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 March 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 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
common stock, as of April 30, 1994, was as follows:
Common stock, par value $10 per share: 15,371,270 shares
outstanding.
Jersey Central Power & Light Company
Quarterly Report on Form 10-Q
March 31, 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 18
PART II - Other Information 22
Signatures 23
_________________________________
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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JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
In Thousands
March 31, December 31,
1994 1993
(Unaudited)
ASSETS
Utility Plant:
In service, at original cost $3 969 009 $3 938 700
Less, accumulated depreciation 1 414 845 1 380 540
Net utility plant in service 2 554 164 2 558 160
Construction work in progress 111 853 102 178
Other, net 127 446 116 751
Net utility plant 2 793 463 2 777 089
Current Assets:
Cash and temporary cash investments 63 555 17 301
Special deposits 7 124 7 124
Accounts receivable:
Customers, net 148 085 133 407
Other 47 405 31 912
Unbilled revenues 46 187 57 943
Materials and supplies, at average cost or less:
Construction and maintenance 103 328 102 659
Fuel 17 673 11 886
Deferred income taxes 17 772 28 650
Prepayments 14 373 58 057
Total current assets 465 502 448 939
Deferred Debits and Other Assets:
Three Mile Island Unit 2 deferred costs 137 133 146 284
Unamortized property losses 108 035 109 478
Deferred income taxes 113 036 110 794
Income taxes recoverable through
future rates 125 380 121 509
Decommissioning funds 156 304 139 279
Special deposits 83 821 82 103
Other 337 226 333 680
Total deferred debits and other assets 1 060 935 1 043 127
Total Assets $4 319 900 $4 269 155
<FN>
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
In Thousands
March 31, December 31,
1994 1993
(Unaudited)
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 435 715 435 715
Retained earnings 733 592 724 194
Total common stockholder's equity 1 323 020 1 313 622
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 37 741 37 741
Long-term debt 1 215 727 1 215 674
Total capitalization 2 726 488 2 717 037
Current Liabilities:
Debt due within one year 60 008 60 008
Obligations under capital leases 85 823 89 631
Accounts payable:
Affiliates 20 872 34 538
Other 119 704 95 509
Taxes accrued 152 907 119 337
Deferred energy credits 14 586 23 633
Interest accrued 29 483 33 804
Other 55 211 50 950
Total current liabilities 538 594 507 410
Deferred Credits and Other Liabilities:
Deferred income taxes 574 217 569 966
Unamortized investment tax credits 76 894 79 902
Three Mile Island Unit 2 future costs 79 818 79 967
Other 323 889 314 873
Total deferred credits and other liabilities 1 054 818 1 044 708
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 319 900 $4 269 155
<FN>
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Income
(Unaudited)
In Thousands
Three Months
Ended March 31,
1994 1993
Operating Revenues $486 910 $448 634
Operating Expenses:
Fuel 30 325 21 389
Power purchased and interchanged:
Affiliates 2 834 4 319
Others 144 714 150 617
Deferral of energy and capacity
costs, net (8 777) 6 323
Other operation and maintenance 118 136 103 295
Depreciation and amortization 47 759 44 550
Taxes, other than income taxes 59 144 55 017
Total operating expenses 394 135 385 510
Operating Income Before Income Taxes 92 775 63 124
Income taxes 21 254 11 713
Operating Income 71 521 51 411
Other Income and Deductions:
Allowance for other funds used
during construction 57 738
Other income, net 15 434 4 496
Income taxes (5 537) (1 789)
Total other income
and deductions 9 954 3 445
Income Before Interest Charges 81 475 54 856
Interest Charges:
Interest on long-term debt 23 715 23 934
Other interest 5 313 918
Allowance for borrowed funds used
during construction (650) (826)
Total interest charges 28 378 24 026
Net Income 53 097 30 830
Preferred stock dividends 3 699 4 706
Earnings Available for Common Stock $ 49 398 $ 26 124
<FN>
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Cash Flows
(Unaudited)
In Thousands
Three Months
Ended March 31,
1994 1993
Operating Activities:
Income before preferred dividends $ 53 097 $ 30 830
Adjustments to reconcile income to cash provided:
Depreciation and amortization 52 974 47 448
Amortization of property under capital leases 8 605 7 890
Nuclear outage maintenance costs, net 5 609 (13 831)
Deferred income taxes and investment tax
credits, net 9 277 19 054
Deferred energy and capacity costs, net (8 840) 6 323
Accretion income (3 388) (3 628)
Allowance for other funds used during construction (57) (738)
Changes in working capital:
Receivables (18 439) (26 742)
Materials and supplies (6 456) 2 793
Special deposits and prepayments 43 685 7 128
Payables and accrued liabilities 27 749 9 533
Other, net (14 148) (2 227)
Net cash provided by operating activities 149 668 83 833
Investing Activities:
Cash construction expenditures (46 552) (48 472)
Contributions to decommissioning trust (4 453) (4 521)
Other, net (2 178) (3 941)
Net cash used for investing activities (53 183) (56 934)
Financing Activities:
Issuance of long-term debt - 129 148
Decrease in notes payable, net - (5 700)
Capital lease principal payments (6 532) (4 348)
Dividends paid on common stock (40 000) -
Dividends paid on preferred stock (3 699) (4 706)
Net cash (required) provided
by financing activities (50 231) 114 394
Net increase in cash and temporary cash
investments from above activities 46 254 141 293
Cash and temporary cash investments,
beginning of year 17 301 140
Cash and temporary cash investments, end of period $ 63 555 $141 433
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 32 708 $ 23 208
Income taxes paid $ 76 $ 130
New capital lease obligations incurred $ 2 931 $ 698
<FN>
The accompanying notes are an integral part of the financial statements.
