursuant to, this Section shall continue as to a
person who has ceased to be an officer, director, employee or agent in respect
of matters arising prior to such time, and shall inure to the benefit of the
heirs, executors and administrators of such person.
Stock of Other Corporations
38. The Board of Directors may authorize any director, officer or
other person on behalf of the Corporation to attend, act and vote at meetings
of the stockholders of any corporation in which the Corporation shall hold
stock, and to exercise thereat any and all of the rights and powers incident
to the ownership of such stock and to execute waivers of notice of such
meetings and calls therefor.
Certificates of Stock
39. The certificates of stock of the Corporation shall be numbered and
shall be entered in the books of the Corporation as they are issued. They
shall exhibit the holder's name and number of shares and may include his
address. No fractional shares of stock shall be issued. Certificates of
stock shall be signed by the Chairman, President or a Vice President and by
the Treasurer or an Assistant Treasurer or the Secretary or an Assistant
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Secretary, and shall be sealed with the seal of the Corporation. Where any
certificate of stock is signed by a transfer agent or transfer clerk, who may
but need not be an officer or employee of the Corporation, and by a registrar,
the signatures of any such Chairman, President, Vice President, Secretary,
Assistant Secretary, Treasurer, or Assistant Treasurer upon such certificate
may be facsimiles, engraved or printed. In case any such officer who has
signed or whose facsimile signature has been placed upon such certificate
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shall have ceased to be such before such certificate of stock is issued, it
may be issued by the Corporation with the same effect as if such officer had
not ceased to be such at the date of its issue.
Transfer of Stock
40. Transfers of stock shall be made on the books of the Corporation
only by the person named in the certificate or by attorney, lawfully
constituted in writing, and upon surrender of the certificate therefor.
Fixing of Record Date
41. The Board of Directors is hereby authorized to fix a time, not
exceeding fifty (50) days preceding the date of any meeting of stockholders or
the date fixed for the payment of any dividend or the making of any
distribution, or for the delivery of evidences of rights or evidences of
interests arising out of any change, conversion or exchange of capital stock,
as a record time for the determination of the stockholders entitled to notice
of and to vote at such meeting or entitled to receive any such dividend,
distribution, rights or interests, as the case may be; and all persons who are
holders of record of capital stock at the time so fixed and no others, shall
be entitled to notice of and to vote at such meeting, and only stockholders of
record at such time shall be entitled to receive any such notice, dividend,
distribution, rights or interests.
Registered Stockholders
42. The Corporation shall be entitled to treat the holder of record of
any share or shares of stock as the holder in fact thereof and accordingly
shall not be bound to recognize any equitable or other claim to, or interest
in, such share on the part of any other person, whether or not it shall have
express or other notice thereof, save as expressly provided by statutes of the
Commonwealth of Pennsylvania.
Lost Certificates
43. Any person claiming a certificate of stock to be lost or destroyed
shall make an affidavit or affirmation of that fact, whereupon a new
certificate may be issued of the same tenor and for the same number of shares
as the one alleged to be lost or destroyed; provided, however, that the Board
of Directors may require, as a condition to the issuance of a new certificate,
the payment of the reasonable expenses of such issuance or the furnishing of a
bond of indemnity in such form and amount and with such surety or sureties, or
without surety, as the Board of Directors shall determine, or both the payment
of such expenses and the furnishing of such bond, and may also require the
advertisement of such loss in such manner as the Board of Directors may
prescribe.
Inspection of Books
44. The Board of Directors may determine whether and to what extent,
and at what time and places and under what conditions and regulations, the
accounts and books of the Corporation (other than the books required by
statute to be open to the inspection of stockholders), or any of them, shall
be open to the inspection of stockholders, and no stockholder shall have any
right to inspect any account or book or document of the Corporation, except as
27
<PAGE>
such right may be conferred by statutes of the Commonwealth of Pennsylvania or
by the By-Laws or by resolution of the Board of Directors or of the
stockholders.
Checks, Notes, Bonds and Other Instruments
45. (a) All checks or demands for money and notes of the Corporation
shall be signed by such person or persons (who may but need not be an officer
or officers of the Corporation) as the Board of Directors may from time to
28
<PAGE>
time designate, either directly or through such officers of the Corporation as
shall, by resolution of the Board of Directors, be authorized to designate
such person or persons. If authorized by the Board of Directors, the
signatures of such persons, or any of them, upon any checks for the payment of
money may be made by engraving, lithographing or printing thereon a facsimile
of such signatures, in lieu of actual signatures, and such facsimile
signatures so engraved, lithographed or printed thereon shall have the same
force and effect as if such persons had actually signed the same.
(b) All bonds, mortgages and other instruments requiring a seal,
when required in connection with matters which arise in the ordinary course of
business or when authorized by the Board of Directors, shall be executed on
behalf of the Corporation by the Chairman or the President or a Vice
President, and the seal of the Corporation shall be thereupon affixed by the
Secretary or an Assistant Secretary or the Treasurer or an Assistant
Treasurer, who shall, when required, attest the ensealing and execution of
said instrument. If authorized by the Board of Directors, a facsimile of the
seal may be employed and such facsimile of the seal may be engraved,
lithographed or printed and shall have the same force and effect as an
impressed seal. If authorized by the Board of Directors, the signatures of
the Chairman or the President or a Vice President and the Secretary or an
Assistant Secretary or the Treasurer or an Assistant Treasurer upon any
engraved, lithographed or printed bonds, debentures, notes or other
instruments may be made by engraving, lithographing or printing thereon a
facsimile of such signatures, in lieu of actual signatures, and such facsimile
signatures so engraved, lithographed or printed thereon shall have the same
force and effect as if such officers had actually signed the same. In case
any officer who has signed, or whose facsimile signature appears on, any such
bonds, debentures, notes or other instruments shall cease to be such officer
before such bonds, debentures, notes or other instruments shall have been
delivered by the Corporation, such bonds, debentures, notes or other
instruments may nevertheless be adopted by the Corporation and be issued and
delivered as though the person who signed the same, or whose facsimile
signature appears thereon, had not ceased to be such officer of the
Corporation.
Receipts for Securities
46. All receipts for stocks, bonds or other securities received by the
Corporation shall be signed by the Treasurer or an Assistant Treasurer, or by
such other person or persons as the Board of Directors or Executive Committee
shall designate.
