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, 1995
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 October 31, 1995, was as follows:
Common stock, par value $10 per share: 15,371,270 shares
outstanding.
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Jersey Central Power & Light Company
Quarterly Report on Form 10-Q
September 30, 1995
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 20
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 Consolidated Financial Statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
Consolidated Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $4 243 760 $4 119 617
Less, accumulated depreciation 1 630 308 1 499 405
Net utility plant in service 2 613 452 2 620 212
Construction work in progress 168 371 136 884
Other, net 112 357 123 349
Net utility plant 2 894 180 2 880 445
Other Property and Investments:
Nuclear decommissioning trusts 208 274 165 511
Nuclear fuel disposal fund 92 799 82 920
Other, net 7 053 6 906
Total other property and investments 308 126 255 337
Current Assets:
Cash and temporary cash investments 8 226 1 041
Special deposits 7 361 4 608
Accounts receivable:
Customers, net 162 041 126 760
Other 14 686 16 936
Unbilled revenues 53 318 59 288
Materials and supplies, at average cost or less:
Construction and maintenance 97 019 95 937
Fuel 18 523 18 563
Deferred energy costs 11 164 (148)
Deferred income taxes 10 616 10 454
Prepayments 82 237 45 880
Total current assets 465 191 379 319
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 126 831 138 294
Unamortized property losses 101 064 104 451
Income taxes recoverable through future rates 143 900 132 642
Other 312 533 309 230
Total regulatory assets 684 328 684 617
Deferred income taxes 126 494 122 944
Other 18 478 13 978
Total deferred debits and other assets 829 300 821 539
Total Assets $4 496 797 $4 336 640
The accompanying notes are an integral part of the consolidated financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
Consolidated Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 450 769 435 715
Retained earnings 834 721 772 240
Total common stockholder's equity 1 439 203 1 361 668
Cumulative preferred stock:
With mandatory redemption 134 000 150 000
Without mandatory redemption 37 741 37 741
Company-obligated mandatorily
redeemable preferred securities 125 000 -
Long-term debt 1 192 890 1 168 444
Total capitalization 2 928 834 2 717 853
Current Liabilities:
Securities due within one year 83 140 47 439
Notes payable 37 381 110 356
Obligations under capital leases 90 607 102 059
Accounts payable:
Affiliates 30 186 34 283
Other 96 391 118 369
Taxes accrued 8 421 22 561
Interest accrued 30 285 29 765
Other 103 426 75 159
Total current liabilities 479 837 539 991
Deferred Credits and Other Liabilities:
Deferred income taxes 615 709 598 843
Unamortized investment tax credits 68 642 72 928
Three Mile Island Unit 2 future costs 86 693 85 273
Regulatory liabilities 38 979 41 732
Other 278 103 280 020
Total deferred credits and
other liabilities 1 088 126 1 078 796
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 496 797 $4 336 640
The accompanying notes are an integral part of the consolidated financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
Consolidated Statements of Income
(Unaudited)
<CAPTION>
In Thousands
Three Months Nine Months
Ended September 30, Ended September 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $625 479 $567 827 $1 546 594 $1 513 634
Operating Expenses:
Fuel 33 454 25 950 74 263 80 597
Power purchased and interchanged:
Affiliates 9 854 8 068 13 222 13 194
Others 182 420 157 519 493 698 437 082
Deferral of energy and capacity
costs, net (355) 832 (10 746) (8 211)
Other operation and maintenance 114 888 126 864 341 265 412 850
Depreciation and amortization 49 150 46 943 145 111 141 104
Taxes, other than income taxes 65 421 64 773 171 298 177 981
Total operating expenses 454 832 430 949 1 228 111 1 254 597
Operating Income Before Income Taxes 170 647 136 878 318 483 259 037
Income taxes 51 190 37 574 79 965 58 942
Operating Income 119 457 99 304 238 518 200 095
Other Income and Deductions:
Allowance for other funds used
during construction 399 70 856 179
Other income, net 3 728 3 557 10 713 23 154
Income taxes (1 491) (2 438) (4 273) (9 645)
Total other income
and deductions 2 636 1 189 7 296 13 688
Income Before Interest Charges and
Dividends on Preferred Securities 122 093 100 493 245 814 213 783
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 23 461 23 579 69 421 70 981
Other interest 2 161 3 140 7 684 12 011
Allowance for borrowed funds used
during construction (1 651) (799) (3 698) (2 054)
Dividends on company-obligated
mandatorily redeemable
preferred securities 2 675 - 3 953 -
Total interest charges and dividends
on preferred securities 26 646 25 920 77 360 80 938
Net Income 95 447 74 573 168 454 132 845
Preferred stock dividends 3 586 3 698 10 871 11 096
Earnings Available for Common Stock $ 91 861 $ 70 875 $ 157 583 $ 121 749
The accompanying notes are an integral part of the consolidated financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
<CAPTION>
In Thousands
Nine Months
Ended September 30,
1995 1994
<S> <C> <C>
Operating Activities:
Net income $ 168 454 $ 132 845
Adjustments to reconcile income to cash provided:
Depreciation and amortization 157 747 155 433
Amortization of property under capital leases 24 342 23 883
Voluntary enhanced retirement programs - 46 862
Nuclear outage maintenance costs, net 12 588 (1 507)
Deferred income taxes and investment tax
credits, net 16 733 11 860
Deferred energy and capacity costs, net (10 814) (8 008)
Accretion income (9 390) (10 156)
Allowance for other funds used
during construction (856) (179)
Changes in working capital:
Receivables (27 061) 20 345
Materials and supplies (1 042) (1 890)
Special deposits and prepayments (39 111) (141 905)
Payables and accrued liabilities (55 906) 10 279
Other, net (32 120) (7 585)
Net cash provided by operating activities 203 564 230 277
Investing Activities:
Cash construction expenditures (158 272) (146 400)
Contributions to decommissioning trusts (13 523) (12 719)
Other, net (3 153) (9 757)
Net cash used for investing activities (174 948) (168 876)
Financing Activities:
Issuance of long-term debt 49 625 -
Increase (decrease) in notes payable, net (73 100) 99 100
Retirement of long-term debt (9) (40 008)
Capital lease principal payments (21 978) (25 745)
Redemption of preferred stock (6 049) -
Issuance of company-obligated mandatorily
redeemable preferred securities 121 063 -
Dividends paid on common stock (95 000) (100 000)
Dividends paid on preferred stock (10 983) (11 096)
Contributions from parent corporation 15 000 -
Net cash required by financing activities (21 431) (77 749)
Net increase (decrease) in cash and temporary cash
investments from above activities 7 185 (16 348)
Cash and temporary cash investments,
beginning of year 1 041 17 301
Cash and temporary cash investments, end of period $ 8 226 $ 953
Supplemental Disclosure:
Interest paid $ 78 411 $ 85 400
Income taxes paid $ 78 675 $ 25 482
New capital lease obligations incurred $ 11 377 $ 34 935
The accompanying notes are an integral part of the consolidated financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was
incorporated under the laws of New Jersey in 1925, is a wholly owned
subsidiary of General Public Utilities Corporation (GPU), a holding company
registered under the Public Utility Holding Company Act of 1935. The Company
owns all of the common stock of JCP&L Preferred Capital, Inc., which is the
general partner of JCP&L Capital L.P., a special purpose finance subsidiary.