-6-
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). In April 1994,
General Portfolios Corporation (GPC) merged into EI, formerly a subsidiary of
GPC. 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 GPC 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 March 31, 1994, the Company's net investment in
TMI-1 and Oyster Creek, including nuclear fuel, was $170 million and
$796 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 and safety standards and experience gained in the
construction and operation of nuclear facilities. The Company and its
affiliates may also incur costs and experience reduced output at their nuclear
plants because of the design criteria prevailing at the time of construction
and the age of the plants' systems and equipment. In addition, for economic
or other reasons, operation of these plants for the full term of their now
assumed lives cannot be assured. Also, not all risks associated with
ownership or operation of nuclear facilities may be adequately insured or
insurable. Consequently, the ability of electric utilities to obtain adequate
and timely recovery of costs associated with nuclear projects, including
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1. COMMITMENTS AND CONTINGENCIES (continued)
replacement power, any unamortized investment at the end of the plants' useful
life (whether scheduled or premature), the carrying costs of that investment
and retirement costs, is not assured. Management intends, in general, to seek
recovery of any such costs described above through the ratemaking process, but
recognizes that recovery is not assured.
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990. After receiving Nuclear Regulatory
Commission (NRC) approval, TMI-2 entered into long-term monitored storage in
December 1993.
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 (the Court). 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 Price-Anderson Act, 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, which is
the ceiling established by the Price-Anderson Act on the aggregate public
liability that may be imposed upon them for the TMI-2 accident.
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, on March 30, 1994, that the insurers would withdraw their reservation
of rights.
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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 twelve allegedly representative
cases is scheduled to begin in October 1994. On February 18, 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 on February 18, 1994,
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 an Order issued April 20, 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) denied the defendants' motions for
interlocutory appeal of the Court's Orders of February 18, 1994, stating 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 1993 dollars) for
TMI-1 is $143 million, of which the Company's share is $36 million, and for
Oyster Creek is $175 million. Based on NRC studies, a comparable funding
target for TMI-2 (in 1993 dollars), which takes into account the accident, is
$228 million, of which the Company's share is $57 million. The NRC is
currently studying the levels of these funding targets. Management cannot
predict the effect that the results of this review will have on the funding
targets. NRC regulations and a regulatory guide provide mechanisms, including
exemptions, to adjust the funding targets over their collection periods to
reflect increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not actual cost
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1. COMMITMENTS AND CONTINGENCIES (continued)
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $205 to $285 million, of which the Company's share is $51
to $71 million, and $220 to $320 million, respectively (adjusted to 1993
dollars). In addition, the studies estimated the cost of removal of
nonradiological structures and materials for TMI-1 and Oyster Creek at
$72 million, of which the Company's share is $18 million, and $47 million,
respectively.
The ultimate cost of retiring the Company and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies and cannot now be more
reasonably estimated than the level of the NRC funding target because such
costs are subject to (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time
of decommissioning. The Company charges to expense and contributes to
external trusts amounts collected from customers for nuclear plant
decommissioning and nonradiological costs. In addition, in 1990 the Company
contributed to an external trust an amount not recoverable from customers for
nuclear plant decommissioning.
