UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 file number 1-3141
Jersey Central Power & Light Company
(Exact name of registrant as specified in its charter)
New Jersey 21-0485010
(State or other jurisdiction of (I.R.S. Employer)
incorporation or organization) Identification No.)
300 Madison Avenue
Morristown, New Jersey 07962-1911
(Address of principal executive offices) (Zip Code)
(201) 455-8200
(Registrant's telephone number, including area code)
N/A
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
The number of shares outstanding of each of the issuer's classes of
voting stock, as of October 31, 1994, was as follows:
Common stock, par value $10 per share: 15,371,270 shares
outstanding.<PAGE>
Jersey Central Power & Light Company
Quarterly Report on Form 10-Q
September 30, 1994
Table of Contents
Page
PART I - Financial Information
Financial Statements:
Balance Sheets 3
Statements of Income 5
Statements of Cash Flows 6
Notes to Financial Statements 7
Management's Discussion and Analysis of
Financial Condition and Results of
Operations 19
PART II - Other Information 25
Signatures 26
_________________________________
The financial statements (not examined by independent accountants)
reflect all adjustments (which consist of only normal recurring
accruals) which are, in the opinion of management, necessary for a
fair statement of the results for the interim periods presented,
subject to the ultimate resolution of the various matters as
discussed in Note 1 to the Financial Statements.
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<TABLE>
JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1994 1993
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $4 035 234 $3 938 700
Less, accumulated depreciation 1 486 143 1 380 540
Net utility plant in service 2 549 091 2 558 160
Construction work in progress 143 172 102 178
Other, net 124 862 116 751
Net utility plant 2 817 125 2 777 089
Other Property and Investments:
Nuclear decommissioning trusts 166 889 139 279
Nuclear fuel disposal fund 84 884 82 095
Other, net 5 807 5 802
Total other property and investments 257 580 227 176
Current Assets:
Cash and temporary cash investments 953 17 301
Special deposits 7 384 7 124
Accounts receivable:
Customers, net 143 971 133 407
Other 10 319 31 912
Unbilled revenues 48 644 57 943
Materials and supplies, at average cost or less:
Construction and maintenance 100 418 102 659
Fuel 16 016 11 886
Deferred income taxes 1 799 28 650
Prepayments 199 703 58 057
Total current assets 529 207 448 939
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 138 307 146 284
Unamortized property losses 105 346 109 478
Deferred income taxes 125 598 110 794
Income taxes recoverable through
future rates 124 354 121 509
Other 324 152 327 886
Total deferred debits and other assets 817 757 815 951
Total Assets $4 421 669 $4 269 155
The accompanying notes are an integral part of the financial statements.
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</TABLE>
<TABLE>
JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1994 1993
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 435 715 435 715
Retained earnings 745 943 724 194
Total common stockholder's equity 1 335 371 1 313 622
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 37 741 37 741
Long-term debt 1 215 822 1 215 674
Total capitalization 2 738 934 2 717 037
Current Liabilities:
Debt due within one year 20 009 60 008
Notes payable 98 936 -
Obligations under capital leases 102 638 89 631
Accounts payable:
Affiliates 49 976 34 538
Other 90 612 95 509
Taxes accrued 149 406 119 337
Deferred energy credits 12 094 23 633
Interest accrued 29 233 33 804
Other 53 732 50 950
Total current liabilities 606 636 507 410
Deferred Credits and Other Liabilities:
Deferred income taxes 577 185 569 966
Unamortized investment tax credits 74 359 79 902
Three Mile Island Unit 2 future costs 84 732 79 967
Other 339 823 314 873
Total deferred credits and other liabilities 1 076 099 1 044 708
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 421 669 $4 269 155
The accompanying notes are an integral part of the financial statements.
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</TABLE>
<TABLE>
JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Income
(Unaudited)
<CAPTION>
In Thousands
Three Months Nine Months
Ended September 30, Ended September 30,
1994 1993 1994 1993
<S> <C> <C> <C> <C>
Operating Revenues $567 827 $576 268 $1 513 634 $1 488 256
Operating Expenses:
Fuel 25 950 32 569 80 597 72 742
Power purchased and interchanged:
Affiliates 8 068 12 476 13 194 22 891
Others 157 519 157 163 437 082 440 979
Deferral of energy and capacity
costs, net 832 5 020 (8 211) 30 109
Other operation and maintenance 126 864 115 853 412 850 335 164
Depreciation and amortization 46 943 46 200 141 104 137 976
Taxes, other than income taxes 64 773 67 002 177 981 175 958
Total operating expenses 430 949 436 283 1 254 597 1 215 819
Operating Income Before Income Taxes 136 878 139 985 259 037 272 437
Income taxes 37 574 41 433 58 942 65 421
Operating Income 99 304 98 552 200 095 207 016
Other Income and Deductions:
Allowance for other funds used
during construction 70 645 179 1 891
Other income, net 3 557 4 117 23 154 11 895
Income taxes (2 438) (1 746) (9 645) (4 715)
Total other income
and deductions 1 189 3 016 13 688 9 071
Income Before Interest Charges 100 493 101 568 213 783 216 087
Interest Charges:
Interest on long-term debt 23 579 24 847 70 981 75 856
Other interest 3 140 1 838 12 011 4 362
Allowance for borrowed funds used
during construction (799) (356) (2 054) (1 751)
Total interest charges 25 920 26 329 80 938 78 467
Net Income 74 573 75 239 132 845 137 620
Preferred stock dividends 3 698 3 699 11 096 13 111
Earnings Available for Common Stock $ 70 875 $ 71 540 $ 121 749 $ 124 509
The accompanying notes are an integral part of the financial statements.