The Company's business is the generation, transmission, distribution and sale
of electricity. The Company is affiliated with Metropolitan Edison Company
(Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and
Penelec are referred to herein as the "Company and its affiliates". The
Company is also affiliated with GPU Service Corporation (GPUSC), a service
company; GPU Nuclear Corporation (GPUN), which operates and maintains the
nuclear units of the Company and its affiliates; and Energy Initiatives, Inc.,
EI Power, Inc., and EI Energy, Inc. (collectively, EI), which develop, own and
operate generating, transmission and distribution facilities in the United
States and in foreign countries. 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 1994 Annual Report on Form 10-K. The year-end
condensed balance sheet data contained in the attached financial statements
was derived from audited financial statements. For disclosures required by
generally accepted accounting principles, see the 1994 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. TMI-1 and TMI-2 are jointly owned by the Company,
Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively.
Oyster Creek is owned by the Company. At September 30, 1995 and December 31,
1994, the Company's net investment in TMI-1 and Oyster Creek, including
nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 Oyster Creek
September 30, 1995 $167 $778
December 31, 1994 $162 $817
The Company's net investment in TMI-2 at September 30, 1995 and December
31, 1994 was $86 million and $89 million, respectively. The Company is
collecting retail revenues for TMI-2 on a basis which provides for the
recovery of its remaining investment in the plant by 2008.
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
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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
replacement power, any unamortized investment at the end of each plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and after receiving 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, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the United
States District Court for the Middle District of Pennsylvania. Some of the
claims also seek recovery for injuries from alleged emissions of radioactivity
before and after the accident.
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 up to an aggregate of $335 million in
premium charges under such plan, and (c) an indemnity agreement with the NRC
for up to $85 million, bringing their total primary, secondary and tertiary
financial protection up to an aggregate of $560 million. Under the secondary
level, the Company and its affiliates are subject to a retrospective premium
charge of up to $5 million per reactor, or a total of $15 million, of which
the Company's share is $7.5 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers (the defendants) under a reservation of rights with respect to
any award of punitive damages. However, in March 1994, the defendants in the
TMI-2 litigation and the insurers agreed that the insurers would withdraw
their reservation of rights with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
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cases is scheduled to begin in June 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.
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.
In October 1995, the U.S. Court of Appeals for the Third Circuit ruled
that the Price-Anderson Act provides coverage under its primary and secondary
levels for punitive as well as compensatory damages, but that punitive damages
could not be recovered against the Federal Government. In so doing, the Court
of Appeals referred to the "finite fund" (the $560 million of financial
protection under the Price-Anderson Act) to which plaintiffs must resort to
get compensatory as well as punitive damages.
The Court of Appeals also found that the standard of care owed by the
defendants to a plaintiff was determined by the specific level of radiation
which was released into the environment, as measured at the site boundary,
rather than as measured at the specific site where the plaintiff was located
at the time of the accident (as GPU and the Company and its affiliates
proposed). The Court of Appeals also held, however, that each plaintiff still
must demonstrate exposure to radiation released during the TMI-2 accident and
that such exposure had resulted in injuries.
GPU and the Company and its affiliates believe that any liability to
which they might be subject by reason of the TMI-2 accident and these Court of
Appeals decisions will not exceed the financial protection under the Price-
Anderson Act. GPU and the Company and its affiliates have filed a petition
with the Third Circuit Court seeking a rehearing and en banc reconsideration
of its decision that punitive damages are recoverable under the Price-Anderson
Act.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE).
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's remaining in long-term storage and being
decommissioned at the same time as TMI-1. Under the NRC regulations, the
funding targets (in 1995 dollars) for TMI-1 are $157 million, of which the
Company's share is $39 million, and $189 million for Oyster Creek. Based on
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NRC studies, a comparable funding target for TMI-2 has been developed which
takes the accident into account (see TMI-2 Future Costs). The NRC continues
to study the levels of these funding targets. Management cannot predict the
effect that the results of this review will have on the funding targets. NRC
regulations and a regulatory guide provide mechanisms, including exemptions,
to adjust the funding targets over their collection periods to reflect
increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not considered cost
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $225 million to $309 million, of which the Company's share
would range from $56 million to $77 million, and $239 million to $350 million,
respectively (in 1995 dollars). In addition, the studies estimated the cost
of removal of nonradiological structures and materials for TMI-1 and Oyster
Creek at $74 million, of which the Company's share is $18 million, and $48
million, respectively (in 1995 dollars).