TMI-1 AND OYSTER CREEK:
The Company is collecting revenues for decommissioning, which are
expected to result in the accumulation of its share of the NRC funding target
for each plant. The Company is also collecting revenues for the cost of
removal of nonradiological structures and materials at each plant based on its
share ($3.83 million) of an estimated $15.3 million for TMI-1 and
$31.6 million for Oyster Creek. Collections from customers for
decommissioning expenditures are deposited in external trusts and are
classified as Decommissioning Funds 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
$14 million for TMI-1 and $84 million for Oyster Creek at March 31, 1994.
These decommissioning 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 ratemaking process.
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1. COMMITMENTS AND CONTINGENCIES (continued)
TMI-2:
The Company and its affiliates have recorded a liability, amounting to
$229 million, of which the Company's share is approximately $57 million as of
March 31, 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. Such costs are expected to be
incurred between 1994 and 2014, when decommissioning is forecast to begin. In
addition, the Company and its affiliates have a remaining liability in the
amount of $70 million, of which the Company's share is approximately
$17.5 million, for nonradiological cost of removal. The Company's share of
the above amounts for retirement costs and monitored storage are reflected as
Three Mile Island Unit 2 Future Costs on the balance sheet. The Company has
made a nonrecoverable contribution of $15 million to an external
decommissioning trust. Earnings resulting from decommissioning funds are
offset against amounts collectible from customers in Three Mile Island Unit 2
Deferred Costs on the balance sheet.
The New Jersey Board of Regulatory Commissioners (NJBRC) has granted the
Company decommissioning revenues for the remainder of the NRC funding target
and allowances for the cost of removal of nonradiological structures and
materials. Management intends to seek recovery for any increases in TMI-2
retirement costs, but recognizes that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage, the Company
and its affiliates are incurring incremental annual storage costs of
$1 million, of which the Company's share is $.25 million. The Company and its
affiliates have deferred the $20 million, of which the Company's share is
$5 million, for the total estimated incremental costs attributable to
monitored storage through 2014, the expected retirement date of TMI-1. The
Company's share of these costs has been recognized in rates by the NJBRC.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the Company.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered
one site for insurance purposes) and for Oyster Creek totals $2.7 billion per
site. In accordance with NRC regulations, these insurance policies generally
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1. COMMITMENTS AND CONTINGENCIES (continued)
require that proceeds first be used to stabilize the reactors and then to pay
for decontamination and debris removal expenses. Any remaining amounts
available under the policies may then be used for repair and restoration costs
and decommissioning costs. Consequently, there can be no assurance that, in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of the stations.
The Price-Anderson Act limits the GPU System's liability to third parties
for a nuclear incident at one of its sites to approximately $9.4 billion.
Coverage for the first $200 million of such liability is provided by private
insurance. The remaining coverage, or secondary protection, is provided by
retrospective premiums payable by all nuclear reactor owners. Under secondary
protection, a nuclear incident at any licensed nuclear power reactor in the
country, including those owned by the GPU System, could result in assessments
of up to $79 million per incident for each of the GPU System's three reactors,
subject to an annual maximum payment of $10 million per incident per reactor.
In 1993, GPUN requested an exemption from the NRC to eliminate the secondary
protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at their
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years at decreasing levels beginning at $1.8 million for
Oyster Creek and $2.6 million for TMI-1, per week.
Under their insurance policies applicable to nuclear operations and
facilities, the Company and its affiliates are subject to retrospective
premium assessments of up to $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 cost of which could be material. Management
intends to seek recovery through the ratemaking process for any additional
costs, but recognizes that recovery cannot be assured.
To comply with the federal Clean Air Act Amendments of 1990 (Clean Air
Act), the Company expects to expend up to $58 million for air pollution
control equipment by the year 2000. The Company reduced the estimate from
$145 million to $58 million primarily due to the postponement of a scrubber
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1. COMMITMENTS AND CONTINGENCIES (continued)
installation at the Keystone generating station until after 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. Costs
associated with the capital invested in this equipment and the increased
operating costs of the Company's affected station should be recoverable
through the ratemaking process.
The Company has been notified by the Environmental Protection Agency
(EPA) and a state environmental authority that it is among the potentially
responsible parties (PRPs) who may be jointly and severally liable to pay for
the costs associated with the investigation and remediation at six hazardous
and/or toxic waste sites. In addition, the Company has been requested to
supply information to the EPA and state environmental authorities on several
other sites for which it has not yet been named as a PRP. The ultimate cost
of remediation will depend upon changing circumstances as site investigations
continue, including (a) the existing technology required for site cleanup,
(b) the remedial action plan chosen and (c) the extent of site contamination
and the portion attributed to the Company.
