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 June 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 July 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
June 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 19
PART II - Other Information 25
Signatures 26
_________________________________
The financial statements (not examined by independent accountants)
reflect all adjustments (which consist of only normal recurring
accruals) which are, in the opinion of management, necessary for a
fair statement of the results for the interim periods presented,
subject to the ultimate resolution of the various matters as
discussed in Note 1 to the Consolidated Financial Statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY
Consolidated Balance Sheets
<TABLE>
<CAPTION>
In Thousands
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $4 210 146 $4 119 617
Less, accumulated depreciation 1 591 111 1 499 405
Net utility plant in service 2 619 035 2 620 212
Construction work in progress 145 306 136 884
Other, net 114 705 123 349
Net utility plant 2 879 046 2 880 445
Other Property and Investments:
Nuclear decommissioning trusts 196 509 165 511
Nuclear fuel disposal fund 90 595 82 920
Other, net 6 875 6 906
Total other property and investments 293 979 255 337
Current Assets:
Cash and temporary cash investments 1 024 1 041
Special deposits 7 360 4 608
Accounts receivable:
Customers, net 118 584 126 760
Other 13 276 16 936
Unbilled revenues 59 989 59 288
Materials and supplies, at average cost or less:
Construction and maintenance 99 533 95 937
Fuel 19 280 18 563
Deferred energy costs 11 618 (148)
Deferred income taxes 10 421 10 454
Prepayments 186 661 45 880
Total current assets 527 746 379 319
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 130 654 138 294
Unamortized property losses 102 071 104 451
Income taxes recoverable through future rates 141 350 132 642
Other 295 847 309 230
Total regulatory assets 669 922 684 617
Deferred income taxes 127 571 122 944
Other 20 876 13 978
Total deferred debits and other assets 818 369 821 539
Total Assets $4 519 140 $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
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 450 768 435 715
Retained earnings 787 860 772 240
Total common stockholder's equity 1 392 341 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 1 218 549 1 168 444
Total capitalization 2 907 631 2 717 853
Current Liabilities:
Securities due within one year 57 439 47 439
Notes payable 95 793 110 356
Obligations under capital leases 95 112 102 059
Accounts payable:
Affiliates 26 768 34 283
Other 83 245 118 369
Taxes accrued 2 735 22 561
Interest accrued 30 317 29 765
Other 122 144 75 159
Total current liabilities 513 553 539 991
Deferred Credits and Other Liabilities:
Deferred income taxes 603 878 598 843
Unamortized investment tax credits 70 071 72 928
Three Mile Island Unit 2 future costs 86 836 85 273
Regulatory liabilities 39 897 41 732
Other 297 274 280 020
Total deferred credits and
other liabilities 1 097 956 1 078 796
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 519 140 $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 Six Months
Ended June 30, Ended June 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $453 081 $458 897 $921 115 $945 807
Operating Expenses:
Fuel 20 443 24 322 40 809 54 647
Power purchased and interchanged:
Affiliates 2 270 2 292 3 368 5 126
Others 143 007 134 849 311 278 279 563
Deferral of energy and capacity
costs, net (1 820) (266) (10 391) (9 043)
Other operation and maintenance 112 743 167 850 226 377 285 986
Depreciation and amortization 48 280 46 402 95 961 94 161
Taxes, other than income taxes 49 883 54 064 105 877 113 208
Total operating expenses 374 806 429 513 773 279 823 648
Operating Income Before Income Taxes 78 275 29 384 147 836 122 159
Income taxes 16 441 114 28 775 21 368
Operating Income 61 834 29 270 119 061 100 791
Other Income and Deductions:
Allowance for other funds used
during construction 229 52 457 109
Other income, net 3 367 4 163 6 985 19 597
Income taxes (1 343) (1 670) (2 782) (7 207)
Total other income
and deductions 2 253 2 545 4 660 12 499
Income Before Interest Charges and
Dividends on Preferred Securities 64 087 31 815 123 721 113 290
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 23 461 23 687 45 960 47 402
Other interest 3 530 3 558 5 523 8 871
Allowance for borrowed funds used
during construction (978) (605) (2 047) (1 255)