The ultimate cost of retiring the Company's and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies. Such costs are subject to
(a) the type of decommissioning plan selected, (b) the escalation of various
cost elements (including, but not limited to, general inflation), (c) the
further development of regulatory requirements governing decommissioning,
(d) the absence to date of significant experience in decommissioning such
facilities and (e) the technology available at the time of decommissioning.
The Company and its affiliates charge to expense and contribute to external
trusts amounts collected from customers for nuclear plant decommissioning and
nonradiological costs. In addition, the Company has contributed amounts
written off for TMI-2 nuclear plant decommissioning in 1990 to TMI-2's
external trust (see TMI-2 Future Costs). Amounts deposited in external
trusts, including the interest earned on these funds, are classified as
Nuclear Decommissioning Trusts on the Balance Sheet.
In August 1995, a consultant to GPUN commenced site specific studies of
the TMI site, including both Units 1 and 2, and Oyster Creek. GPUN expects
these studies to be completed in the fourth quarter of 1995.
The Financial Accounting Standards Board (FASB) is reviewing the utility
industry's accounting practices for nuclear plant retirement costs. If the
FASB's tentative conclusions are adopted, Oyster Creek and TMI-1 future
retirement costs will have to be recognized as a liability currently, rather
than recorded over the life of the plants (as is currently the practice), with
an offsetting asset recorded for amounts collectible through rates. Any
amounts not collectible through rates will have to be charged to expense. The
FASB is expected to release an Exposure Draft on decommissioning accounting
practices in the fourth quarter of 1995.
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TMI-1 and Oyster Creek:
The Company is collecting revenues for decommissioning, which are
expected to result in the accumulation of its share of the NRC funding target
for each plant. The Company is also collecting revenues, based on its share
($3.83 million) of an estimate of $15.3 million for TMI-1 and $31.6 million
for Oyster Creek adopted in previous rate orders issued by the New Jersey
Board of Public Utilities (NJBPU), for its share of the cost of removal of
nonradiological structures and materials. Collections from customers for
retirement expenditures are deposited in external trusts. Provision for the
future expenditure of these funds has been made in accumulated depreciation,
amounting to $19 million for TMI-1 and $110 million for Oyster Creek at
September 30, 1995. Oyster Creek and TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 and Oyster Creek retirement costs, in
excess of those currently recognized for ratemaking purposes, should be
recoverable under the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target (in
1995 dollars). The Company and its affiliates record escalations, when
applicable, in the liability based upon changes in the NRC funding target.
The Company and its affiliates have also recorded a liability for incremental
costs specifically attributable to monitored storage. In addition, the Company
and its affiliates have recorded a liability for the nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $3
million, of which the Company's share is $0.8 million, as of September 30,
1995. Estimated TMI-2 Future Costs as of September 30, 1995 and December 31,
1994 are as follows:
September 30, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $ 64 $ 63
Nonradiological Cost of Removal 18 18
Incremental Monitored Storage 5 5
Total $ 87 $ 86
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the Balance Sheet. At September 30, 1995, $47 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet,
and $41 million was recoverable from customers and included in Three Mile
Island Unit 2 Deferred Costs on the Balance Sheet. In 1990, the Company made
a contribution of $15 million to an external decommissioning trust. This
contribution was not recovered from customers and has been expensed. Earnings
on trust fund deposits collected from customers are included in amounts shown
on the Balance Sheet under Three Mile Island Unit 2 Deferred Costs. The NJBPU
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. 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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As a result of TMI-2's entering long-term monitored storage in late
1993, the Company and its affiliates are incurring incremental annual storage
costs of approximately $1 million, of which the Company's share is $.25
million. The Company and its affiliates estimate that the remaining annual
storage costs will total $19 million, of which the Company's share is $5
million, through 2014, the expected retirement date of TMI-1. The Company's
rates reflect its $5 million share of these costs.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the Company.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station and for Oyster Creek totals
$2.7 billion per site. In accordance with NRC regulations, these insurance
policies generally require that proceeds first be used for stabilization of
the reactors and then to pay for decontamination and debris removal expenses.
Any remaining amounts available under the policies may then be used for repair
and restoration costs and decommissioning costs. Consequently, there can be
no assurance that in the event of a nuclear incident, property damage
insurance proceeds would be available for the repair and restoration of that
station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial protection, a nuclear incident at
any licensed nuclear power reactor in the country, including those owned by
the GPU System, could result in assessments of up to $79 million per incident
for each of the GPU System's two operating reactors, subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, the GPU System is also
subject to retrospective premium assessments of up to $69 million, of which
the Company's share is $41 million, in any one year under insurance policies
applicable to nuclear operations and facilities.
The Company and its affiliates have insurance coverage for incremental
replacement power costs resulting from an accident-related outage at its
nuclear plants. Coverage commences after the first 21 weeks of the outage and
continues for three years beginning at $1.8 million for Oyster Creek and $2.6
million for TMI-1 per week for the first year, decreasing to 80 percent of
such amounts for years two and three.