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</TABLE>
<TABLE>
JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Cash Flows
(Unaudited)
<CAPTION>
In Thousands
Nine Months
Ended
<S> <C> <C>
September 30,
1994 1993
Operating Activities:
Net income before preferred stock dividends $132 845 $137 620
Adjustments to reconcile income to cash provided:
Depreciation and amortization 155 433 147 979
Amortization of property under capital leases 23 883 25 443
Voluntary enhanced retirement program 46 862 -
Nuclear outage maintenance costs, net (1 507) (1 964)
Deferred income taxes and investment tax
credits, net 11 860 26 562
Deferred energy and capacity costs, net (8 008) 30 413
Accretion income (10 156) (10 876)
Allowance for other funds used during construction (179) (1 891)
Changes in working capital:
Receivables 20 345 (37 755)
Materials and supplies (1 890) 7 550
Special deposits and prepayments (141 905) (9 288)
Payables and accrued liabilities 10 279 (148 168)
Other, net (7 585) (13 384)
Net cash provided by operating activities 230 277 152 241
Investing Activities:
Cash construction expenditures (146 400) (145 401)
Contributions to decommissioning trusts (12 719) (13 630)
Other, net (9 757) (11 721)
Net cash used for investing activities (168 876) (170 752)
Financing Activities:
Issuance of long-term debt - 401 036
Increase (decrease) in notes payable, net 99 100 (5 700)
Retirement of long-term debt (40 008) (246 711)
Capital lease principal payments (25 745) (19 259)
Redemption of preferred stock - (52 375)
Dividends paid on common stock (100 000) (30 000)
Dividends paid on preferred stock (11 096) (14 119)
Net cash (required) provided by
financing activities (77 749) 32 872
Net (decrease) increase in cash and temporary
cash investments from above activities (16 348) 14 361
Cash and temporary cash investments,
beginning of year 17 301 140
Cash and temporary cash investments, end of period $ 953 $ 14 501
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 85 400 $ 90 297
Income taxes paid $ 25 482 $ 21 035
New capital lease obligations incurred $ 34 935 $ 14 259
The accompanying notes are an integral part of the financial statements.
-6-<PAGE>
<FN>
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
Jersey Central Power & Light Company (the Company), which was
incorporated under the laws of New Jersey in 1925, is a wholly owned
subsidiary of General Public Utilities Corporation (GPU), a holding company
registered under the Public Utility Holding Company Act of 1935. The Company
is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania
Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to
herein as the "Company and its affiliates." The Company is also associated
with GPU Service Corporation (GPUSC), a service company; GPU Nuclear
Corporation (GPUN), which operates and maintains the nuclear units of the
Company and its affiliates; and Energy Initiatives, Inc. (EI). EI develops,
owns and operates nonutility generating facilities. All of the Company's
affiliates are wholly owned subsidiaries of GPU. The Company and its
affiliates, GPUSC, GPUN and EI are referred to as the "GPU System."
These notes should be read in conjunction with the notes to financial
statements included in the 1993 Annual Report on Form 10-K. The year-end
condensed balance sheet data contained in the attached financial statements
were derived from audited financial statements. For disclosures required by
generally accepted accounting principles, see the 1993 Annual Report on Form
10-K.
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in three major nuclear projects -- Three
Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational
generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged
during a 1979 accident. At September 30, 1994, the Company's net investment
in TMI-1 and Oyster Creek, including nuclear fuel, was $164 million and
$804 million, respectively. TMI-1 and TMI-2 are jointly owned by the Company,
Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively.
Oyster Creek is owned by the Company.
Costs associated with the operation, maintenance and retirement of
nuclear plants 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 their 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
- 7 -<PAGE>
1. COMMITMENTS AND CONTINGENCIES (continued)
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 OTHER COMMITMENTS AND CONTINGENCIES - 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 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, 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 such 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 Company.