Dividends on company-obligated
mandatorily redeemable
preferred securities 1 278 - 1 278 -
Total interest charges and dividends
on preferred securities 27 291 26 640 50 714 55 018
Net Income 36 796 5 175 73 007 58 272
Preferred stock dividends 3 586 3 699 7 285 7 398
Earnings Available for Common Stock $ 33 210 $ 1 476 $ 65 722 $ 50 874
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
Six Months
Ended June 30,
1995 1994
<S> <C> <C>
Operating Activities:
Net income $ 73 007 $ 58 272
Adjustments to reconcile income to cash provided:
Depreciation and amortization 105 012 103 898
Amortization of property under capital leases 16 712 16 510
Voluntary enhanced retirement programs - 46 862
Nuclear outage maintenance costs, net 10 821 10 683
Deferred income taxes and investment tax
credits, net 29 702 4 088
Deferred energy and capacity costs, net (10 440) (8 931)
Accretion income (6 260) (6 772)
Allowance for other funds used
during construction (457) (109)
Changes in working capital:
Receivables 6 810 7 924
Materials and supplies (4 313) (8 903)
Special deposits and prepayments (149 122) (138 816)
Payables and accrued liabilities (50 539) (41 543)
Other, net (6 279) (13 736)
Net cash provided by operating activities 14 654 29 427
Investing Activities:
Cash construction expenditures (98 623) (92 425)
Contributions to decommissioning trusts (9 022) (8 205)
Other, net (873) (5 964)
Net cash used for investing activities (108 518) (106 594)
Financing Activities:
Issuance of long-term debt 49 625 -
Increase (decrease) in notes payable, net (14 600) 155 400
Capital lease principal payments (13 637) (15 155)
Issuance of company-obligated mandatorily
redeemable preferred securities 120 906 -
Contributions from parent corporation 15 000 -
Redemption of preferred stock (6 049) -
Dividends paid on common stock (50 000) (70 000)
Dividends paid on preferred stock (7 398) (7 398)
Net cash provided by financing activities 93 847 62 847
Net decrease in cash and temporary cash
investments from above activities (17) (14 320)
Cash and temporary cash investments,
beginning of year 1 041 17 301
Cash and temporary cash investments, end of period $ 1 024 $ 2 981
Supplemental Disclosure:
Interest paid $ 51 355 $ 52 889
Income taxes paid $ 50 799 $ 9 417
New capital lease obligations incurred $ 8 746 $ 27 808
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
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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) and EI Power, Inc., which develop, own and operate nonutility generating
facilities. All of the Company's affiliates are wholly owned subsidiaries of
GPU. The Company and its affiliates, GPUSC, GPUN, EI and EI Power Inc. are
referred to as the "GPU System."
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
were 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 June 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
June 30, 1995 $168 $791
December 31, 1994 $162 $817
The Company's net investment in TMI-2 at June 30, 1995 and December 31,
1994 was $87 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
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
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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. If, notwithstanding the developments noted
below, punitive damages are not covered by insurance and are not subject to
the liability limitations of the federal Price-Anderson Act ($560 million at
the time of the accident), punitive damage awards could have a material
adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for premium charges deferred in whole or
in major part under such plan, and (c) an indemnity agreement with the NRC,
bringing their total primary and secondary insurance financial protection and
indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers under a reservation of rights with respect to any award of
punitive damages. However, in March 1994, the defendants in the TMI-2
litigation and the insurers agreed that the insurers would withdraw their
reservation of rights with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is 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
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out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment. In July 1994, the Court
granted defendants' motions for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals for the Third Circuit.