Fiscal Year
47. The fiscal year shall begin the first day of January in each year.
Dividends
48. (a) Dividends in the form of cash or securities, upon the
capital stock of the Corporation, to the extent permitted by law, may be
declared by the Board of Directors at any regular or special meeting.
(b) The Board of Directors shall have power to fix and
determine, and from time to time vary, the amount to be reserved as working
29
<PAGE>
capital; to determine whether any, and if any, what part of any, surplus of
the Corporation shall be declared as dividends; to determine the date or dates
for the declaration and payment or distribution of dividends; and, before
payment of any dividend or the making of any distribution to set aside out of
the surplus of the Corporation such amount or amounts as the Board of
Directors from time to time, in its absolute discretion, may think proper as a
reserve fund to meet contingencies, or for equalizing dividends, or for such
other purpose as it shall deem to be in the interests of the Corporation.
30
<PAGE>
Directors' Annual Statement
49. The Board of Directors shall present or cause to be presented at
each annual meeting of stockholders, and when called for by vote of the
stockholders at any special meeting of the stockholders, a full and clear
statement of the business and condition of the Corporation.
Notices
50. (a) Whenever under the provisions of the By-Laws notice is
required to be given to any director, officer or stockholder, it shall not be
construed to require personal notice, but, except as otherwise specifically
provided, such notice may be given in writing, by mail, by depositing a copy
of the same in a post office, letter box or mail chute, maintained by the
United States Postal Service, postage prepaid, addressed to such stockholder,
officer or director, at his address as the same appears on the books of the
Corporation.
(b) A stockholder, director or officer may waive in writing any
notice required to be given to him by law or by the By-Laws.
Participation in Meetings by Telephone
51. At any meeting of the Board of Directors or the Executive
Committee or any other committee designated by the Board of Directors, one or
more directors may participate in such meeting in lieu of attendance in person
by means of the conference telephone or similar communications equipment by
means of which all persons participating in the meeting will be able to hear
and speak.
Oath of Judges of Election
52. The judges of election appointed to act at any meeting of the
stockholders shall, before entering upon the discharge of their duties, be
sworn faithfully to execute the duties of judge at such meeting with strict
impartiality and according to the best of their ability.
Amendments
53. The By-Laws may be altered or amended by the affirmative vote of
the holders of a majority of the capital stock represented and entitled to
vote at a meeting of the stockholders duly held, provided that the notice of
such meeting shall have included notice of such proposed amendment. The
By-Laws may also be altered or amended by the affirmative vote of a majority
of the directors in office at a meeting of the Board of Directors, the notice
of which shall have included notice of the proposed amendment. In the event
of the adoption, amendment, or repeal of any By-Law by the Board of Directors
pursuant to this Section, there shall be set forth in the notice of the next
meeting of stockholders for the election of directors the By-Law so adopted,
amended or repealed together with a concise statement of the changes made. By
the affirmative vote of the holders of a majority of the capital stock
represented and entitled to vote at such meeting, the By-Laws may, without
further notice, be altered or amended by amending or repealing such action by
the Board of Directors.
31
<PAGE>
Exhibit 10-A
GENERAL PUBLIC UTILITIES CORPORATION
RESTRICTED STOCK PLAN FOR OUTSIDE DIRECTORS
AS AMENDED AND RESTATED AS OF JUNE 2, 1994 <PAGE>
GENERAL PUBLIC UTILITIES CORPORATION
RESTRICTED STOCK PLAN FOR OUTSIDE DIRECTORS
1. Purpose. The purpose of this restricted Stock Plan for
Outside Directors (the "Plan") is to enable General Public
Utilities Corporation ("GPU") to attract and retain persons of
outstanding competence to serve on its Board of Directors by
paying such persons a portion of their compensation in GPU Common
Stock pursuant to the terms hereof.
2. Definitions.
(a) The term "Change in Control" shall have the same meaning
as assigned to such term under the definition of such term
contained in Section 7(c) of the 1990 Stock Plan for Employees of
General Public Utilities Corporation and Subsidiaries.
(b) The term "Outside Director" or "Participant" means a
member of the Board of Directors of GPU who is not an employee
(within the meaning of the Employee Retirement Income Security
Act of 1974) of GPU or any of its Subsidiaries. A director of
GPU who is also an employee of GPU or any of its Subsidiaries
shall become eligible to participate in this Plan and shall be
entitled to receive an award of restricted stock upon the
termination of such employment.
(c) The term "Subsidiary" means any corporation 50% or more
of the outstanding Common Stock of which is owned, directly or
indirectly, by GPU.
(d) The term "Service" shall mean service as an Outside
Director.
3. Eligibility. All Outside Directors of GPU shall receive
stock awards hereunder.
4. Stock Awards.
(a) A total of 33,000(1) shares of GPU Common Stock shall be
available for awards under the Plan. Such shares shall be either
previously unissued shares or reacquired shares. Any restricted
shares awarded under this Plan with respect to which the
restrictions do not lapse and which are forfeited as provided
herein shall again be available for other awards under the plan.
(1) Initially, 20,000 shares were authorized to be issued under
the Plan. On May 29, 1991, GPU effected a two-for-one stock
split by way of a stock dividend, leaving 33,000 shares
available for issuance under the Plan on and after July 1,
1991 after giving effect to shares previously awarded.<PAGE>
(b) Each Outside Director shall receive an annual award of
300 shares of GPU Common Stock with respect to each
calendar year or portion thereof, during which he or
she serves as an Outside Director, beginning with the
calendar year 1993. Awards shall be made in January of
each year. However, for the calendar year in which an
Outside Director commences Service, the award of shares
to such Outside Director for such year shall be made in
the month in which his or her Service commences, if his
or her Service commences after January 31 of such year.
All awards of shares made hereunder shall be subject to
the restrictions set forth in Section 5.
(c) Subject to the provisions of Section 5, certificates
representing shares of GPU Common Stock awarded
hereunder shall be issued in the name of the respective
Participants. During the period of time such shares
are subject to the restrictions set forth in Section 5,
such certificates shall be endorsed with a legend to
that effect, and shall be held by GPU or an agent
therefor. The Participant shall, nevertheless, have
all the other rights of a shareholder, including the
right to vote and the right to receive all cash
dividends paid with respect to such shares.