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COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
Nonutility Generation Agreements:
Pursuant to the requirements of the federal Public Utility Regulatory
Policies Act (PURPA) and state regulatory directives, the Company has entered
into power purchase agreements with nonutility generators for the purchase of
energy and capacity for periods up to 25 years. The majority of these
agreements contain certain contract limitations and subject the nonutility
generators to penalties for nonperformance. While some of these facilities
are dispatchable, most are must-run and generally obligate the Company to
purchase, at the contract price, the net output up to the contract limits. As
of September 30, 1995, facilities covered by these agreements having 892 MW of
capacity were in service. Estimated payments to nonutility generators from
1995 through 1999, assuming that all facilities which have existing
agreements, or which have obtained orders granting them agreements, enter
service, are $380 million, $358 million, $389 million, $419 million, and $431
million, respectively. These agreements, in the aggregate, will provide
approximately 1,002 MW of capacity and energy to the Company, at varying
prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the GPU System's energy supply needs which has
caused the Company and its affiliates to change their supply strategy to seek
shorter-term agreements offering more flexibility. Due to the current
availability of excess capacity in the marketplace, the cost of near- to
intermediate-term (i.e., one to eight years) energy supply from existing
generation facilities is currently and expected to continue to be
competitively priced at least for the near- to intermediate-term. The
projected cost of energy from new generation supply sources has also decreased
due to improvements in power plant technologies and reduced forecasted fuel
prices. As a result of these developments, the rates under virtually all of
the Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources.
The Company and its affiliates are seeking to reduce the above market
costs of these nonutility generation agreements by (1) attempting to convert
must-run agreements to dispatchable agreements; (2) attempting to renegotiate
prices of the agreements; (3) offering contract buy-outs while seeking to
recover the costs through their energy clauses (see Managing Nonutility
Generation, in Management's Discussion and Analysis of Financial Condition and
Results of Operations) and (4) initiating proceedings before federal and state
administrative agencies, and in the courts, where appropriate. 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 and are supporting
legislative efforts to repeal PURPA. These efforts may result in claims
against the GPU System for substantial damages. There can, however, be no
assurance as to what extent the Company's and its affiliates' efforts will be
successful in whole or in part.
While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the NJBPU and the
Pennsylvania Public Utility Commission (PaPUC), there can be no assurance that
the Company and its affiliates will continue to be able to recover these costs
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throughout the term of the related agreements. The GPU System currently
estimates that in 1998, when substantially all of these nonutility generation
projects are scheduled to be in service, above market payments (benchmarked
against the expected cost of electricity produced by a new gas-fired combined
cycle facility) will range from $240 million to $350 million annually, of
which the Company's share will range from $100 million and $150 million
annually.
Regulatory Assets and Liabilities:
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of
regulatory commissions, the electric utility industry is moving toward a
combination of competition and a modified regulatory environment. In
accordance with Statement of Financial Accounting Standards No. 71 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation," the Company's
financial statements reflect assets and costs based on current cost-based
ratemaking regulations. Continued accounting under FAS 71 requires that the
following criteria be met:
a) A utility's rates for regulated services provided to its customers
are established by, or are subject to approval by, an independent
third-party regulator;
b) The regulated rates are designed to recover specific costs of
providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of
competition, direct and indirect, it is reasonable to assume that
rates set at levels that will recover a utility's costs can be
charged to and collected from customers. This criteria requires
consideration of anticipated changes in levels of demand or
competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various
reasons, including deregulation, a change in the method of regulation, or a
change in the competitive environment for the utility's regulated services.
Regardless of the reason, a utility whose operations cease to meet those
criteria should discontinue application of FAS 71 and report that
discontinuation by eliminating from its Balance Sheet the effects of any
actions of regulators that had been recognized as assets and liabilities
pursuant to FAS 71 but which would not have been recognized as assets and
liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and
meets the above criteria, FAS 71 accounting may only be applied to that
portion. Write-offs of utility plant and regulatory assets may result for
those operations that no longer meet the requirements of FAS 71. In addition,
under deregulation, the uneconomical costs of certain contractual commitments
for purchased power and/or fuel supplies may have to be expensed currently.
Management believes that to the extent that the Company no longer qualifies
for FAS 71 accounting treatment, a material adverse effect on its results of
operations and financial position may result.
In accordance with the provisions of FAS 71, the Company has deferred
certain costs pursuant to actions of the NJBPU and Federal Energy Regulatory
Commission (FERC) and are recovering or expects to recover such costs in
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electric rates charged to customers. Regulatory assets are reflected in the
Deferred Debits and Other Assets section of the Consolidated Balance Sheet,
and regulatory liabilities are reflected in the Deferred Credits and Other
Liabilities section of the Consolidated Balance Sheet. Regulatory assets and
liabilities, as reflected in the September 30, 1995 Consolidated Balance
Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 143,900 $ 37,303
TMI-2 deferred costs 126,831 -
Unamortized property losses 101,064 -
NUG contract termination costs 16,400 -
Other postretirement benefits 30,629 -
N.J. unit tax 52,864 -
Unamortized loss on reacquired debt 34,997 -
Load and demand side management programs 47,643 -
DOE enrichment facility decommissioning 25,529 -
Manufactured gas plant remediation 30,720 -
Storm damage 23,876 -
Nuclear fuel disposal fee 24,117 -
N.J. low-level radwaste disposal 15,572 -
Oyster Creek deferred costs 8,084 -
Other 2,102 1,676
Total $ 684,328 $ 38,979
Income taxes recoverable/refundable through future rates: Represents amounts
deferred due to the implementation of FAS 109, "Accounting for Income Taxes",
in 1993.
TMI-2 deferred costs: Represents costs that are recoverable through rates for
the Company's remaining investment in the plant and fuel core, radiological
decommissioning in accordance with the NRC's funding target and allowances for
the cost of removal of nonradiological structures and materials, and long-term
monitored storage costs. For additional information, see TMI-2 Future Costs.
Unamortized property losses: Consists mainly of costs associated with the
Company's Forked River Project, which are included in rates.
NUG contract termination costs: Represents one-time costs incurred for
terminating power purchase contracts with nonutility generators (NUGs), for
which rate recovery is probable (See Managing Nonutility Generation, in
Management's Discussion and Analysis of Financial Condition and Results of
Operations).