In an order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (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 target (in 1994 dollars) for TMI-1 is $157 million, of which the
Company's share is $39 million, and $189 million for Oyster Creek. Based on
NRC studies, a comparable funding target for TMI-2 has been developed which
takes the accident into account (see TMI-2 Future Costs). The NRC continues
to study the levels of these funding targets. Management cannot predict the
effect that the results of this review will have on the funding targets. NRC
regulations and a regulatory guide provide mechanisms, including exemptions,
to adjust the funding targets over their collection periods to reflect
increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not considered cost
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $225 to $309 million, of which the Company's share would
range from $56 million to $77 million, and $239 to $350 million, respectively
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(in 1994 dollars). In addition, the studies estimated the cost of removal of
nonradiological structures and materials for TMI-1 and Oyster Creek at
$74 million, of which the Company's share is $18 million, and $48 million,
respectively (in 1994 dollars). To date, no site-specific study has been
performed for TMI-2.
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. Amounts deposited in external trusts, including the interest
earned on these funds, are classified as Nuclear Decommissioning Trusts on the
balance sheet.
The Financial Accounting Standards Board (FASB) is currently reviewing
the utility industry's accounting practices for nuclear decommissioning costs.
If the FASB's tentative conclusions are adopted, Oyster Creek and TMI-1
retirement costs may have to be recorded as a liability, rather than as
accumulated depreciation, with an offsetting asset recorded for amounts
collectible through rates. Any amounts that cannot be collected through rates
may have to be charged to expense. The FASB is expected to release an Exposure
Draft on decommissioning accounting practices by the fourth quarter of 1995.
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 $20 million for TMI-1 and $120 million for Oyster Creek at June
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.
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The Company and its affiliates have also recorded a liability for incremental
costs specifically attributable to monitored storage. In addition, the Company
and its affiliates have recorded a liability for 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 June 30, 1995.
Estimated TMI-2 Future Costs as of June 30, 1995 and December 31, 1994 are as
follows:
June 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 June 30, 1995, $46 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and
$43 million was recoverable from customers and included in Three Mile Island
Unit 2 Deferred Costs on the balance sheet. The Company has made a
contribution of $15 million to an external decommissioning trust. This
contribution was not recovered from customers and has been expensed. The
Company's share of earnings on trust fund deposits are offset against amounts
shown on the balance sheet under Three Mile Island Unit 2 Deferred Costs as
collectible from customers. The NJBPU has granted 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.
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
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insurance proceeds would be available for the repair and restoration of that
station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial protection, a nuclear incident at
any licensed nuclear power reactor in the country, including those owned by
the GPU System, could result in assessments of up to $79 million per incident
for each of the GPU System's two operating reactors (TMI-2 being excluded
under an exemption received from the NRC in 1994), subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, 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 by 20 percent for
years two and three.
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 a few 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 June 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 all facilities which have existing agreements, or
which have obtained orders granting them agreements enter service, are $395
million, $556 million, $571 million, $587 million, and $607 million,
respectively. These agreements, in the aggregate, will provide approximately
1,202 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
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the Company's and its affiliate's 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 and (4) initiating proceedings
before federal and state administrative agencies, and in the courts. 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
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 $300 million to $450 million annually, of
which the Company's share will range from $120 million to $190 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
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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 is recovering or expects to recover such costs in
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 June 30, 1995 Consolidated Balance Sheet,
were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 141,350 $38,079
TMI-2 deferred costs 130,654 -
Unamortized property losses 102,071 -
N.J. unit tax 54,185 -
Unamortized loss on reacquired debt 35,708 -
DOE enrichment facility decommissioning 26,024 -
Load and demand side management programs 44,220 -
Other postretirement benefits 27,954 -
Manufactured gas plant remediation 29,548 -
Nuclear fuel disposal fee 24,642 -
Storm damage 23,048 -
N.J. low level radwaste disposal 16,935 -
Oyster Creek deferred costs 11,430 -
Other 2,153 1,818
Total $669,922 $39,897
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: Primarily represents costs that are being recovered
through retail rates for the Company's remaining investment in the plant and
fuel core, radiological decommissioning for the Company's share of 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.
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Unamortized property losses: Consists mainly of costs associated with the
Company's Forked River Project, which is included in rates.
N.J. unit tax: The Company received NJBPU approval in 1993 to recover, over a
ten-year period on an annuity basis, $71.8 million of Gross Receipts and
Franchise Tax not previously recovered from customers.