Subject to the requirements of applicable law, certificates
representing such shares shall be delivered to the Participant
within 30 days after the lapse of the restrictions to which they
are subject.
(d) If as a result of a stock dividend, stock split,
recapitalization (or other adjustment in the stated
capital of GPU), or as the result of a merger,
consolidation, or other reorganization, the common
shares of GPU are increased, reduced, or otherwise
changed, the number of shares available and to be
awarded hereunder shall be appropriately adjusted, and
if by virtue thereof a Participant shall be entitled to
new or additional or different shares, such shares to
which the Participant shall be entitled shall be
subject to the terms, conditions, and restrictions
herein contained relating to the original shares. In
the event that warrants or rights are awarded with
respect to shares awarded hereunder, and the recipient
exercises such rights or warrants, the shares or
securities issuable upon such exercise shall be
likewise subject to the terms, conditions, and
restrictions herein contained relating to the original
shares.
5. Restrictions.
(a) Shares are awarded to a Participant on the condition
that he or she serves or has served as an Outside
Director until:
(i) the Participant's death or disability, or<PAGE>
(ii) the Participant's failure to stand for re-
election at the end of the term during
which the Participant reaches age 70; or
(iii) the Participant's resignation or failure to
stand for re-election prior to the end of
the term during which the Participant
reaches age 70 with the consent of the
Board, i.e., approval thereof by a least
80% of the directors voting thereon, with
the affected director abstaining; or
(iv) the Participant's failure to be re-elected
after being duly nominated.
Termination of Service of a Participant for any other reason,
including, without limitation, any involuntary termination
effected by Board action, shall result in forfeiture of all
shares awarded. Notwithstanding the foregoing, upon the
occurrence of a Change in Control, the restrictions set forth in
Section 5(b) hereof to which any shares awarded to a Participant
are then still subject shall lapse, and the termination of the
Participant's Service for any reason at any time after the
occurrence of such Change in Control shall not result in the
forfeiture of any such shares.
(b) Shares awarded hereunder may not be sold, exchanged,
transferred, pledged, hypothecated, or otherwise
disposed of (herein, "Transferred") other than to GPU
pursuant to Section 5(a) during the period commencing
on the date of the award of such shares and ending on
the date of termination of the Outside Director's
Service; provided, however, that in no event may any
shares awarded hereunder be Transferred for a period of
six months following the date of the award thereof,
except in the case of the recipient's death or
disability, other than to GPU pursuant to Section 5(a)
hereof.
(c) Each Participant shall represent and warrant to and
agree with GPU that he or she (i) takes any shares
awarded under the Plan for investment only and not for
purposes of sale or other disposition and will also
take for investment only and not for purposes of sale
or other disposition any rights, warrants, shares, or
securities which may be issued on account of ownership
of such shares, and (ii) will not sell or transfer any
shares awarded or any shares received upon exercise of
any such rights or warrants except in accordance with
(A) an opinion of counsel for GPU (or other counsel
acceptable to GPU) that such shares,s rights, warrants,
or other securities may be disposed of without
registration under the Securities Act of 1933, or (B)
an applicable "no action" letter issued by the Staff of
the Commission.<PAGE>
6. Administrative Committee. An Administrative Committee (the
"Committee") shall have full power and authority to construe and
administer the Plan. Any action taken under the provisions of
the Plan by the Committee arising out of or in connection with
the administration, construction, or effect of the Plan or any
rules adopted thereunder shall, in each case, lie within the
discretion of the Committee and shall be conclusive and binding
under GPU and upon all Participants, and all persons claiming
under or through any of them. Notwithstanding the foregoing, any
determination made by the Committee after the occurrence of a
Change in Control that denies in whole or in part any claim made
by any individual for benefits under the Plan shall be subject to
judicial review, under a "de novo", rather than a deferential,
standard. The Committee shall have as members the Chief
Executive Officer of GPU and two officers of GPU or its
Subsidiaries designated by the Chief Executive Officer. In the
absence of such designation, the other members of the Committee
shall be the Chief Financial Officer and the Secretary of GPU.
7. Approval: Effective Date. The Plan is subject to the
approval of a majority of the holders of GPU's Common Stock
present and entitled to vote at a meeting of shareholders, and of
the Securities and Exchange Commission under the Public Utility
Holding Company Act of 1935. The Plan shall be effective
January 1, 1989.
8. Amendment. The Plan may be amended or repealed by the Board
of Directors of GPU, provided that if any such amendment requires
shareholder approval to meet the requirements of the then
applicable rules under Section 16(b) of the Securities Exchange
act of 1934, such amendment shall require the approval of a
majority of the holders of GPU's Common Stock present and entitled
to vote at a meeting of shareholders, and provided that such
action shall not adversely affect any Participant's rights under
the Plan with respect to awards which were made prior to such
action. Notwithstanding the foregoing, Section 4(b) of the Plan
may not be amended more often than once every six months other
than to comport with changes in the Internal Revenue Code or the
Employee Retirement Income Security Act, or the rules thereunder.<PAGE>
Exhibit 10-B
RETIREMENT PLAN FOR OUTSIDE DIRECTORS
OF GENERAL PUBLIC UTILITIES CORPORATION
AS AMENDED AND RESTATED AS OF
JUNE 2, 1994<PAGE>
RETIREMENT PLAN FOR OUTSIDE DIRECTORS
OF GENERAL PUBLIC UTILITIES CORPORATION
1. Purpose
The Retirement Plan for Outside Directors of General Public
Utilities Corporation (the "Plan") is designed to enhance the
ability of General Public Utilities Corporation ("GPU") to
attract and retain competent and experienced Outside Directors by
providing retirement benefits and death benefits for Eligible
Outside Directors who retire or die after the Plan's Effective
Date.
2. Definitions
Except as otherwise specified or as the context may otherwise
require, the following terms have the meanings indicated below
for all purposes of this Plan:
Outside Director means a member of the Board of Directors of GPU
who, during the period involved, is not or was not an Officer or
an employee of GPU or a subsidiary thereof.
Board Service means service as an Outside Director of GPU both
before and after the Effective Date.