Other postretirement benefits: Includes costs associated with the adoption of
FAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions", which are deferred in accordance with Emerging Issues Task Force
Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises".
N.J. unit tax: The Company received NJBPU approval in 1993 to recover, with
interest, over a ten-year period on an annuity basis, $71.8 million of Gross
Receipts and Franchise Tax not previously recovered from customers.
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Unamortized loss on reacquired debt: Represents premiums and expenses incurred
in the early redemption of long-term debt. In accordance with FERC
regulations, reacquired debt costs are amortized over the remaining original
life of the retired debt.
Load and demand side management (DSM) programs: Consists of load management
costs that are currently being recovered, with interest, through the Company's
retail base rates pursuant to a 1993 NJBPU order, and other DSM program
expenditures that are recovered annually. Also includes provisions for lost
revenues between base rate cases and performance incentives.
DOE enrichment facility decommissioning: These costs, representing payments
to the DOE over a 15-year period beginning in 1994, are currently being
collected through the Company's energy adjustment clause.
Manufactured gas plant remediation: Consists of costs being recovered
associated with the investigation and remediation of several gas manufacturing
plants. For additional information, see ENVIRONMENTAL MATTERS.
Storm damage: Relates to noncapital costs associated with various storms in
the Company's service territory that are not recoverable through insurance.
These amounts were deferred based upon past rate recovery precedent. An
annual amount for recovery of storm damage expense is included in the
Company's retail base rates.
Nuclear fuel disposal fee: Represents amounts recoverable through rates for
estimated future disposal costs for spent nuclear fuel at Oyster Creek and
TMI-1 in accordance with the Nuclear Waste Policy Act of 1982.
N.J. low-level radwaste disposal: Represents the accrual of the estimated
assessment for a disposal facility for low-level waste from Oyster Creek, less
amortization as allowed in the Company's rates.
Oyster Creek deferred costs: Consists of replacement power and O&M costs
deferred in accordance with orders from the NJBPU. The Company has been
granted recovery of these costs through rates at an annual amount until fully
amortized.
Amounts related to the decommissioning of TMI-1 and Oyster Creek, which
are not included in Regulatory Assets on the Balance Sheet, are separately
disclosed in NUCLEAR PLANT RETIREMENT COSTS.
The Company continues to be subject to cost-based ratemaking regulation.
The Company is unable to estimate to what extent FAS 71 may no longer be
applicable to its utility assets in the future.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including but
not limited to acid rain, water quality, air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, the Company may be required to incur substantial additional costs to
construct new equipment, modify or replace existing and proposed equipment,
remediate, decommission or clean up waste disposal and other sites currently
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or formerly used by it, including formerly owned manufactured gas plants, mine
refuse piles and generating facilities, and with regard to electromagnetic
fields, postpone or cancel the installation of, or replace or modify, utility
plant, the costs of which could be material.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of
1990, the Company expects to spend up to $58 million for air pollution control
equipment by the year 2000. In developing its least-cost plan to comply with
the Clean Air Act, the Company will continue to evaluate major capital
investments compared to participation in the emission allowance market and the
use of low-sulfur fuel or retirement of facilities.
The Company has been notified by the EPA and state environmental
authorities that it is among the potentially responsible parties (PRPs) who
may be jointly and severally liable to pay for the costs associated with the
investigation and remediation at 6 hazardous and/or toxic waste sites. In
addition, the Company has been requested to voluntarily participate in the
remediation or supply information to the EPA and state environmental
authorities on several other sites for which it has not yet been named as a
PRP. The Company has also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
The ultimate cost of remediation will depend upon changing circumstances as
site investigations continue, including (a) the existing technology required
for site cleanup, (b) the remedial action plan chosen and (c) the extent of
site contamination and the portion attributed to the Company.
The Company has entered into agreements with the New Jersey Department
of Environmental Protection for the investigation and remediation of 17
formerly owned manufactured gas plant sites. The Company has also entered
into various cost-sharing agreements with other utilities for most of the
sites. As of September 30, 1995, the Company has an estimated environmental
liability of $32 million recorded on its Balance Sheet relating to these
sites. The estimated liability is based upon ongoing site investigations and
remediation efforts, including capping the sites and pumping and treatment of
ground water. If the periods over which the remediation is currently expected
to be performed are lengthened, the Company believes that it is reasonably
possible that the ultimate costs may range as high as $60 million. Estimates
of these costs are subject to significant uncertainties because 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 also provided for interest on any
overrecovery to be credited to customers until the overrecovery is eliminated
and for future costs to be amortized over seven years with interest. A final
1994 NJBPU order indicated that interest is to be accrued retroactive to June
1993. The Company is pursuing reimbursement of the remediation costs from its
insurance carriers. In 1994, the Company filed a complaint with the Superior
Court of New Jersey against several of its insurance carriers, relative to
these manufactured gas plant sites. The Company requested the Court to order
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the insurance carriers to reimburse it for all amounts it has paid, or may be
required to pay, in connection with the remediation of the sites. Pretrial
discovery has begun in this case.
The Company is unable to estimate the extent of possible remediation and
associated costs of additional environmental matters. Also unknown are the
consequences of environmental issues, which could cause the postponement or
cancellation of either the installation or replacement of utility plant.
OTHER COMMITMENTS AND CONTINGENCIES
The Company's construction programs, for which substantial commitments
have been incurred and which extend over several years, contemplate
expenditures of $226 million during 1995. As a consequence of reliability,
licensing, environmental and other requirements, additions to utility plant
may be required relatively late in their expected service lives. If such
additions are made, current depreciation allowance methodology may not make
adequate provision for the recovery of such investments during their remaining
lives. Management intends to seek recovery of such costs through the
ratemaking process, but recognizes that recovery is not assured.