Unamortized loss on reacquired debt: Represents premiums and expenses incurred
in the redemption of long-term debt. In accordance with FERC regulations,
reacquired debt costs are amortized over the remaining original life of the
retired debt.
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.
Load and demand side management (DSM) programs: Consists of load management
costs that are currently being recovered 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.
Other postretirement benefits: Includes costs associated with the adoption of
FAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions." Recovery of these costs is subject to regulatory approval.
Manufactured gas plant remediation: Consists of costs associated with the
investigation and remediation of several gas manufacturing plants. For
additional information, see ENVIRONMENTAL MATTERS.
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.
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.
N.J. low level radwaste disposal: Represents the accrual of the estimated
assessment for disposal of 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.
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ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including but
not limited to acid rain, water quality, air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, the Company may be required to incur substantial additional costs to
construct new equipment, modify or replace existing and proposed equipment,
remediate, decommission or clean up waste disposal and other sites currently
or formerly used by it, including formerly owned manufactured gas plants, 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 7 hazardous and/or toxic waste sites. In
addition, the Company has been requested to voluntarily participate in the
remediation or supply information to the EPA and state environmental
authorities on several other sites for which it has not yet been named as a
PRP. The Company has also been named in lawsuits requesting damages for
hazardous and/or toxic substances allegedly released into the environment.
The ultimate cost of remediation will depend upon changing circumstances as
site investigations continue, including (a) the existing technology required
for site cleanup, (b) the remedial action plan chosen and (c) the extent of
site contamination and the portion attributed to the Company.
The Company has entered into agreements with the New Jersey Department
of Environmental Protection for the investigation and remediation of 17
formerly owned manufactured gas plant sites. The Company has also entered
into various cost-sharing agreements with other utilities for some of the
sites. As of June 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 as the Company does
not presently own or control most of these sites; the environmental standards
have changed in the past and are subject to future change; the accepted
technologies are subject to further development; and the related costs for
these technologies are uncertain. If the Company is required to utilize
different remediation methods, the costs could be materially in excess of $60
million.
In 1993, the NJBPU approved a mechanism similar to the Company's
Levelized Energy Adjustment Clause (LEAC) for the recovery of future
manufactured gas plant remediation costs when expenditures exceed prior
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collections. Since collections currently exceed expenditures, the NJBPU
decision also provided for interest on the excess 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 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 $220 million during 1995. As a consequence of reliability,
licensing, environmental and other requirements, additions to utility plant
may be required relatively late in their expected service lives. If such
additions are made, current depreciation allowance methodology may not make
adequate provision for the recovery of such investments during their remaining
lives. Management intends to seek recovery of such costs through the
ratemaking process, but recognizes that recovery is not assured.
The Company has entered into a long-term contract with a nonaffiliated
mining company for the purchase of coal for the Keystone generating station in
which the Company owns a one-sixth undivided interest. This contract, which
expires in 2004, requires the purchase of minimum amounts of the station's
coal requirements. The price of the coal under the contract is based on
adjustments of indexed cost components. The Company's share of the cost of
coal purchased under this agreement is expected to aggregate $21 million for
1995.
The Company and its affiliates have entered into agreements 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 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
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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.
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 exposure from the 1992 LEAC period through February 1996, the
end of the current LEAC period, is $73 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 businesses, in addition
to the matters described above, the Company is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by customers, contractors,
vendors and other suppliers of equipment and services and by employees
alleging unlawful employment practices. It is not expected that the outcome
of these types of matters would have a material effect on the Company's
financial position or results of operations.
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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 available for common stock for the second quarter of 1995 were
$33.2 million, compared to $1.5 million for the same period ended 1994. The
increase in second quarter earnings was due primarily to a 1994 charge of
$30.4 million after-tax for costs related to voluntary enhanced retirement
programs. Also contributing to the earnings increase was lower operation and
maintenance (O&M) expense and increased sales from new customer growth,
largely offset by lower sales from cooler 1995 spring weather.