Change in Control means a "Change in Control" as defined in
Section 7(c) of the 1990 Stock Plan for Employees of General
Public Utilities Corporation and Subsidiaries.
Compensation means the sum of: (a) the monthly retainer paid in
cash to an Outside Director as compensation for services as a
Director of GPU, excluding any fees paid for attendance at
meetings of the Board of Directors of GPU or any committee of
such Board of Directors, and also excluding any additional
retainer paid for service as a Committee Chairman, and (b) one-
twelfth of the cash value of all shares awarded to, the Outside
Director pursuant to the Restricted Stock Plan for Outside
Directors as the annual award thereunder for the year preceding
his or her Retirement, and not subsequently forfeited.
The cash value of a share shall be its closing price as reported
for New York Stock Exchange-Composite Transactions on the date of
award.
Effective Date means the date of initial adoption of this Plan by
the Board of Directors of GPU.
Retirement of Retires means the cessation of service as an
Outside Director for any reason other than (i) acceptance of
employment as an officer or employee of GPU or a subsidiary
thereof or (ii) death.
2<PAGE>
3. Eligibility
An Outside Director who has completed at least fifty-four (54)
months of Board Service and who Retires from the Board of
Directors of GPU or dies before Retirement on or after the
Effective Date shall be eligible for benefits as provided herein.
After the occurrence of a Change in Control, any person who was
an Outside Director immediately prior to such Change in Control,
shall be eligible for benefits as provided herein upon Retirement
or death before Retirement, whether or not such Outside Director
has completed at least fifty-four (54) months of Board Service.
4. Pension Benefits of Eligible Retired Outside Directors
Before Death
The accumulated amount of pension benefits payable to an Outside
Director eligible to receive benefits hereunder shall be equal to
the product of (a) the number of months of such Outside
Director's Board Service under this Plan times (b) the monthly
compensation of such Outside Director at the date of such Outside
Director's Retirement under the Plan. Such pension benefits
shall be paid in monthly installments equal to the monthly
compensation of each Outside Director at the date of such Outside
Director's Retirement. Such pension benefits shall commence on
the first day of the month following the Director's 60th birthday
or the Director's Retirement under the Plan, whichever is later,
and shall continue during the Retired Outside Director's life
until the date when the total payments to the Retired Outside
Director shall be equal to the Outside Director's accumulated
pension benefits at the date of such Director's Retirement.
5. Benefits Payable by Reason of Death of Eligible Outside
Director
In the event that an Outside Director who is eligible to
receive benefits hereunder should die prior to receiving
payment of the full amount of his or her accumulated pension
benefits, the remaining portion of such Outside Director's
accumulated pension benefits shall be paid as follows:
(a) If the Outside Director dies after Retirement, the
monthly payments previously made to the Outside
Director shall continue to be made to the Outside
Director's surviving spouse (or, if applicable,
designated beneficiary) until the aggregate of the
payments to the Outside Director and such surviving
spouse or beneficiary shall be equal to the Outside
Director's accumulated pension benefits at the date of
such Director's Retirement.
3<PAGE>
(b) If the Outside Director dies prior to Retirement, there
shall be paid to the Outside Director's surviving
spouse, (or, if applicable, designated beneficiary)
monthly installments equal to the monthly compensation
of such Outside Director at the date of such Outside
Director's death until the aggregate of the payments to
such surviving spouse (or, if applicable, designated
beneficiary) shall be equal to the Outside Director's
accumulated amount of pension benefits at the date of
the Outside Director's death. Payment of such monthly
installments shall begin on the first day of the month
next following the Outside Director's death or, if
later, the first day of the month in which the Outside
Director's 60th birthday would have occurred if the
outside Director had survived.
6. Designated Beneficiary of Eligible Outside Director
If an Eligible Outside Director shall die without leaving a
surviving spouse or if the Outside Director's surviving spouse
shall die prior to payment in full of the outside Director's
accumulated pension benefits, the payments which would otherwise
have been made to the Outside Director's surviving spouse shall
be made to the Outside Director's designated beneficiary (or
beneficiaries). Such designations shall be made in writing on
forms provided by GPU to the Outside Director. Any such
designation by an Outside Director may be revoked by the Outside
Director at any time before or after Retirement. Any such
revocation shall be made in writing on a form provided by GPU to
the Outside Director.
7. Provision for Benefits
All benefits payable hereunder shall be provided from the general
assets of GPU. No Outside Director shall acquire any interest in
any specific assets of GPU by reason of this Plan. An Outside
Director shall have the status of a mere unsecured creditor of
GPU with respect to his or her right to receive any payment under
the Plan. The Plan shall constitute a mere promise by GPU to
make payments in the future of the benefits provided for herein.
It is intended that the arrangements reflected in this Plan be
treated as unfunded for tax purposes.
8. Amendment and Terminations
The Board of Directors of GPU reserves the right to terminate
this Plan or amend this Plan prospectively in any respect at any
time, but no such amendment may reduce (a) the benefits of any
Outside Director who has previously Retired hereunder, or (b) the
benefits accrued herewith by any Outside Director prior to the
effective date of such amendment.
4<PAGE>
9. Administration
This Plan shall be administered by the Personnel, Compensation,
and Nominating Committee of the Board of Directors of GPU. Such
Committee's final decision, in making any determination or
construction under this Plan and in exercising any discretionary
power, shall in all instances be final and binding on all persons
having or claiming any rights under this Plan. Notwithstanding
the foregoing, any determination made by the Committee after the
occurrence of a Change in Control that denies in whole or in part
any claim made by any individual for benefits under the Plan
shall be subject to judicial review, under a "de novo", rather
than a deferential, standard.
10. Miscellaneous
Nothing herein contained shall be deemed to give any Outside
Director the right to be retained as a Director of GPU, nor shall
it interfere with the Outside Director's right to terminate such
directorship at any time. An Outside Director's rights to
payments under this Plan shall not be subject in any manner to
anticipation, alienation, sale, transfer (other than transfer by
will or by the laws of descent and distribution, in the absence
of a beneficiary designation), assignment, pledge, encumbrance,
attachment or garnishment by creditors of the Outside Director or
his or her spouse or other beneficiary.