The Company has entered into a long-term contract with a nonaffiliated
mining company for the purchase of coal for the Keystone generating station in
which the Company has a one-sixth ownership interest. This contract, which
expires in 2004, requires the purchase of minimum amounts of the station's
coal requirements. The price of the coal under the contract is based on
adjustments of indexed cost components. The Company's share of the cost of
coal purchased under this agreement is expected to aggregate $23 million for
1995.
The Company and its affiliates have entered into agreements with other
utilities to purchase capacity and energy for various periods through 2004.
These agreements will provide for up to 1,308 MW in 1995, declining to
1,096 MW in 1997 and 696 MW by 2004. For the years 1995 through 1999, the
Company's share of payments pursuant to these agreements are estimated to
aggregate $202 million, $175 million, $162 million, $145 million, and
$128 million, respectively.
The Company has commenced construction of a 141 MW gas-fired combustion
turbine at its Gilbert generating station. The new facility, coupled with the
retirement of two older units, will result in a net capacity increase of
approximately 95 MW. This estimated $50 million project (of which $32 million
has already been spent) is expected to be in-service by mid-1996. In February
1995, the NJDEP issued an air permit for the facility based, in part, on the
NJBPU's December 1994 order which found that New Jersey's Electric Facility
Need Assessment Act is not applicable to this combustion turbine and that
construction of this facility, without a market test, is consistent with New
Jersey energy policies. An industry trade group representing nonutility
generators has appealed the NJDEP's issuance of the air permit and the NJBPU's
order to the Appellate Division of the New Jersey Superior Court. The Company
has moved to dismiss the appeal. There can be no assurance as to the outcome
of this proceeding.
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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 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 a NJBPU Administrative Law Judge. The Company estimates that
the potential refund liability from the 1992 LEAC period through February
1996, the end of the current LEAC period, is $56 million. There can be no
assurance as to the outcome of this proceeding.
The Company's two operating nuclear units are subject to the NJBPU's
annual nuclear performance standard. Operation of these units at an aggregate
annual generating capacity factor below 65% or above 75% would trigger a
charge or credit based on replacement energy costs. At current cost levels,
the maximum annual effect on net income of the performance standard charge at
a 40% capacity factor would be approximately $11 million before tax. While a
capacity factor below 40% would generate no specific monetary charge, it would
require the issue to be brought before the NJBPU for review. The annual
measurement period, which begins in March of each year, coincides with that
used for the LEAC.
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 defendants in litigation in which
compensatory and punitive damages are sought by the public, customers,
contractors, vendors and other suppliers of equipment and services and by
employees alleging unlawful employment practices. While management does not
expect that the outcome of these matters will have a material effect on the
Company's financial position or results of operations, there can be no
assurance that this will continue to be the case.
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Jersey Central Power & Light Company and Subsidiary 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
1994 Annual Report on Form 10-K.
RESULTS OF OPERATIONS
Earnings for the third quarter of 1995 were $91.9 million, compared to
$70.9 million for the same period ended 1994. The increase in third quarter
earnings was due primarily to lower operation and maintenance expense (O&M),
higher sales resulting from hotter summer temperatures compared to last year,
and new residential and commercial customer growth.
For the nine months ended September 30, 1995, earnings were $157.6
million, compared to $121.7 million for the same period last year. The same
factors affecting the quarterly results also affected the results for the nine
month period. In addition, the increase in earnings for the nine month period
was due primarily to a one-time charge of $30.4 million (after-tax) resulting
from early retirement programs offered in 1994, and lower O&M expense, which
included payroll and benefit savings from the early retirement programs. These
increases for the nine month period were partially offset by lower sales due
to warmer winter and cooler spring weather, and one-time net interest income
in 1994 of $7.4 million (after-tax) resulting from refunds of previously paid
federal income taxes related to the tax retirement of TMI-2.
OPERATING REVENUES:
Total revenues for the third quarter of 1995 increased 10.2% to
$625.5 million, as compared to the third quarter of 1994. For the nine months
ended September 30, 1995 revenues increased 2.2% to $1.5 billion, as compared
to the same period last year. The components of the changes are as follows:
(In Millions)
Three Months Nine Months
Ended Ended
September 30, 1995 September 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ 22.1 $ (3.2)
Energy revenues 33.8 39.1
Other revenues 1.8 (2.9)
Increase in revenues $ 57.7 $ 33.0
Kilowatt-hour revenues
The increase in KWH revenues for the three month period was due primarily
to higher sales from hotter summer temperatures in 1995, and new customer
additions in the residential and commercial sectors. The decrease in KWH
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revenues for the nine month period was due to lower residential sales from
milder winter and cooler spring weather in 1995.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased in both the three and nine month periods
primarily from higher energy cost rates and increased sales to other
utilities. The nine month period increase was partially offset by lower sales
to customers.
Other revenues
Generally, changes in other revenues do not affect earnings as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Company's energy clause.
However, earnings for the nine month period were negatively impacted by higher
reserve capacity expense resulting primarily from a 1995 Pennsylvania-New
Jersey-Maryland Interconnection (PJM) prior year adjustment, and one-time net
charges of $3.6 million (pre-tax) from another utility.
Fuel and Deferral of energy and capacity costs, net
Generally, changes in fuel expense and deferral of energy and capacity
costs do not affect earnings as they are offset by corresponding changes in
energy revenues. However, first quarter 1994 earnings benefitted from the
recognition of a performance award for the efficient operation of the
Company's nuclear generating stations.
Other operation and maintenance
The decrease in other O&M expense for the three month period was
primarily attributable to lower storm activity than in the third quarter of
1994, and lower nuclear expenses due to a refueling outage occurring at Oyster
Creek during the third quarter of 1994. The decrease in other O&M expense for
the nine month period was primarily attributable to a one-time $46.9 million
(pre-tax) charge in 1994 related to the early retirement programs. Also
contributing to the nine month O&M reduction were payroll and benefits savings
from the early retirement programs, and lower 1995 winter storm repair costs.