For the six months ended June 30, 1995 earnings available for common
stock were $65.7 million, compared to $50.9 million for the same period last
year. The same factors affecting the quarterly results also affected the
results for the six month period. In addition, earnings compared to last year
were negatively affected by lower sales due to warmer 1995 winter weather,
higher reserve capacity expense and the recognition in 1994 of a performance
award for the efficient operation of the Company's nuclear generating
stations. Also affecting the six months earnings comparison was nonrecurring
interest income (net of nonrecurring interest expense) in 1994 of $7.4 million
after-tax resulting from refunds of previously paid federal income taxes
related to the tax retirement of Three Mile Island Unit 2 (TMI-2).
OPERATING REVENUES:
Total revenues for the second quarter of 1995 decreased 1.3% to
$453.1 million, as compared to the second quarter of 1994. For the six months
ended June 30, revenues decreased 2.6% to $921.1 million, as compared to the
same period last year. The components of the changes are as follows:
(In Millions)
Three Months Six Months
Ended Ended
June 30, 1995 June 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $(12.2) $(25.3)
Energy revenues 8.4 5.3
Other revenues (2.0) (4.7)
Decrease in revenues $ (5.8) $(24.7)
Kilowatt-hour revenues
The decrease in KWH revenues in the three and six month periods was due
primarily to lower residential sales from a warmer winter and cooler spring
this year as compared to the previous year. New customer additions in the
residential and commercial sectors partially offset these decreases.
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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 six month periods
primarily from higher energy cost rates and increased sales to other
utilities, 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 six months ended June 1995 were negatively impacted
by higher reserve capacity expense resulting primarily from higher payments to
the Pennsylvania-New Jersey-Maryland Interconnection and a one-time
$3.3 million pre-tax charge 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, 1994 earnings benefitted from the recognition of a
performance award in the first quarter 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 and six months ended June
1995 was primarily attributable to a one-time $46.9 million pre-tax charge in
1994 related to the voluntary enhanced retirement programs. Also contributing
to the O&M reduction was payroll and benefits savings from the retirement
programs and lower first quarter winter storm repair costs.
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/(expense), net
The decrease in other income for the six months ended June 1995 was
primarily attributable to lower first quarter 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.
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INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Other interest
Other interest expense for the six months ended June 1995 decreased due
primarily to 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.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the six months ended June 30, 1995
consisted of cash construction expenditures of $99 million. Construction
expenditures for the year are forecasted to be $220 million. Expenditures for
maturing debt are expected to be $47 million for 1995. Management estimates
that approximately two-thirds of the capital needs in 1995 will be satisfied
through internally generated funds.
FINANCING:
During the second quarter of 1995, JCP&L Capital L.P., a special-purpose
finance subsidiary of the Company, issued $125 million stated value of monthly
income preferred securities. The proceeds from the issuance were used to
reduce outstanding short-term debt. Also, the Company repurchased in the
market, 60,000 shares of its 7.52% Series K cumulative preferred stock. The
repurchased shares may be used to satisfy future sinking fund requirements.
Also in the second quarter, GPU sold one million shares of common stock
through an underwritten public offering. The net proceeds of $29.6 million
were used to make cash capital contributions to the Company and its
affiliates, of which the Company's share was $15 million.
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 1997. Under existing authorization, the Company may issue senior
securities in the amount of $225 million, of which $100 million may consist of
preferred stock. The Company also has regulatory authority to incur short-
term debt, a portion of which may be through the issuance of commercial paper.
The Company's bond indentures 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. The ability to issue securities in the future will depend on
coverages at that time.
COMPETITIVE ENVIRONMENT:
In March 1995, prior to the Federal Energy Regulatory Commission's (FERC)
issuance of the Notice of Proposed Rulemaking on open access non-
discriminatory transmission services, the Company and its affiliates filed
with the FERC proposed open access transmission tariffs. Such proposed
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tariffs provided for both firm and interruptible service on a point-to-point
basis. Network service, where requested, would be negotiated on a case by
case basis. In July 1995, the Company and its affiliates submitted to the
FERC further support and justification for their tariffs in response to a FERC
Staff request. The Company and its affiliates do not know whether or to what
extent the FERC will require modifications to any of the proposed terms and
conditions of these transmission tariffs.