5<PAGE>
Exhibit 10-C
DEFERRED REMUNERATION PLAN FOR OUTSIDE DIRECTORS
OF GENERAL PUBLIC UTILITIES CORPORATION
(AS AMENDED AND RESTATED EFFECTIVE JUNE 2, 1994)
1. Purpose
1.1 The purpose of this document is to set forth the
Deferred Remuneration Plan for Outside Directors, as
amended and restated effective June 2, 1994. The Plan
will be implemented by individual elections by each
Director.
2. Plan Summary
2.1 This Plan provides for deferral by Directors of all or
a portion of current Remuneration.
2.2 Funds being deferred will be credited with the
equivalent of interest in accordance with Section 6.
2.3 Each component of the deferred funds will be
distributed as follows:
(a) for a Director who elects deferral until a date or
dates following his or her Retirement, to the
Director, in accordance with his or her latest
effective election.
(b) for a Director who elects deferral until a date or
dates preceding his or her Retirement, to the
Director, in accordance with his or her initial
election; or
(c) if a Director dies before the deferred funds have
been fully distributed, to his or her designated
beneficiary, in accordance with the option in
effect for the Director under Section 7.2 for each
component except as the Board may otherwise
determine, based on the circumstances at the time
the distribution is to commence.
3. Definition of Terms
3.1 Account - refers to both Pre-Retirement and Retirement
Accounts established for Directors unless specifically
designated one or the other in the text of this Plan.
3.2 Board of Directors - refers to the Board of Directors
of General Public Utilities Corporation.<PAGE>
3.3 Committee - refers to the Personnel, Compensation and
Nominating Committee of General Public Utilities
Corporation.
3.4 Company - refers to General Public Utilities
Corporation.
3.5 Director - refers to a member of the Board of Directors
who is not an employee of General Public Utilities
Corporation or any of its subsidiaries.
3.6 Plan - refers to this Deferred Remuneration Plan for
Outside Directors as described in this document and as
it may be amended in the future.
3.7 Remuneration - refers to all cash amounts earned during
a calendar year by a Director for services performed as
a Director (including services performed as a member of
a committee of the Board of Directors), but does not
include consulting fees, reimbursement for travel or
other expenses or Company contributions to other
benefit plans.
3.8 Pre-Retirement Account - refers to the memorandum
account which shall be established and maintained for a
Director who elects, pursuant to Section 5.2, to have
payment of any portion of his or her Remuneration for
any Plan Year deferred to a date prior to his or her
Retirement. A separate Pre-Retirement Account shall be
established and maintained for the Remuneration for
each Plan Year which the Director so elects to defer.
3.9 Retirement Account - refers to the memorandum account
which shall be established and maintained for a
Director who elects, pursuant to Section 5.2, to have
payment of any portion of his or her Remuneration for
any Plan Year deferred to a date after his or her
Retirement. All amounts deferred pursuant to elections
made on or before December 31, 1985 under the Plan by a
Director, together with all interest equivalents earned
by such election and created to such amounts prior to
December 31, 1986, shall be treated, on or after such
date, as part of the Director's Retirement Account.
3.10 Retirement - refers to the retirement from service on
the Board of Directors, on account of resignation,
death, or any other reason, without becoming an
employee of GPU or any of its subsidiaries.
3.11 Plan Year - refers to the period October 1, 1986
through December 31, 1986; and each twelve (12) month
period from January 1 through December 31 thereafter.
2<PAGE>
4. Administration
4.1 The Board of Directors has established this Plan. The
Board of Directors may in its sole discretion modify
the provisions of the Plan from time to time, or may
terminate the entire Plan at any time. Such
modification or termination shall not affect the rights
of any participant accrued prior to such modification
or termination.
4.2 Responsibility for the ongoing administration of this
Plan rests with the Committee.
4.3 The Committee may delegate the daily administration of
this Plan, including the maintenance of appropriate
records, receiving notifications, making filings, and
maintaining related documentation, to the Vice
President - Human Resources of GPU Service Corporation
and to the Vice President's staff.
4.4 All questions concerning the Plan, as well as any
dispute over accounting or administrative procedures or
interpretation of the Plan, will be resolved at the
sole discretion of the Committee, except that no member
of the Committee shall vote on any matter which affects
that member but not all other members of the Committee.
Notwithstanding the foregoing, any determination made
by the Committee after the occurrence of a "Change in
Control", as defined in Section 7(c) of the 1990 Stock
Plan for Employees of General Public Utilities
Corporation and Subsidiaries, that denies in whole or
in part any claim made by any individual for benefits
under the Plan shall be subject to judicial review,
under a "de novo", rather than a deferential, standard.
4.5 All provisions of this Plan, its administration and
interpretation, are intended to be in compliance with
appropriate Internal Revenue Service Rulings and
judicial decisions regarding the construction and
operation of a deferred compensation program, so that
deferred Remuneration and interest equivalents thereon
will not constitute income constructively received
prior to being distributed under the terms of this
Plan.
4.6 A Director's election to voluntarily defer
Remuneration, selection of a distribution commencement
date and distribution option, and designation of a
beneficiary and contingent beneficiary, made pursuant
to this Plan shall be made in writing, on a form
furnished to the Director by the Company for such
purposes, signed and delivered personally or by first
class mail to:
3<PAGE>
Corporate Secretary
GPU Service Corporation
100 Interpace Parkway
Parsippany, New Jersey 07054-1149
Any such election, selection, designation, or change
therein, shall not become effective unless and until
received by the Corporate Secretary. A change in a
distribution election made after April 30, 1987 will
not be effective unless made at least twenty-four (24)
months prior to his or her Retirement or Disability.
5. Deferral Election
5.1 A Director may elect to defer all or any portion of his
or her Remuneration for any Plan Year, providing such
portion is three thousand dollars ($3,000) or more. A
separate deferral election shall be made with respect
to a Director's Remuneration for each Plan Year. An
election to defer Remuneration for the 1986 amended
Plan Year shall be made on or prior to September 30.
In subsequent years, the election shall be made on or
before December 31 of the year preceding the Plan Year.