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, the Company and its affiliates and their
suppliers under a reservation of rights with respect to any award of punitive
damages. However, the defendants in the TMI-2 litigation and the insurers
agreed, in March 1994, that the insurers would withdraw their reservation of
rights, with respect to any award of punitive damages.
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1. COMMITMENTS AND CONTINGENCIES (continued)
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 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. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy.
In 1990, the Company and its affiliates submitted a report, in compliance
with NRC regulations, setting forth a funding plan (employing the external
sinking fund method) for the decommissioning of their nuclear reactors. Under
this plan, the Company and its affiliates intend to complete the funding for
Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014,
respectively. The TMI-2 funding completion date is 2014, consistent with
TMI-2 remaining in long-term storage and being decommissioned at the same time
as TMI-1. Under the NRC regulations, the funding target (in 1994 dollars) for
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1. COMMITMENTS AND CONTINGENCIES (continued)
TMI-1 is $157 million, of which the Company's share is $39 million, and for
Oyster Creek is $189 million. Based on NRC studies, a comparable funding
target for TMI-2 (in 1994 dollars), which takes into account the accident, is
$250 million, of which the Company's share is $63 million. 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 actual cost
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $225 to $309 million, of which the Company's share is $56
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 $19 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 charges to expense and contributes to
external trusts amounts collected from customers for nuclear plant
decommissioning and nonradiological costs. In addition, in 1990 the Company
contributed to an external trust an amount not recoverable from customers for
nuclear plant decommissioning.
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1. COMMITMENTS AND CONTINGENCIES (continued)
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 estimates,
for the cost of removal of nonradiological structures and materials at each
plant based on its share ($3.83 million) of an estimated $15.3 million for
TMI-1 and $31.6 million for Oyster Creek. Collections from customers for
retirement expenditures are deposited in external trusts and are classified as
Nuclear decommissioning trusts on the balance sheet, which includes the
interest earned on these funds. Provision for the future expenditures of
these funds has been made in accumulated depreciation, amounting to
$17 million for TMI-1 and $99 million for Oyster Creek at September 30, 1994.
Oyster Creek and TMI-1 retirement costs are accrued and 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:
The Company and its affiliates have recorded a liability amounting to
$250 million, of which the Company's share is approximately $63 million, as of
September 30, 1994, for the radiological decommissioning of TMI-2, reflecting
the NRC funding target. The Company and its affiliates record escalations,
when applicable, in the liability based upon changes in the NRC funding
target. The Company and its affiliates have also recorded a liability in the
amount of $20 million, of which the Company's share is $5 million, for
incremental costs specifically attributable to monitored storage. In
addition, the Company and its affiliates had recorded a liability in the
amount of $71 million, of which the Company's share was approximately
$17.5 million, for nonradiological cost of removal. Expenditures for such
costs through September 1994 have reduced the liability to $69 million, of
which the Company's share is approximately $17.3 million. The Company's share
of the above amounts for retirement costs and monitored storage are reflected
as Three Mile Island Unit 2 future costs on the balance sheet. The Company
has expensed and made a nonrecoverable contribution of $15 million to an
external decommissioning trust. 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 New Jersey Board of Public Utilities (NJBPU) has granted the Company
decommissioning revenues for its 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.
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1. COMMITMENTS AND CONTINGENCIES (continued)
As a result of TMI-2's entering long-term monitored storage, in late
1993, the Company and its affiliates began 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 incremental
monitored storage costs will total $20 million, of which the Company's share
is $5 million, through 2014, the expected retirement date of TMI-1. The
Company's share of these costs has been recognized in rates by the NJBPU.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the Company.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered
one site for insurance purposes) and for Oyster Creek totals $2.7 billion per
site. In accordance with NRC regulations, these insurance policies generally
require that proceeds first be used 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 $9.0 billion.
Coverage for the first $200 million of such liability is provided by private
insurance. The remaining coverage, or secondary protection, is provided by
retrospective premiums payable by all nuclear reactor owners. Under secondary
protection, a nuclear incident at any licensed nuclear power reactor in the
country, including those owned by the GPU System, could result in assessments
of up to $79 million per incident for each of the GPU System's two operating
reactors, subject to an annual maximum payment of $10 million per incident per
reactor. In July 1994, GPUN received an exemption from the NRC to eliminate
the secondary protection requirements for TMI-2.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at their
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years at decreasing levels beginning at $1.8 million for
Oyster Creek and $2.6 million for TMI-1, per week.
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1. COMMITMENTS AND CONTINGENCIES (continued)
Under their insurance policies applicable to nuclear operations and
facilities, the Company and its affiliates are subject to retrospective
premium assessments of up to $51 million in any one year, of which the
Company's share is $31 million, in addition to those payable under the
Price-Anderson Act.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including, but
not limited to, acid rain, water quality, air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, the Company may be required to incur substantial additional costs to
construct new equipment, modify or replace existing and proposed equipment,
remediate or clean up waste disposal and other sites currently or formerly
used by it, including formerly owned manufactured gas plants, and with regard
to electromagnetic fields, postpone or cancel the installation of, or replace
or modify, utility plant, the costs of which could be material. Management
intends to seek recovery through the current ratemaking process for any
additional costs, but recognizes that recovery cannot be assured.