In July 1995, New Jersey adopted energy rate flexibility legislation that
will enable electric utilities to offer rate discounts to certain customers
and allow these customers access to competitive markets. If certain
conditions are met, utilities are permitted to recover from customers 50% of
revenue lost as a result of a rate discount. The legislation also provides
utilities with the opportunity to propose to the New Jersey Board of Public
Utilities (NJBPU) alternative ways to set rates.
In June 1995, the Securities and Exchange Commission (SEC) approved an
SEC Staff report containing a series of legislative and administrative
recommendations to reform the Public Utility Holding Company Act of 1935
(Holding Company Act). The SEC Staff recommended that the SEC support repeal
of the Holding Company Act with a minimum one year transition period, and a
transfer of audit, reporting and certain other responsibilities to the FERC
while giving state commissions access to holding company books and records.
In the interim, the Staff recommended that the SEC adopt a series of
administrative reforms that would streamline such things as the issuance of
securities for routine financings and permit a wide range of energy related
diversification activities. The Staff also recommended that the SEC more
flexibly interpret the Holding Company Act's integrated system requirements by
allowing utility acquisitions and specifically, combination electric and gas
systems, where the affected state commissions concur.
In response to the Staff report, the SEC has adopted certain changes
which will streamline routine financings, and has proposed a number of others.
GPU and other registered holding companies, believe, however, that repeal of
the Holding Company Act is necessary to remove a significant impediment to
competition.
THE SUPPLY PLAN:
New Energy Supplies:
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 is expected to be in-
service by mid-1996. In February 1995, the New Jersey Department of
Environmental Protection (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 issuance of the air permit
by the NJDEP and the NJBPU's order to the Appellate Division of 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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Managing Nonutility Generation
The Company is seeking to reduce the above market costs of nonutility
generation (NUG) 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 its energy clause and (4) initiating proceedings before federal
and state administrative agencies, and in the courts. In addition, the
Company intends to avoid, to the maximum extent practicable, entering into any
new nonutility generation agreements that are not needed or not consistent
with current market pricing 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 for substantial damages. There can,
however, be no assurance as to what extent the Company's efforts will be
successful in whole or in part. The following is a discussion of some major
nonutility generation activities involving the Company.
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 a nonutility generator under a long-term power purchase agreement entered
into pursuant to PURPA. Also in March 1995, the Company 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 two recent decisions involving
other utilities, the FERC ruled that PURPA prohibits the states from requiring
utilities to enter into contracts at rates higher than the utility's avoided
costs, and found that contracts containing these rates are void under certain
conditions. In June 1995, The Company and the Ratepayer Advocate filed
petitions with the U.S. Supreme Court seeking the Court to review the U.S.
Court of Appeals decision. The Company's petition before the FERC is pending.
In 1994, a nonutility generator requested that the NJBPU order the
Company to enter into long-term agreements 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 May 1994, the NJBPU issued orders granting two nonutility generators,
aggregating 200 MW, a final in-service (sunset) date extension for projects
originally scheduled to be operational in 1997. The NJBPU orders extend the
in-service dates for one year plus any appeal period. In May 1995, the
Appellate Division of the New Jersey Superior Court reversed the NJBPU
decision. 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 two projects for three
years. The State Senate is expected to consider the legislation in September
1995.
As part of an effort to reduce above-market payments under nonutility
generation agreements, the Company and its affiliates are seeking to implement
a program under which the natural gas fuel and transportation for the
Company's and its affiliates' gas-fired facilities, as well as up to
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approximately 1,100 MW of nonutility generation capacity, would be pooled and
managed by a nonaffiliated fuel manager. The Company and its affiliates
believe the plan has the potential to provide substantial savings for their
customers. The Company and its affiliates are conducting negotiations with a
nonaffiliated company to serve as fuel manager.