Notwithstanding, the foregoing, (a) Directors who are
initially elected prior to December 1st of any Plan
Year may, within 30 days of such initial election, make
a deferral election for the then current Plan Year, and
(b) Directors who are initially elected after December
1st of any Plan Year may immediately make a deferral
election for both the then current Plan Year and for
the immediately succeeding Plan Year; provided,
however, that any deferral election made pursuant to
clause (a) or (b) hereof shall be effective only with
respect to Remuneration earned after such election has
become effective. All elections under this Section 5.1
shall be irrevocable.
5.2 In his or her election to defer Remuneration for any
Plan Year, a Director shall specify the amount or
portion of the Remuneration to be deferred, and shall
indicate whether the Remuneration so deferred is to be
credited to a Pre-Retirement Account, or to a
Retirement Account.
5.3 With respect to Remuneration deferred hereunder for a
Plan Year which a Director elects to have credited to
his or her Pre-Retirement Account, the Director shall
specify in the election form the date on which
distribution of the Pre-Retirement Account shall be
made or commence. The date so selected shall be no
earlier than 24 months from the close of the Plan Year.
In the election form for the Plan Year, the Director
shall also select an option under Section 7.2 for the
distribution of the Pre-Retirement Account. Except as
provided in Section 7.4, the date so specified, and the
option so selected, may not thereafter be changed by
the Director.
4<PAGE>
5.4 With respect to any Remuneration deferred hereunder
which a Director elects to have credited to his or her
Retirement Account, the Director shall, at the time he
or she first elects to have an amount credited to that
account, also elect a distribution commencement date
and a distribution option under Section 7.2 for the
distribution of the Retirement Account. A Director
may, subject to the provisions of Section 4.6, change
any election as to the distribution commencement date
and distribution option for the Retirement Account
previously made by the Director. The distribution
commencement date so elected shall be either the first
business day of the calendar year following the
Director's Retirement, or the first business day of any
subsequent calendar year.
5.5 In the case of a Director who, prior to January 1,
1986, made a deferral election under the Plan with
respect to his or her Remuneration for the calendar
year 1986, any deferral election made by the Director
hereunder with respect to the period commencing October
1, 1986 and ending December 31, 1986 shall be
effective, for that period, only with respect to the
excess, if any, of the amount he or she so elects to
defer for said period over the amount of Remuneration
for said period deferred pursuant to the Director's
prior election.
5.6 The amounts which are deferred, including interest
equivalents, will be credited to a Director's Account.
Prior to distribution, all amounts deferred including
interest equivalents, will constitute general assets of
the Company for use as it deems necessary, and will be
subject to the claims of the Company's creditors. A
Director shall have the status of a mere unsecured
creditor of the Company with respect to his or her
right to receive any payment under the Plan. The Plan
shall constitute a mere promise by the Company to make
payments in the future of the benefits provided for
herein. It is intended that the arrangements reflected
in the Plan be treated as unfunded for tax purposes.
6. Interest
Interest equivalents, compounded monthly on deposits treated
as monthly transactions, will be credited at the end of each
quarter in the calendar year. Such credit will be made to
the balance of each account maintained for a Director
hereunder, including the undistributed balance of any such
account from which payments are being made in installments.
The rate used in calculation of interest equivalents will be
no less than the rate equal to the simple average of
Citibank N.A. of New York Prime Rates for the last business
day of each of the three months in the calendar quarter of,
if greater, such other rate as established from time to time
by the Committee.
5<PAGE>
The Company may, but shall not be required to, purchase a
life insurance policy, or policies, to assist it in funding
its payment obligations under the Plan. If a policy, or
policies, is so purchased, it shall, at all times, remain
the exclusive property of the Company and subject to the
claims of its creditors. Neither the Director nor any
beneficiary or contingent beneficiary designated by him or
her shall have any interest in, or rights with respect to
such policy.
7. Distribution of Deferred Funds
7.1 A Director's Pre-Retirement Account shall be
distributed to the Director, or distributions from such
Pre-Retirement Accounts shall commence, on the date or
dates specified in the elections made by the Director
with respect to such accounts. A Director's Retirement
Account shall be distributed to the Director, or
distributions from such Retirement Account shall
commence, on the date specified in the Director's
latest effective election.
7.2 The options for distribution are:
(a) A single lump sum payment.
(b) Annual Installments over any fixed number of years
selected by the Director, with a minimum of five
annual installments required for the Retirement
Account.
(c) Other option, in equal or unequal payments, as
specifically approved by the Committee.
If distribution of a Director's Account is to be made
in annual installments under Option (b) of Section 7.2,
the amount of each installment will be equal the total
amount in said Account on the date the installment is
payable, divided by the number of installments
remaining to be paid. In addition, if the
distributions are made in installments under Option (b)
of Section 7.2, the interest equivalent accrued on each
Account each year after the date the first installment
is payable will be distributed on each anniversary of
such date.
7.3 Except as the Committee may otherwise determine based
on the circumstances at the time the distribution to
the beneficiary is to commence:
(a) If a Director should die after distribution of
his/her Account maintained for the Director has
commenced, but before the entire balance has been
fully distributed, distributions will continue to
be made to the Director's designated beneficiary
or contingent beneficiary, in accordance with the
distribution option in effect for such Account at
the time of the Director's death.
6<PAGE>
(b) If a Director should die before any distribution
from an Account maintained for the Director
hereunder has been made to him or her,
distribution to the Director's designated
beneficiary or contingent beneficiary shall be
made, or shall commence, as soon as practicable
after the Director's death, in accordance with the
distribution option in effect for such Account at
the time of the Director's death.
Amounts remaining to be paid after the death of the
Director, to the designated beneficiary and the
contingent beneficiary, will be paid in a lump sum to
the estate of the last of such persons to die.
7.4 Notwithstanding anything herein to the contrary, any
Account maintained for a Director hereunder may be
distributed, in whole or in part, to such Director on
any date earlier than the date on which distribution is
to be made, or commence, pursuant to the director's
election if:
(a) the Director requests early distribution, and
(b) the Committee, in its sole discretion, determines
that early distribution is necessary to help the
Director meet some severe financial need arising
from circumstances which were beyond the
Director's control and which were not foreseen by
the Director at the time he or she made the
election as to the date or dates for distribution.
A request by a Director for an early distribution
shall be made in writing, shall set forth
sufficient information as to the Director's needs
for such distribution to enable the Committee to
take action on his or her request, and shall be
mailed or delivered to the Company's Corporate
Secretary.