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. The reduction from the previous estimate of
$145 million is primarily due to the postponement of a scrubber installation
at the Keystone generating station until after 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 a state environmental
authority that it is among the potentially responsible parties (PRPs) who may
be jointly and severally liable to pay for the costs associated with the
investigation and remediation at five 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 a lawsuit 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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1. COMMITMENTS AND CONTINGENCIES (continued)
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. At September 30, 1994,
the Company has an estimated environmental liability of $35 million recorded
on its balance sheet relating to these sites. The estimated liability is
based upon ongoing site investigations and remediation efforts, including
capping the sites and pumping and treatment of ground water. If the periods
over which the remediation is currently expected to be performed are
lengthened, the Company believes that it is reasonably possible that the
ultimate costs may range as high as $60 million. Estimates of these costs are
subject to significant uncertainties as the Company does not presently own or
control most of these sites; the environmental standards have changed in the
past and are subject to future change; the accepted technologies are subject
to further development; and the related costs for these technologies are
uncertain. If the Company is required to utilize different remediation
methods, the costs could be materially in excess of $60 million.
In 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. At September 30, 1994, the Company
has collected from customers $3.8 million in excess of expenditures of
$14.3 million. The Company is awaiting a final NJBPU order. The Company is
pursuing reimbursement of the above costs from its insurance carriers, and
intends to seek recovery of these costs from its customers to the extent not
covered by insurance.
The Company is unable to estimate the extent of possible remediation and
associated costs of additional environmental matters. Also unknown are the
consequences of environmental issues, which could cause the postponement or
cancellation of either the installation or replacement of utility plant.
Management believes the costs described above should be recoverable through
the current ratemaking process.
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1. COMMITMENTS AND CONTINGENCIES (continued)
OTHER COMMITMENTS AND CONTINGENCIES
Competition and the Changing Regulatory Environment
As a result of the Energy Policy Act of 1992 and actions of regulatory
commissions, the electric utility industry appears to be moving toward a
combination of competition and a modified regulatory environment. In
accordance with Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (FAS 71), the
Company's financial statements reflect assets and costs based on current cost-
based ratemaking regulations. Continued accounting under FAS 71 requires that
the following criteria be met:
a) A utility's rates for regulated services provided to its
customers are established by, or are subject to approval by, an
independent third-party regulator;
b) The regulated rates are designed to recover specific costs of
providing the regulated services or products; and
c) In view of the demand for the regulated services and the level
of competition, direct and indirect, it is reasonable to assume
that rates set at levels that will recover a utility's costs
can be charged to and collected from customers. This criteria
requires consideration of anticipated changes in levels of
demand or competition during the recovery period for any
capitalized costs.
A utility's operations can cease to meet those criteria for various
reasons, including deregulation, a change in the method of regulation, or a
change in the competitive environment for the utility's regulated services.
Regardless of the reason, a utility whose operations cease to meet those
criteria should discontinue application of FAS 71 and report that
discontinuation by eliminating from its balance sheet the effects of certain
actions of regulators that had been recognized as assets and liabilities
pursuant to FAS 71 but which would not have been recognized as assets and
liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and
meets the above criteria, FAS 71 accounting may only be applied to that
portion. Write-offs of utility plant and regulatory assets may result for
those operations that no longer meet the requirements of FAS 71. In addition,
under deregulation, the uneconomical costs of certain contractual commitments
for purchased power and/or fuel supplies may have to be expensed 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.
- 15 -<PAGE>
1. COMMITMENTS AND CONTINGENCIES (continued)
The Company has entered into power purchase agreements with independently
owned power production facilities (nonutility generators) for the purchase of
energy and capacity for periods up to 25 years. The majority of these
agreements are subject to penalties for nonperformance and other contract
limitations. While a few of these facilities are dispatchable, most are must-
run and generally obligate the Company to purchase all of the power produced
up to the contract limits. As of September 30, 1994, facilities covered by
these agreements having 664 MW of capacity were in service, with another
215 MW scheduled to commence operation in 1994. The estimated cost of these
agreements for 1994 is $325 million. These agreements together with those for
facilities which are not yet in operation provide for the purchase of
approximately 1,197 MW of capacity and energy to the Company by the mid-to-
late 1990s at varying prices.
The emerging competitive market has created uncertainty regarding the
forecasting of the GPU System's energy supply needs which, in turn, has caused
the Company and its affiliates to change their supply strategy to now seek
shorter term agreements offering more flexibility (see Management's Discussion
and Analysis - Competition). Due to the current availability of excess
capacity, the cost of near to intermediate-term energy supply from existing
facilities (i.e., one to eight years) is currently very competitively priced.