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 310 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 and
GPU 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 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
By Consent of the Sole Stockholder dated May 16, 1995, the
following were elected directors of the Company for the ensuing
year:
R. C. Arnold D. W. Myers
D. Baldassari G. E. Persson
J. G. Graham S. C. Van Ness
J. R. Leva S. B. Wiley
M. P. Morrell
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(12) Statements Showing Computation of Ratio of
Earnings to Fixed Charges and Ratio of
Earnings to Combined Fixed Charges and
Preferred Stock Dividends.
(27) Financial Data Schedule.
(b) Reports on Form 8-K:
None.
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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
August 8, 1995 By: /s/ M. P. Morrell
M. P. Morrell, Vice President -
Regulatory and Public Affairs
August 8, 1995 By: /s/ D. W. Myers
D. W. Myers, Vice President -
Operations Support and Comptroller
(Principal Accounting Officer)
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<NAME> JERSEY CENTRAL POWER & LIGHT COMPANY
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<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> JUN-30-1995
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,879,046
<OTHER-PROPERTY-AND-INVEST> 293,979
<TOTAL-CURRENT-ASSETS> 527,746
<TOTAL-DEFERRED-CHARGES> 818,369
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,519,140
<COMMON> 153,713
<CAPITAL-SURPLUS-PAID-IN> 450,768
<RETAINED-EARNINGS> 787,860
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,392,341
259,000 <F1>
37,741
<LONG-TERM-DEBT-NET> 1,218,549
<SHORT-TERM-NOTES> 64,900
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 30,893
<LONG-TERM-DEBT-CURRENT-PORT> 47,439
10,000
<CAPITAL-LEASE-OBLIGATIONS> 3,343
<LEASES-CURRENT> 95,112
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,359,822
<TOT-CAPITALIZATION-AND-LIAB> 4,519,140
<GROSS-OPERATING-REVENUE> 921,115
<INCOME-TAX-EXPENSE> 28,775
<OTHER-OPERATING-EXPENSES> 773,279
<TOTAL-OPERATING-EXPENSES> 802,054
<OPERATING-INCOME-LOSS> 119,061
<OTHER-INCOME-NET> 4,660
<INCOME-BEFORE-INTEREST-EXPEN> 123,721
<TOTAL-INTEREST-EXPENSE> 50,714 <F2>
<NET-INCOME> 73,007
7,285
<EARNINGS-AVAILABLE-FOR-COMM> 65,722
<COMMON-STOCK-DIVIDENDS> 50,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 92,035
<CASH-FLOW-OPERATIONS> 14,654
<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 $1,278.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<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
Six Months Ended
June 30, 1995 June 30, 1994
OPERATING REVENUES $921 115 $945 807
OPERATING EXPENSES 773 279 823 648
Interest portion
of rentals (A) 6 429 5 502
Net expense 766 850 818 146
OTHER INCOME:
Allowance for funds
used during
construction 2 504 1 364
Other income, net 6 985 19 597
Total other income 9 489 20 961
EARNINGS AVAILABLE FOR FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS
(excluding taxes
based on income) $163 754 $148 622
FIXED CHARGES:
Interest on funded
indebtedness $ 45 960 $ 47 402
Other interest (B) 6 801 8 871
Interest portion
of rentals (A) 6 429 5 502
Total fixed charges $ 59 190 $ 61 775
RATIO OF EARNINGS TO
FIXED CHARGES 2.77 2.41
Preferred stock dividend
requirement 7 285 7 398
Ratio of income before
provision for income
taxes to net income (C) 143.2% 149.0%
Preferred stock dividend
requirement on a pre-tax
basis 10 432 11 023
Fixed charges, as above 59 190 61 775
Total fixed charges
and preferred
stock dividends $ 69 622 $ 72 798
RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS 2.35 2.04
<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 $1,278 for the six months ended June 30, 1995 only.
(C) Represents income before provision for income taxes of $104,563 and
$86,847, for the six months ended June 30, 1995 and June 30, 1994,
respectively, divided by net income of $73,007 and $58,272, respectively.
<PAGE>