The Company has entered into agreements with the New Jersey Department of
Environmental Protection and Energy for the investigation and remediation of
17 formerly owned manufactured gas plant sites. One of these sites has been
repurchased by the Company. The Company has also entered into various cost
sharing agreements with other utilities for some of the sites. At March 31,
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 NJBRC approved a mechanism for the recovery of future
manufactured gas plant remediation costs through the Company's Levelized
Energy Adjustment Clause (LEAC) when expenditures exceed prior collections.
The NJBRC decision provides for interest to be credited to customers until the
overrecovery is eliminated and for future costs to be amortized over seven
years with interest. At March 31, 1994, the Company has collected from
customers $4.6 million in excess of expenditures of $13.3 million. The
Company is awaiting a final NJBRC order. The Company is pursuing
reimbursement of the above costs from its insurance carriers, and will seek to
recover costs to the extent not covered by insurance through this mechanism.
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1. COMMITMENTS AND CONTINGENCIES (continued)
The Company is unable to estimate the extent of possible remediation and
associated costs of additional environmental matters. Also unknown are the
consequences of environmental issues, which could cause the postponement or
cancellation of either the installation or replacement of utility plant.
Management believes the costs described above should be recoverable through
the ratemaking process.
OTHER COMMITMENTS AND CONTINGENCIES
In April 1994, GPU announced it was offering a voluntary enhanced
retirement program to certain nonbargaining employees. In addition, in April
1994, Penelec's bargaining units were offered, and accepted, a similar
enhanced retirement program. The Company and Met-Ed are negotiating with
their respective unions with respect to possible participation of bargaining
unit employees in similar enhanced retirement programs. The enhanced
retirement programs are part of a corporate realignment that was 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. If two-thirds of the
anticipated eligible bargaining and nonbargaining employees were to accept the
offer, depending upon the age and years of service of those employees, the
program could result in a 1994 pretax charge to earnings for the GPU System of
between $110 million and $120 million.
The NJBRC has instituted a generic proceeding to address the appropriate
recovery of capacity costs associated with electric utility power purchases
from nonutility generation projects. The proceeding was initiated, in part,
to respond to contentions of the New Jersey Public Advocate, Division of Rate
Counsel (Rate Counsel), that by permitting utilities to recover such costs
through the LEAC, an excess or "double recovery" may result when combined with
the recovery of the utilities' embedded capacity costs through their base
rates. In 1993, the Company and the other New Jersey electric utilities filed
motions for summary judgment with the NJBRC requesting that the NJBRC dismiss
contentions being made by Rate Counsel that adjustments for alleged "double
recovery" in prior periods are warranted. Rate Counsel has filed a brief in
opposition to the utilities' summary judgment motions including a statement
from its consultant that in his view, the "double recovery" for the Company
for the 1988-92 LEAC periods would be approximately $102 million. In February
1994, the NJBRC ruled that the 1991 LEAC period was considered closed but
subsequent periods remain open for further investigation. It is anticipated
that the proceeding will be transmitted to the Office of Administrative Law
for further action. Management estimates that the potential exposure for LEAC
periods subsequent to 1991 is approximately $33 million through February 1995,
the end of the current LEAC period. Management is unable to estimate the
outcome of this proceeding.
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:
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1. COMMITMENTS AND CONTINGENCIES (continued)
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. 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 all of the power produced
up to the contract limits. The agreements have been approved by the
NJBRC and permit the Company to recover energy and demand costs from customers
through its energy clause. These agreements provide for the sale of
approximately 1,194 MW of capacity and energy to the Company by the mid-to-
late 1990s. As of March 31, 1994, facilities covered by these agreements
having 661 MW of capacity were in service, and 215 MW are scheduled to
commence operation in 1994. Payments pursuant to agreements with nonutility
generators are estimated to aggregate $325 million for 1994. The price of the
energy and capacity to be purchased under these agreements is determined by
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1. COMMITMENTS AND CONTINGENCIES (continued)
the terms of the contracts. The rates payable under a number of these
agreements are substantially in excess of current market prices. While the
Company has been granted full recovery of these costs from customers by the
NJBRC, there can be no assurance that the Company will continue to be able to
recover these costs throughout the terms of the related contracts. The
emerging competitive market has created additional uncertainty regarding the
forecasting of the GPU System's energy supply needs which, in turn, has caused
the Company and its affiliates to change their supply strategy to seek shorter
term agreements offering more flexibility. At the same time, the Company and
its affiliates are attempting to renegotiate, and in some cases buy out, high
cost long-term nonutility generation contracts where opportunities arise. The
extent to which the Company and its affiliates may be able to do so, however,
or recover associated costs through rates, is uncertain. Moreover, these
efforts have led to disputes before the NJBRC, as well as to litigation, and
may result in claims against the Company for substantial damages. There can
be no assurance as to the outcome of these matters.