The forecasted cost of energy from new supply sources is now lower priced due
to improvements in power plant technologies and reduced forecast fuel prices.
As a result of these developments, the contract prices under virtually all of
the Company and its affiliates' nonutility generation agreements are
substantially in excess of current and forecasted market prices. The Company
and its affiliates intend to initiate actions geared toward substantially
reducing 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 substantial recovery of these costs from customers by
the NJBPU and 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. If the
costs under these agreements are ultimately not recoverable through
ratemaking, or in a competitive market, it could result in a material adverse
effect on the Company as well as the GPU System's financial position and
results of operations. 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.
- 16 -<PAGE>
2. COMMITMENTS AND CONTINGENCIES (continued)
During the second quarter, GPU announced it was offering voluntary
enhanced retirement programs to certain employees. The enhanced retirement
programs are part of a corporate realignment announced in February 1994. At
that time, GPU said that its goal was to achieve $80 million in annual cost
savings by the end of 1996. Approximately 82% of eligible employees have
accepted the retirement programs, resulting in a pre-tax charge to earnings of
$127 million, of which the Company's share was $47 million. These charges are
included as Other operation and maintenance expense on the Income Statement.
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 requesting that the NJBPU dismiss
contentions being made by Ratepayer Advocate that adjustments for alleged
"double recovery" in prior periods are warranted. 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 February 1994, the NJBPU ruled that the 1991 LEAC period was
considered closed but subsequent LEAC periods remain open for further
investigation. This matter is pending before an NJBPU Administrative Law
Judge. Management estimates that the potential exposure for LEAC periods
subsequent to 1991 is approximately $30 million through February 1995, the end
of the current LEAC period. Management is unable to predict 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 $10 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 both current and
former employees alleging unlawful employment practices. It is not expected
that the outcome of these matters will have a material effect on the Company's
financial position or results of operations.
- 17 -<PAGE>
2. INCOME TAXES
In March 1994, as a result of a settlement of a federal income tax refund
claim for 1986, the Company and its affiliates recorded net income tax refunds
aggregating $17 million, of which the Company's share was $4 million, based on
the retirement of TMI-2 for tax purposes. The Company is returning its
portion of the tax refund amounts to its customers by reducing the recovery
period for its investment in TMI-2. Income tax amounts refunded will have no
effect on net income.
At the same time, the Company and its affiliates also recorded a total of
$46 million of net interest income, of which the Company's share was
$11.5 million, representing net interest receivable from the Internal Revenue
Service associated with this refund settlement.
- 18 -<PAGE>
Jersey Central Power & Light Company
Management's Discussion and Analysis of Financial Condition
and Results of Operations
The following is management's discussion of significant factors that
affected the Company's interim financial condition and results of operations.
This should be read in conjunction with Management's Discussion and Analysis
of Financial Condition and Results of Operations included in the Company's
1993 Annual Report on Form 10-K.
RESULTS OF OPERATIONS
Earnings available for common stock for the three months ended
September 30, 1994 were $70.9 million compared with $71.5 million for the
three months ended September 30, 1993. For the nine months ended
September 30, 1994, earnings available for common stock decreased to
$121.7 million from $124.5 million for the comparable period in 1993.
The slight decrease in earnings for the three months ended September 30,
1994 was primarily the result of increased operation and maintenance expense,
which was partially offset by a reduction in reserve capacity expense.
Earnings for the nine months ended September 30, 1994 continue to be
negatively affected by a second quarter charge of $46.9 million ($30.3 million
after taxes) for costs related to the Voluntary Enhanced Retirement Programs.
The same factors that affected the quarterly results also affected results for
the nine-month period. Increased other operation and maintenance expense
included higher emergency and winter storm repair costs, and contributed to
the earnings reduction in the current nine month period.
Earnings for the nine months ended September 30, 1994 were positively
affected by nonrecurring net interest income resulting from refunds of
previously paid federal income taxes related to the tax retirement of Three
Mile Island Unit 2 (TMI-2), increased sales due primarily to the colder-than-
normal winter weather as compared with last year's, increased revenues
resulting from the continued positive effects of a February 1993 retail base
rate increase, and a performance award of $7.8 million for the operation of
the Company's nuclear generating stations. Increased other operation and
maintenance expense, which included emergency and winter storm repair costs,
more than offset the increases detailed above, resulting in an earnings
decrease in the nine month period.