8. Non-Assignment of Deferred Remuneration
8.1 A Director's rights to payments under this Plan shall
not be subject to any manner to anticipation,
alienation, sale, transfer (other than transfer by will
or by the laws of descent and distribution, in the
absence of a beneficiary designation), assignment,
pledge, encumbrance, attachment or garnishment by
creditors of the Director or his or her spouse or other
beneficiary.
8.2 All amounts paid under the Plan, including the interest
equivalents credited to a Director's Account, are
considered to be Remuneration. The crediting of
interest equivalents is intended to preserve the value
of the Remuneration so deferred for the Director.
7<PAGE>
Exhibit 21(A)
METROPOLITAN EDISON COMPANY
SUBSIDIARIES OF THE REGISTRANT
NAME OF STATE OF
SUBSIDIARIES BUSINESS INCORPORATION
YORK HAVEN POWER COMPANY HYDROELECTRIC GENERATING NEW YORK
STATION
MET-ED PREFERRED SPECIAL-PURPOSE DELAWARE
CAPITAL, INC.
<PAGE>
Exhibit 21(B)
PENNSYLVANIA ELECTRIC COMPANY
SUBSIDIARIES OF THE REGISTRANT
NAME OF STATE OF
SUBSIDIARIES BUSINESS INCORPORATION
NINEVEH WATER WATER SERVICE PENNSYLVANIA
COMPANY
THE WAVERLY ELECTRIC LIGHT ELECTRIC DISTRIBUTION PENNSYLVANIA
AND POWER COMPANY
PENELEC PREFERRED SPECIAL-PURPOSE DELAWARE
CAPITAL INC.
<PAGE>
Exhibit 23(A)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the
registration statements of General Public Utilities Corporation
on Forms S-8 (File Nos. 33-32326, 33-42078, 33-34661, 33-32327,
33-51037, 33-32328 and 33-51035) and Forms S-3 (File No.
33-30765) of our report dated February 1, 1995, on our audits of
the consolidated financial statements and financial statement
schedule of General Public Utilities Corporation and Subsidiaries
as of December 31, 1994 and 1993, and for each of the three years
in the period ended December 31, 1994, which report is included
in this Annual Report on Form 10-K, for the year ended December
31, 1994. Our report on such audits contains explanatory
paragraphs related to certain contingencies which have resulted
from the accident at Unit 2 of the Three Mile Island Nuclear
Generating Station; the adoption of 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.
COOPERS & LYBRAND L.L.P.
New York, New York
March 9, 1995<PAGE>
Exhibit 23(B)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the
registration statements of Jersey Central Power & Light Company
on Forms S-3 (File Nos. 33-49463, 33-57905 and 33-57905-01) of
our report dated February 1, 1995, on our audits of the financial
statements and financial statement schedule of Jersey Central
Power & Light Company as of December 31, 1994 and 1993, and for
each of the three years in the period ended December 31, 1994,
which report is included in this Annual Report on Form 10-K, for
the year ended December 31, 1994. Our report on such audits
contains explanatory paragraphs related to a contingency which
has resulted from the accident at Unit 2 of the Three Mile Island
Nuclear Generating Station; the adoption of 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.
COOPERS & LYBRAND L.L.P.
New York, New York
March 9, 1995<PAGE>
EXHIBIT 23(C)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the
registration statements of Metropolitan Edison Company on Forms
S-3 (File Nos. 33-51001, 33-53673 and 33-53763-01) of our report
dated February 1, 1995, on our audits of the consolidated
financial statements and financial statement schedule of
Metropolitan Edison Company and Subsidiaries as of December 31,
1994 and 1993, and for each of the three years in the period
ended December 31, 1994, which report is included in this Annual
Report on Form 10-K, for the year ended December 31, 1994. Our
report on such audits contains explanatory paragraphs related to
certain contingencies which have resulted from the accident at
Unit 2 of the Three Mile Island Nuclear Generating Station; the
adoption of 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.
COOPERS & LYBRAND L.L.P.
New York, New York
March 9, 1995<PAGE>
EXHIBIT 23(D)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the
registration statements of Pennsylvania Electric Company on Forms
S-3 (File Nos. 33-49669, 33-53677 and 33-53677-01) of our report
dated February 1, 1995, on our audits of the consolidated
financial statements and financial statement schedule of
Pennsylvania Electric Company and Subsidiaries as of December 31,
1994 and 1993, and for each of the three years in the period
ended December 31, 1994, which report is included in this Annual
Report on Form 10-K, for the year ended December 31, 1994. Our
report on such audits contains explanatory paragraphs related to
certain contingencies which have resulted from the accident at
Unit 2 of the Three Mile Island Nuclear Generating Station; the
adoption of 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.
COOPERS & LYBRAND L.L.P.
New York, New York
March 9, 19952<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000040779
<NAME> GENERAL PUBLIC UTILITIES CORPORATION
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,266,598
<OTHER-PROPERTY-AND-INVEST> 492,493
<TOTAL-CURRENT-ASSETS> 785,602
<TOTAL-DEFERRED-CHARGES> 1,665,084
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 9,209,777
<COMMON> 314,458
<CAPITAL-SURPLUS-PAID-IN> 663,418
<RETAINED-EARNINGS> 1,775,759
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,572,584 <F1>
150,000
303,116 <F2>
<LONG-TERM-DEBT-NET> 2,345,417
<SHORT-TERM-NOTES> 287,800
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 59,608
<LONG-TERM-DEBT-CURRENT-PORT> 91,165
0
<CAPITAL-LEASE-OBLIGATIONS> 16,982
<LEASES-CURRENT> 157,168
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3,225,937
<TOT-CAPITALIZATION-AND-LIAB> 9,209,777
<GROSS-OPERATING-REVENUE> 3,649,516
<INCOME-TAX-EXPENSE> 152,047
<OTHER-OPERATING-EXPENSES> 3,008,944
<TOTAL-OPERATING-EXPENSES> 3,160,991
<OPERATING-INCOME-LOSS> 488,525
<OTHER-INCOME-NET> (81,155)
<INCOME-BEFORE-INTEREST-EXPEN> 407,370
<TOTAL-INTEREST-EXPENSE> 243,682 <F3>
<NET-INCOME> 163,688
0
<EARNINGS-AVAILABLE-FOR-COMM> 163,688
<COMMON-STOCK-DIVIDENDS> 204,233
<TOTAL-INTEREST-ON-BONDS> 183,186
<CASH-FLOW-OPERATIONS> 750,133
<EPS-PRIMARY> 1.42
<EPS-DILUTED> 1.42
<FN>
<F1> INCLUDES REACQUIRED COMMON STOCK OF $181,051.