The Company's two operating nuclear units are subject to the NJBRC's
annual nuclear performance standard. Operation of these units at an aggregate
annual generating capacity factor below 65% or above 75% would trigger a
charge or credit based on replacement energy costs. At current cost levels,
the maximum annual effect on net income of the performance standard charge at
a 40% capacity factor would be approximately $10 million. While a capacity
factor below 40% would generate no specific monetary charge, it would require
the issue to be brought before the NJBRC for review. The annual measurement
period, which begins in March of each year, coincides with that used for the
LEAC.
During the normal course of the operation of its business, in addition to
the matters described above, the Company is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by customers, contractors,
vendors and other suppliers of equipment and services and by both current and
former employees alleging unlawful employment practices. It is not expected
that the outcome of these matters will have a material effect on the Company's
financial position or results of operations.
2. INCOME TAXES
In March 1994, as a result of a settlement of a federal income tax refund
claims for 1986, the Company and its affiliates recorded net income tax
refunds aggregating $17 million, of which the Company's share is $4 million,
based on the retirement of TMI-2 for tax purposes.
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2. INCOME TAXES (continued)
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 is
$11.5 million, representing net interest receivable from the Internal Revenue
Service (IRS) associated with this refund settlement. While the Company
intends to refund the tax refund amount to its customers, the ultimate
disposition of the income tax refund and the associated net interest is
subject to regulatory review. Income tax amounts refunded will have no effect
on net income.
In addition, in April 1994, audits of the Company and its affiliates'
federal income tax returns for the years 1987 through 1989 were settled with
the IRS. Exclusive of the effects of the TMI-2 retirement mentioned above,
these settlements had no material effect on the financial position or results
of operations of the Company.
3. ACCOUNTING POLICIES
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115 (FAS 115) "Accounting for Certain Investments in
Debt and Equity Securities", which addresses the accounting and reporting for
investments in equity securities that have readily determinable fair values
and for all investments in debt securities. The adoption of FAS 115 did not
have a material effect on the financial position of the Company.
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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 first quarter ended March 31,
1994 were $49.4 million compared with $26.1 million for the first quarter of
1993. The increase in earnings for the quarter was primarily due to increased
revenues resulting from a February 1993 retail base rate increase, increased
sales due to colder-than-normal winter weather as compared with last year's,
and 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). Earnings also increased due to a performance award of $7.8 million
for the operation of the Company's nuclear generating stations. These
increases were partially offset by increased operation and maintenance expense
due primarily to emergency and storm repairs caused by winter storms.
REVENUES:
Total revenues for the first quarter of 1994 increased 8.5% to
$486.9 million. The components of this change are as follows:
(In Millions)
Kilowatt-hour (KWh) revenues
(excluding energy portion) $ 16.3
Rate increase 20.8
Energy revenues (2.0)
Other revenues 3.2
Increase in revenues $ 38.3
Kilowatt-hour revenues
KWh revenues increased for the quarter ended March 31, 1994 primarily due
to increased sales resulting from the significantly colder-than-normal winter
temperatures as compared with last year. An increase in new customers also
contributed to the increase.
Energy revenues
Changes in energy revenues do not affect net income 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
the energy cost rates in effect, decreased sales to other utilities and the
loss of wholesale customers. These decreases were partially offset by
increased sales to ultimate customers.
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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, reduced
reserve capacity expense resulting from the expiration of purchase contracts
with other utilities favorably impacted earnings in the first quarter.
Other operation and maintenance
Other operation and maintenance expense increased primarily due to
emergency and storm repairs caused by winter storms.
Taxes other than income taxes
Generally, changes in taxes other than income taxes do not significantly
affect earnings as these taxes are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income, net
The increase in other income, net is attributable to 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 in which TMI-2 was retired, and resulted in additional amounts
owed for subsequent tax years in which depreciation deductions with respect to
TMI-2 had been taken. The net effect on pretax earnings of these refunds for
the tax retirement of TMI-2 was an increase of $11.3 million resulting from an
increase in interest income of $14.7 million partially offset by an increase
in interest expense of $3.4 million.