OPERATING REVENUES:
Total revenues of $567.8 million for the three months ended September 30,
1994 were lower by 1.5% compared with the three months ended September 30,
1993. Total revenues for the nine months ended September 30, 1994 increased
1.7% to $1.5 billion compared with the same period in 1993. The components of
the changes are as follows:
- 19 -<PAGE>
(In Millions)
Three Months Nine Months
Ended Ended
September 30, 1994 September 30, 1994
Kilowatt-hour (KWH) revenues
(excluding energy portion) $(0.5) $21.0
Rate increase - 20.8
Energy revenues (7.7) (20.8)
Other revenues (0.2) 4.4
(Decrease)/Increase in revenues $(8.4) $25.4
Kilowatt-hour revenues
The increase in KWH revenues for the nine months ended September 30, 1994
was principally due to new customer additions and increased sales resulting
from seasonal weather effects, particularly the colder-than-normal winter
weather as compared with last year. KWH revenues were relatively flat for the
three month period as the growth in new customers was offset by reduced
customer usage, which was primarily weather-related.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues decreased in each period as a result of a January
1994 decrease in the energy cost rates in effect, decreased energy sales to
other utilities and the loss of wholesale customers. For the nine month
period, these decreases were partially offset by increased sales to ultimate
customers.
Other revenues
Generally, changes in other revenues do not affect net income as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings as it is
substantially recovered through the Company's energy clause. However,
earnings for the three and nine months ended September 30, 1994 were favorably
impacted by a reduction in reserve capacity expense primarily resulting from
the replacement at lower rates of expiring utility purchase contracts.
- 20 -<PAGE>
Other operation and maintenance
The increase in other operation and maintenance expense for the three
months ended September 30, 1994 is primarily due to higher storm and emergency
repairs. The increase in other operation and maintenance expense for the nine
months ended September 30, 1994 is largely attributable to a $46.9 million
charge for costs related to the Voluntary Enhanced Retirement Programs. Other
operation and maintenance expense also increased in the nine-month period due
to higher emergency and winter storm repairs.
Taxes, other than income taxes
Generally, changes in taxes other than income taxes do not significantly
affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income, net
The increase in the nine-month period is principally due to nonrecurring
interest income resulting from refunds of previously paid federal income taxes
related to the tax retirement of TMI-2.
INTEREST CHARGES:
Interest on long-term debt decreased for both periods as a result of
lower interest rates associated with the refinancing of higher cost debt.
Interest on long-term debt also decreased as a result of a reduction in long-
term debt outstanding.
Other interest increased in the nine-month period primarily due to the
tax retirement of TMI-2, which resulted in an increase in interest expense on
additional amounts owed for tax years in which depreciation deductions with
respect to TMI-2 had been taken. Other interest also increased in both
periods due to an increase in the average outstanding amounts of short-term
debt and an increase in interest rates.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the nine months ended September 30, 1994
consisted of $146 million for cash construction expenditures and $40 million
for maturing obligations. The GPU System's construction forecast for 1994 is
currently $586 million, of which the Company's share is $249 million.
Expenditures for maturing debt are expected to be $60 million for 1994.
Management estimates that approximately one-half of the 1994 capital needs
will be satisfied through internally generated funds.
- 21 -<PAGE>
FINANCING:
GPU has requested authorization from the Securities and Exchange
Commission (SEC) to issue up to 5 million shares of additional common stock
through 1996. The proceeds from the sale of such additional common stock
would be principally used to increase the Company and its affiliates' common
equity ratios.
In October 1994, the Company requested regulatory authorization to issue
up to $125 million of Monthly Income Preferred Securities (Securities) through
a special purpose finance subsidiary. The proceeds from the sale of the
Securities will be loaned to the Company and the Company will issue its
deferrable interest subordinated debentures to its subsidiary. The Company
will take a tax deduction for interest paid on the subordinated debentures and
will receive some preferred equity recognition by the credit rating agencies
for the Securities.
In the third quarter of 1994, the Company redeemed at maturity 8.70% and
8.85% first mortgage bonds aggregating $40 million. The Company also redeemed
a maturing $20 million 8.65% first mortgage bond in October 1994.
The Company has regulatory authority to issue and sell first mortgage
bonds, which may be issued as secured medium-term notes, and preferred stock
through June 1995. Under existing authorization, the Company may issue senior
securities in the amount of $275 million, of which $100 million may consist of
preferred stock. The Company currently has the ability to issue $318 million
of first mortgage bonds on the basis of previously issued and retired bonds,
and has interest and dividend coverage ratios currently well in excess of
indenture and charter restrictions. The Company also has regulatory authority
to issue short-term debt, a portion of which may be commercial paper.
GPU GENERATION CORPORATION:
In the third quarter of 1994, the Pennsylvania Public Utility Commission
authorized Met-Ed and Penelec to enter into an operating agreement with the
proposed GPU Generation Corporation (GPUGC) whereby GPUGC would undertake
responsibility for the operation, maintenance and rehabilitation of all
nonnuclear generation facilities owned and operated by the Company and its
affiliates as well as the responsibility for the design, construction, start-
up and testing of any new nonnuclear generation facilities which the Company
and its affiliates may need in the future. Similar applications for
regulatory approval are pending with the NJBPU and the SEC.