Depreciation and Amortization
The increase in depreciation and amortization expense for the nine month
period was due primarily to additions to plant in service, partially offset by
lower amortization of regulatory assets.
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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 decrease in other income for the nine month period was primarily
attributable to lower interest income of $14.7 million (pre-tax) resulting
from 1994 refunds of previously paid federal income taxes related to the tax
retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for the
tax years after TMI-2 was retired.
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Other interest
Other interest expense for the nine month period decreased primarily from
the recognition in the first quarter of 1994 of interest expense related to
the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $3.3
million (pre-tax) charge to interest expense on additional amounts owed for
tax years in which depreciation deductions with respect to TMI-2 had been
taken.
Dividends on subsidiary-obligated mandatorily redeemable preferred securities
In the second quarter of 1995, the Company issued $125 million of
monthly income preferred securities through a special-purpose finance
subsidiary. Dividends on these securities are payable monthly.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the nine months ended September 30, 1995
consisted of cash construction expenditures of $158 million. Construction
expenditures for the year are forecasted to be $226 million. Expenditures for
securities maturing in 1995 will total $47 million. Management estimates that
approximately two-thirds of the capital needs in 1995 will be satisfied
through internally generated funds.
FINANCING:
GPU has regulatory authority to issue up to four million shares of
additional common stock through 1996. GPU expects to use the proceeds from
any sale of additional common stock to reduce GPU short-term debt and make
capital contributions to the Company and its affiliates, and EI.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), which may be issued as secured medium-term notes, and preferred
stock through June 1997. Under existing authorizations, the Company may issue
such senior securities in the amount of $225 million, of which $100 million
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may consist of preferred stock. The Company also has regulatory authority to
incur short-term debt, a portion of which may be through the issuance of
commercial paper.
On November 1, 1995, the Company redeemed, at maturity, $17.4 million
principal amount of FMBs.
The Company's bond indenture and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Company may issue. The Company's interest and preferred
dividend coverage ratios are currently in excess of indenture and charter
restrictions.
COMPETITIVE ENVIRONMENT:
In September 1995, the Federal Energy Regulatory Commission (FERC)
accepted for filing, subject to possible refund, the Company's proposed open
access transmission tariffs. The tariffs were submitted to the FERC in March
1995, prior to the FERC's issuance of the Notice of Proposed Rulemaking on
open access non-discriminatory transmission services. The FERC has ordered
that hearings be held on a number of aspects of these tariffs, including
whether they are consistent in certain respects with FERC policy on open
access and comparability of service. The tariffs provide for both firm and
interruptible service on a point-to-point basis. Network service, where
requested, will be negotiated on a case by case basis.
In August 1995, the New Jersey Board of Public Utilities (NJBPU)
initiated Phase II of the Energy Master Plan on industry restructuring. The
NJBPU Phase II Report, which is expected to address such items as retail and
wholesale competition and divestiture of utility assets, is scheduled for
release in March 1996.
THE SUPPLY PLAN:
Managing Nonutility Generation
The Company and its affiliates are seeking to reduce the above market
costs of nonutility generation agreements, including (1) attempting to convert
must-run agreements to dispatchable agreements; (2) attempting to renegotiate
prices of the agreements; (3) offering contract buy-outs while seeking to
recover the costs through their energy clauses and (4) initiating proceedings
before federal and state administrative agencies, and in the courts, where
appropriate. 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,
and are supporting legislative efforts to repeal the Public Utility Regulatory
Policies Act of 1978 (PURPA). These efforts may result in claims against the
Company and its affiliates for substantial damages. There can, however, be no
assurance as to what extent the Company's and its affiliates' efforts will be
successful in whole or in part. The following is a discussion of some major
nonutility generation activities involving the Company.
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In March 1995, the U.S. Court of Appeals denied petitions for rehearing
filed by the Company, the NJBPU, and the New Jersey Division of Ratepayer
Advocate, asking that the Court reconsider its January 1995 decision
prohibiting the NJBPU from reexamining its order approving the rates payable
to Freehold Cogeneration Associates under a long-term power purchase agreement
entered into pursuant to PURPA. On October 5, 1995 the U. S. Supreme Court
denied petitions for review, filed by the Company and the Ratepayer Advocate.
The Company also petitioned the FERC to declare the agreement unlawful on the
grounds that when it was approved by the NJBPU, the contract pricing violated
PURPA, in that it requires the Company to purchase power at costs that were
above its then avoided costs. On October 11, 1995, the FERC denied the
Company's petition to void the agreement. The Company intends to seek
rehearing by the FERC, and may pursue the case in federal court.
In 1994, a nonutility generator requested that the NJBPU order the
Company to enter into a long-term agreement to buy capacity and energy. The
Company contested the request, and the NJBPU referred the matter to an
Administrative Law Judge (ALJ) for hearings. In February 1995, the ALJ issued
an initial decision stating that the nonutility generator had created a
legally enforceable obligation, but the appropriate avoided cost to be used
was still to be decided by the NJBPU. However, in April 1995, the NJBPU
remanded the proceeding to the ALJ for fact finding. In October 1995, at the
request of the nonutility generator, the NJBPU entered an order dismissing the
petition.
In May 1995, the Appellate Division of the New Jersey Superior Court
reversed NJBPU orders granting the developers of the Crown/Vista project in-
service date extensions for their proposed 200 MW coal-fired facilities. In
June 1995, the New Jersey Assembly passed a bill which, if enacted, would have
the effect of nullifying the Court's decision by retroactively extending the
in-service deadlines on the project for three years. In August 1995, the
developers entered into a buy-out agreement under which the Company has
purchased and terminated the agreements for $17 million. The Company intends
to file with the NJBPU for recovery of the costs through the levelized energy
adjustment clause.