INTEREST CHARGES:
Other interest increased primarily due to the tax retirement of TMI-2
that 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.
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LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs were $47 million for cash construction
expenditures in the first quarter of 1994. Construction expenditures for the
year are currently forecasted to be $281 million. Construction estimates for
ongoing system development are expected to remain stable over the next five
years. Expenditures for maturing debt are expected to be $60 million for
1994. Management estimates that approximately one-half of the capital needs
in 1994 will be satisfied through internally generated funds.
FINANCING:
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.
COMPETITION:
In April 1994, GPU announced it was offering a voluntary enhanced
retirement program to certain nonbargaining employees. In addition, in April
1994, Penelec's bargaining units were offered and accepted a similar enhanced
retirement program. The Company and Met-Ed are negotiating with their
respective unions with respect to possible participation of bargaining unit
employees in similar enhanced retirement programs. The enhanced retirement
programs are part of a corporate realignment that was 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. If two-thirds of the anticipated
eligible bargaining and nonbargaining employees were to accept the offer,
depending upon the age and years of service of those employees, the program
could result in a 1994 pretax charge to earnings for the GPU System of between
$110 million and $120 million.
MEETING ENERGY DEMANDS:
In 1993, the New Jersey Board of Regulatory Commissioners (NJBRC) asked
all electric utilities in the state to assess the economics of their purchase
power contracts with nonutility generators to determine whether there were 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, the NJBRC directed the Company and the developer to attempt to negotiate
contract repricing to a level more consistent with the Company's current
avoided cost projections or a contract buy-out. The Company and the developer
have not been able to reach an agreement, and pursuant to an NJBRC order,
hearings on this matter are being held. The developer is contesting the
NJBRC's jurisdiction in this matter in the federal courts.
In January 1994, the NJBRC issued an order granting two nonutility
generators, having a total of 200 MW under contract with the Company, a
one-year extension in the in-service date for projects originally scheduled to
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be operational in 1997. The Company has filed a motion for reconsideration of
that order, which is pending before the NJBRC. The Company intends to appeal
the order if its motion is not granted.
In January 1994, the Company issued an all source solicitation for the
short-term supply of energy and/or capacity to determine and evaluate the
availability of competitively priced power supply options. The Company is
seeking proposals from utility and nonutility generation suppliers, for
periods of one to eight years in length, that are capable of delivering
electric power beginning in 1996. This solicitation is expected to fulfill a
significant part of the uncommitted sources identified in the Company's supply
plan. The Company has received bids and has begun the evaluation process.
The NJBRC has approved an agreement among the Company, the NJBRC staff,
and a nonutility generator under which the Company has agreed to buy out a
power purchase agreement for $2 million. In its order, the NJBRC has allowed
the Company to recover $1.2 million of the purchase price, together with a
return thereon, through the Company's Levelized Energy Adjustment Clause.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 661 MW of capacity is currently in
service and an additional 533 MW are currently scheduled or anticipated to be
in service by 1998.
ENVIRONMENTAL ISSUES:
To comply with the federal Clean Air Act Amendments of 1990 (Clean Air
Act), the Company expects to expend up to $58 million for air pollution
control equipment by the year 2000. The estimate was reduced from $145
million primarily due to the postponement of a scrubber installation at the
Keystone generating station until after 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. Costs associated with the capital
invested in this equipment and the increased operating costs of the affected
station are expected to be recoverable through the ratemaking process.
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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
As previously reported, GPUN believes that the Company's Oyster
Creek nuclear station 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, but that additional on-site storage capacity
will be required beginning in 1996 in order to maintain the full
core reserve margin. Loss of the full core reserve margin means
that off-loading the entire core will not be possible to conduct
certain maintenance or repairs, when necessary, in order to
restore operation of the plant. Contract commitments with an
outside vendor have been made for the construction of incremental
spent fuel dry storage capacity need for the period 1996 to 1998
at an estimated cost of $16 million. In March 1994, GPUN
received approval from the Lacey Township Zoning Board to build
the storage facility. The construction proposal is also
contingent upon GPUN meeting certain other requirements including
Nuclear Regulatory Commission Approval and licensing. GPUN
expects to receive the remaining authorizations necessary by
October 1994.
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.
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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
May 5, 1994 By: /s/ D. Baldassari
D. Baldassari, President
May 5, 1994 By: /s/ P. H. Preis
P. H. Preis, Vice President and Comptroller
(Principal Accounting Officer)
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