COMPETITION:
Due to the current availability of excess capacity, the cost of near to
intermediate-term energy supply from existing facilities (i.e., one to eight
years) is currently very competitively priced as evidenced by the results of
the Company's all source competitive supply solicitation conducted in 1994.
In addition to the energy purchase opportunities from existing facilities, the
forecasted cost of energy from new supply sources is now lower than the
forecasted price in prior years due to improvements in power plant
- 22 -<PAGE>
technologies and reduced forecast fuel prices. As a result of these
developments, the contract prices payable under virtually all of the Company
and its affiliates' nonutility generation agreements are substantially in
excess of current and forecasted market prices. The current and anticipated
above-market payments for nonutility generation (NUG) contracted power is
likely to adversely impact the competitive position of the Company and its
affiliates. In addition, if the costs under these agreements are ultimately
not recoverable through ratemaking, or in a competitive market, it could
result in a material adverse effect on the Company and its affiliates
financial position and results of operations. Therefore, the Company and its
affiliates plan on initiating actions to either eliminate or substantially
reduce the above-market payments under NUG contracts. The Company and its
affiliates intend to communicate with legislators, regulators and customers as
to the adverse economic impacts of these above-market contracts; initiate
regulatory and legislative actions to mitigate the future economic impact of
these contracts; and aggressively pursue NUG contract restructurings including
contract buyouts. As part of the program to reduce above-market payments
under NUG agreements, the Company and its affiliates intend 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
megawatts of NUG contract capacity, would be pooled and managed by a non-
affiliated fuel manager. The Company and its affiliates are in the process of
initiating discussions with the NUGs involved, negotiating a management
agreement with a fuel manager and reviewing the extent to which state and
federal regulatory approvals may be necessary. For more information
concerning NUG purchased power, see Note 1, Other Commitments and
Contingencies - Competition and the Changing Regulatory Environment to the
financial statements.
MEETING ENERGY DEMANDS:
In 1993, the NJBPU asked all electric utilities in the state to assess
the economics of their purchase power contracts with nonutility generators to
determine whether there are any candidates for potential buy-out or other
remedial measures. The Company identified a 100-megawatt (MW) project now
under development that it believes is economically undesirable based on
current cost projections. In November 1993, at the NJBPU's direction, the
Company and the developer attempted to negotiate contract repricing to a level
more consistent with the Company's current avoided cost projections or a
contract buy-out but were unable to reach agreement. Pursuant to an NJBPU
order, hearings on whether the NJBPU should revoke or modify its 1992 order
approving the power purchase agreement are being held. The developer has
contested the NJBPU's authority in this matter in the federal courts. In
March 1994, the U.S. District Court granted the Company's motion to dismiss
the developer's complaint, holding that the federal courts did not have
jurisdiction. The developer has appealed the decision to the U.S. Court of
Appeals. Oral argument has been held and a decision is pending.
In January 1994, the NJBPU issued an order granting two nonutility
generators, having a total of 200 MW under contract with the Company, an
extension in the in-service date for projects originally scheduled to be
- 23 -<PAGE>
operational in 1997. The Company believes these contracts provide for
payments substantially in excess of current and future avoided cost
projections and in June 1994 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.
In January 1994, the Company issued an all source solicitation for the
short-term supply of energy and/or capacity to determine and evaluate the
availability of competitively priced power supply options. This solicitation
is expected to fulfill a significant part of the uncommitted sources
identified in the Company's supply plan at a cost significantly below the cost
of both replacement power and new generation. The Company has evaluated the
bids and has commenced contract negotiations.
In March 1994, a nonutility generation developer petitioned the NJBPU
for an order directing the Company to enter into a long-term contract to sell
the Company 200 MW of energy annually. The Company has appealed this
petition and the NJBPU has referred the matter to an Administrative Law Judge
for evidentiary hearings which have not yet begun.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 664 MW of capacity is currently in
service and an additional 533 MW are currently scheduled or anticipated to be
in service by 1999.
- 24 -<PAGE>
</FN>
</TABLE>
PART II
ITEM 1 - LEGAL PROCEEDINGS
Information concerning the current status of certain legal
proceedings instituted against the Company and its
affiliates as a result of the March 28, 1979 nuclear
accident at Unit 2 of the Three Mile Island nuclear
generating station discussed in Part I of this report in
Notes to Financial Statements is incorporated herein by
reference and made a part hereof.