<F2> INCLUDES PREFERRED SECURITIES OF SUBSIDIARIES OF $205,000.
<F3> INCLUDES PREFERRED DIVIDENDS OF SUBSIDIARIES OF $28,384.
</FN>
<PAGE>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000053456
<NAME> JERSEY CENTRAL POWER & LIGHT COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,880,445
<OTHER-PROPERTY-AND-INVEST> 255,337
<TOTAL-CURRENT-ASSETS> 379,467
<TOTAL-DEFERRED-CHARGES> 821,539
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,336,788
<COMMON> 153,713
<CAPITAL-SURPLUS-PAID-IN> 435,715
<RETAINED-EARNINGS> 772,240
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,361,668
150,000
37,741
<LONG-TERM-DEBT-NET> 1,168,444
<SHORT-TERM-NOTES> 77,500
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 32,856
<LONG-TERM-DEBT-CURRENT-PORT> 47,439
0
<CAPITAL-LEASE-OBLIGATIONS> 4,362
<LEASES-CURRENT> 102,059
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,354,719
<TOT-CAPITALIZATION-AND-LIAB> 4,336,788
<GROSS-OPERATING-REVENUE> 1,952,425
<INCOME-TAX-EXPENSE> 75,748
<OTHER-OPERATING-EXPENSES> 1,622,399
<TOTAL-OPERATING-EXPENSES> 1,698,147
<OPERATING-INCOME-LOSS> 254,278
<OTHER-INCOME-NET> 13,516
<INCOME-BEFORE-INTEREST-EXPEN> 267,794
<TOTAL-INTEREST-EXPENSE> 104,953
<NET-INCOME> 162,841
14,795
<EARNINGS-AVAILABLE-FOR-COMM> 148,046
<COMMON-STOCK-DIVIDENDS> 100,000 <F1>
<TOTAL-INTEREST-ON-BONDS> 93,477
<CASH-FLOW-OPERATIONS> 356,106
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000065350
<NAME> METROPOLITAN EDISON COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,579,560
<OTHER-PROPERTY-AND-INVEST> 74,667
<TOTAL-CURRENT-ASSETS> 174,861
<TOTAL-DEFERRED-CHARGES> 407,191
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,236,279
<COMMON> 66,273
<CAPITAL-SURPLUS-PAID-IN> 341,616
<RETAINED-EARNINGS> 190,742
<TOTAL-COMMON-STOCKHOLDERS-EQ> 598,631
0
123,598 <F1>
<LONG-TERM-DEBT-NET> 529,783
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 40,517
0
<CAPITAL-LEASE-OBLIGATIONS> 2,174
<LEASES-CURRENT> 33,810
<OTHER-ITEMS-CAPITAL-AND-LIAB> 907,766
<TOT-CAPITALIZATION-AND-LIAB> 2,236,279
<GROSS-OPERATING-REVENUE> 801,303
<INCOME-TAX-EXPENSE> 34,002
<OTHER-OPERATING-EXPENSES> 655,805
<TOTAL-OPERATING-EXPENSES> 689,807
<OPERATING-INCOME-LOSS> 111,496
<OTHER-INCOME-NET> (54,227)
<INCOME-BEFORE-INTEREST-EXPEN> 57,269
<TOTAL-INTEREST-EXPENSE> 56,538 <F2>
<NET-INCOME> 731
2,960
<EARNINGS-AVAILABLE-FOR-COMM> (2,229)
<COMMON-STOCK-DIVIDENDS> 35,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 43,270
<CASH-FLOW-OPERATIONS> 230,171
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> INCLUDES PREFERRED SECURITIES OF SUBSIDIARY OF $100,000.
<F2> INCLUDES DIVIDENDS ON PREFERRED SECURITIES OF SUBSIDIARY
<F2> OF $3,200.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000077227
<NAME> PENNSYLVANIA ELECTRIC COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,747,864
<OTHER-PROPERTY-AND-INVEST> 34,467
<TOTAL-CURRENT-ASSETS> 212,201
<TOTAL-DEFERRED-CHARGES> 386,522
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,381,054
<COMMON> 105,812
<CAPITAL-SURPLUS-PAID-IN> 261,671
<RETAINED-EARNINGS> 290,786
<TOTAL-COMMON-STOCKHOLDERS-EQ> 658,269
0
141,777 <F1>
<LONG-TERM-DEBT-NET> 616,490
<SHORT-TERM-NOTES> 84,300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 26,752
<LONG-TERM-DEBT-CURRENT-PORT> 9
0
<CAPITAL-LEASE-OBLIGATIONS> 6,741
<LEASES-CURRENT> 17,957
<OTHER-ITEMS-CAPITAL-AND-LIAB> 828,759
<TOT-CAPITALIZATION-AND-LIAB> 2,381,054
<GROSS-OPERATING-REVENUE> 944,744
<INCOME-TAX-EXPENSE> 42,297
<OTHER-OPERATING-EXPENSES> 776,215
<TOTAL-OPERATING-EXPENSES> 818,512
<OPERATING-INCOME-LOSS> 126,232
<OTHER-INCOME-NET> (38,077)
<INCOME-BEFORE-INTEREST-EXPEN> 88,155
<TOTAL-INTEREST-EXPENSE> 56,356 <F2>
<NET-INCOME> 31,799
2,937
<EARNINGS-AVAILABLE-FOR-COMM> 28,862
<COMMON-STOCK-DIVIDENDS> 65,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 46,439
<CASH-FLOW-OPERATIONS> 151,566
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> INCLUDES PREFERRED SECURITIES OF SUBSIDIARY OF $105,000.
<F2> INCLUDES DIVIDENDS ON PREFERRED SECURITIES OF SUBSIDIARY
<F2> OF $4,492.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