In August 1995, the Company and its affiliates entered into a three-year
fuel management agreement with New Jersey Natural Energy Corporation, an
affiliate of New Jersey Natural Gas Company, to manage the Company's and its
affiliates' natural gas purchases and interstate pipeline capacity. It is
intended that the Company's and its affiliates' gas-fired facilities, as well
as up to approximately 1,100 MW of nonutility generation capacity, will be
pooled and managed under this agreement, allowing the Company and its
affiliates to reduce power purchase expenses.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 892 MW of capacity are currently
in service and an additional 110 MW are currently scheduled or anticipated to
be in service by 1999.
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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 Consolidated Financial Statements is
incorporated herein by reference and made a part hereof.
ITEM 5 - OTHER EVENTS
Management 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, i.e. its ability,
when necessary, to off-load the entire core to conduct certain
maintenance or repairs in order to restore operation of the plant.
In 1994, the Lacey Township Zoning Board of Adjustment issued a
use variance for the on-site storage facility, but Berkeley
Township and another party appealed to the New Jersey Superior
Court to overturn the decision. The Superior Court then remanded
the variance application to the Board of Adjustment for the
limited purpose of permitting the plaintiffs to present expert
testimony. In August 1995, the Board of Adjustment ruled in favor
of the Company and reaffirmed its 1994 decision granting the
Company the use variance. Construction of the facility is
continuing, and is expected to be completed by early 1996.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(27) Financial Data Schedule
(b) Reports on Form 8-K:
For the month of October 1995, dated October 4, 1995, under
Item 5 (Other Events)
For the month of October 1995, dated October 20, 1995, under
Item 5 (Other Events), as amended by Form 8-K/A No. 1, dated
October 27, 1995
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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
November 8, 1995 By: /s/ D. Baldassari
D. Baldassari, President
November 8, 1995 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 AND SUBSIDIARY 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, 1995 September 30, 1994
<S> <C> <C>
OPERATING REVENUES $1 546 594 $1 513 634
OPERATING EXPENSES 1 228 111 1 254 597
Interest portion of rentals (A) 9 385 8 284
Net expense 1 218 726 1 246 313
OTHER INCOME:
Allowance for funds used
during construction 4 554 2 233
Other income, net 10 713 23 154
Total other income 15 267 25 387
EARNINGS AVAILABLE FOR FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(excluding taxes based on income) $ 343 135 $ 292 708
FIXED CHARGES:
Interest on funded indebtedness $ 69 421 $ 70 981
Other interest (B) 11 637 12 011
Interest portion of rentals (A) 9 385 8 284
Total fixed charges $ 90 443 $ 91 276
RATIO OF EARNINGS TO FIXED CHARGES 3.79 3.21
Preferred stock dividend requirement 10 871 11 096
Ratio of income before provision
for income taxes to net income (C) 150.0% 151.6%
Preferred stock dividend requirement
on a pre-tax basis 16 306 16 822
Fixed charges, as above 90 443 91 276
Total fixed charges and
preferred stock dividends $ 106 749 $ 108 098
RATIO OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED
STOCK DIVIDENDS 3.21 2.71
</TABLE>
<PAGE>
Exhibit 12
Page 2 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY 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
NOTES:
(A) The Company has included the equivalent of the interest portion of all
rentals charged to income as fixed charges for this statement and has
excluded such components from Operating Expenses.
(B) Includes dividends on company-obligated mandatorily redeemable preferred
securities of $3,953 for the nine months ended September 30, 1995 only.
(C) Represents income before provision for income taxes of $252,692 and
$201,432, for the nine months ended September 30, 1995 and September 30,
1994, respectively, divided by net income of $168,454 and $132,845,
respectively.
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000053456
<NAME> JERSEY CENTRAL POWER & LIGHT COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> SEP-30-1995
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,894,180
<OTHER-PROPERTY-AND-INVEST> 308,126
<TOTAL-CURRENT-ASSETS> 465,191
<TOTAL-DEFERRED-CHARGES> 829,300
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,496,797
<COMMON> 153,713
<CAPITAL-SURPLUS-PAID-IN> 450,769
<RETAINED-EARNINGS> 834,721
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,439,203
259,000 <F1>
37,741
<LONG-TERM-DEBT-NET> 1,192,890
<SHORT-TERM-NOTES> 13,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 23,781
<LONG-TERM-DEBT-CURRENT-PORT> 73,140
10,000
<CAPITAL-LEASE-OBLIGATIONS> 2,849
<LEASES-CURRENT> 90,607
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,353,986
<TOT-CAPITALIZATION-AND-LIAB> 4,496,797
<GROSS-OPERATING-REVENUE> 1,546,594
<INCOME-TAX-EXPENSE> 79,965
<OTHER-OPERATING-EXPENSES> 1,228,111
<TOTAL-OPERATING-EXPENSES> 1,308,076
<OPERATING-INCOME-LOSS> 238,518
<OTHER-INCOME-NET> 7,296
<INCOME-BEFORE-INTEREST-EXPEN> 245,814
<TOTAL-INTEREST-EXPENSE> 77,360 <F2>
<NET-INCOME> 168,454
10,871
<EARNINGS-AVAILABLE-FOR-COMM> 157,583
<COMMON-STOCK-DIVIDENDS> 95,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 91,917
<CASH-FLOW-OPERATIONS> 203,564
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> INCLUDES COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
<F1> SECURITIES OF $125,000.
<F2> INCLUDES DIVIDENDS ON COMPANY-OBLIGATED MANDATORILY REDEEMABLE
<F2> PREFERRED SECURITIES OF $3,953.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