ITEM 5 - OTHER EVENTS
In July 1994, the Nuclear Regulatory Commission ordered all
boiling water reactor owners to inspect, during their next
outage, the shroud inside the reactor vessel. Certain welds
in the shroud, which directs the flow of cooling water
through the fuel core, may be susceptible to cracking. On
September 10, 1994, the Company's Oyster Creek generating
station was taken out of service for a scheduled maintenance
and refueling outage. Examination during the outage has
identified significant cracks. The necessary modifications
are estimated to cost $6 million and is expected to extend
the outage by up to three weeks.
As previously reported, GPUN believes that the Oyster Creek
nuclear station will require additional on-site storage
capacity, beginning in 1996, in order to maintain its full
core reserve margin. Loss of the full core reserve margin
would mean that off-loading the entire core would not be
possible to conduct certain maintenance or repairs, when
necessary, in order to restore operation of the plant. In
March 1994, the Lacey Township Zoning Board of Adjustment
issued a use variance for the facility. In May 1994,
Berkeley Township and other parties appealed to the New
Jersey Superior Court to overturn the Lacey Township Zoning
Board decision. The Court has scheduled a trial for
December 8, 1994. Construction of the facility, which is
scheduled for completion in September 1995, is continuing
during the appeal process.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(12) Statements Showing Computation of Ratio of
Earnings to Fixed Charges and Ratio of
Earnings to Combined Fixed Charges and
Preferred Stock Dividends.
(27) Financial Data Schedule.
- 25 -<PAGE>
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
JERSEY CENTRAL POWER & LIGHT COMPANY
November 4, 1994 By: /s/ D. Baldassari
D. Baldassari, President
November 4, 1994 By: /s/ D. W. Myers
D W. Myers, Vice President -
Operations Support and Comptroller
(Principal Accounting Officer)
- 26 -<PAGE>
<TABLE>
Exhibit 12
Page 1 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
UNAUDITED
<CAPTION>
Nine Months Ended
September 30, 1993 September 30, 1994
<S> <C> <C>
OPERATING REVENUES $1 488 256 $1 513 634
OPERATING EXPENSES 1 215 819 1 254 597
Interest portion
of rentals (A) 8 009 8 284
Net expense 1 207 810 1 246 313
OTHER INCOME:
Allowance for funds
used during
construction 3 642 2 233
Other income, net 11 895 23 154
Total other income 15 537 25 387
EARNINGS AVAILABLE FOR FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS
(excluding taxes
based on income) $ 295 983 $ 292 708
FIXED CHARGES:
Interest on funded
indebtedness $ 75 856 $ 70 981
Other interest 4 362 12 011
Interest portion
of rentals (A) 8 009 8 284
Total fixed charges $ 88 227 $ 91 276
RATIO OF EARNINGS TO
FIXED CHARGES 3.35 3.21
Preferred stock dividend
requirement 13 111 11 096
Ratio of income before
provision for income
taxes to net income (B) 151.0% 151.6%
Preferred stock dividend
requirement on a pretax
basis 19 798 16 822
Fixed charges, as above 88 227 91 276
Total fixed charges
and preferred
stock dividends $ 108 025 $ 108 098
RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS 2.74 2.71<PAGE>
Exhibit 12
Page 2 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
UNAUDITED
<FN>
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 of $201,432 and
$207,756 for the nine months ended September 30, 1994 and September 30,
1993, respectively, divided by net income of $132,845 and $137,620,
respectively. <PAGE>
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> SEP-30-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,817,125
<OTHER-PROPERTY-AND-INVEST> 257,580
<TOTAL-CURRENT-ASSETS> 529,207
<TOTAL-DEFERRED-CHARGES> 817,757
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,421,669
<COMMON> 153,713
<CAPITAL-SURPLUS-PAID-IN> 435,715
<RETAINED-EARNINGS> 745,943
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,335,371
150,000
37,741
<LONG-TERM-DEBT-NET> 1,215,822
<SHORT-TERM-NOTES> 79,100
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 19,836
<LONG-TERM-DEBT-CURRENT-PORT> 20,009
0
<CAPITAL-LEASE-OBLIGATIONS> 5,012
<LEASES-CURRENT> 102,638
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,456,140
<TOT-CAPITALIZATION-AND-LIAB> 4,421,669
<GROSS-OPERATING-REVENUE> 1,513,634
<INCOME-TAX-EXPENSE> 58,942
<OTHER-OPERATING-EXPENSES> 1,254,597
<TOTAL-OPERATING-EXPENSES> 1,313,539
<OPERATING-INCOME-LOSS> 200,095
<OTHER-INCOME-NET> 13,688
<INCOME-BEFORE-INTEREST-EXPEN> 213,783
<TOTAL-INTEREST-EXPENSE> 80,938
<NET-INCOME> 132,845
11,096
<EARNINGS-AVAILABLE-FOR-COMM> 121,749
<COMMON-STOCK-DIVIDENDS> 100,000 <F1>
<TOTAL-INTEREST-ON-BONDS> 95,371
<CASH-FLOW-OPERATIONS> 230,277
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
