UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 April 30, 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
March 31, 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 27
Signatures 28
_________________________________
The financial statements (not examined by independent accountants)
reflect all adjustments (which consist of only normal recurring
accruals) which are, in the opinion of management, necessary for a
fair statement of the results for the interim periods presented,
subject to the ultimate resolution of the various matters as
discussed in Note 1 to the Financial Statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
ASSETS
Utility Plant:
In service, at original cost $4 153 053 $4 119 617
Less, accumulated depreciation 1 545 224 1 499 405
Net utility plant in service 2 607 829 2 620 212
Construction work in progress 151 118 136 884
Other, net 116 648 123 349
Net utility plant 2 875 595 2 880 445
Other Property and Investments:
Nuclear decommissioning trusts 180 078 165 511
Nuclear fuel disposal fund 87 204 82 920
Other, net 6 883 6 906
Total other property and investments 274 165 255 337
Current Assets:
Cash and temporary cash investments 19 262 1 041
Special deposits 3 690 4 608
Accounts receivable:
Customers, net 117 032 126 760
Other 16 292 16 936
Unbilled revenues 52 996 59 288
Materials and supplies, at average cost or less:
Construction and maintenance 98 991 95 937
Fuel 18 805 18 563
Deferred energy costs 7 975 (148)
Deferred income taxes 13 044 10 454
Prepayments 16 143 45 880
Total current assets 364 230 379 319
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 134 663 138 294
Unamortized property losses 103 167 104 451
Income taxes recoverable through future rates 136 706 132 642
Other 302 190 309 230
Total regulatory assets 676 726 684 617
Deferred income taxes 124 810 122 944
Other 16 695 13 978
Total deferred debits and other assets 818 231 821 539
Total Assets $4 332 221 $4 336 640
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Balance Sheets
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 153 713 $ 153 713
Capital surplus 435 715 435 715
Retained earnings 804 752 772 240
Total common stockholder's equity 1 394 180 1 361 668
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 37 741 37 741
Long-term debt 1 218 496 1 168 444
Total capitalization 2 800 417 2 717 853
Current Liabilities:
Debt due within one year 47 439 47 439
Notes payable - 110 356
Obligations under capital leases 95 935 102 059
Accounts payable:
Affiliates 25 509 34 283
Other 92 552 118 369
Taxes accrued 88 895 22 561
Interest accrued 28 957 29 765
Other 63 599 75 159
Total current liabilities 442 886 539 991
Deferred Credits and Other Liabilities:
Deferred income taxes 602 027 598 843
Unamortized investment tax credits 71 500 72 928
Three Mile Island Unit 2 future costs 86 118 85 273
Regulatory liabilities 40 815 41 732
Other 288 458 280 020
Total deferred credits and
other liabilities 1 088 918 1 078 796
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 332 221 $4 336 640
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Income
(Unaudited)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Revenues $468 034 $486 910
Operating Expenses:
Fuel 20 366 30 325
Power purchased and interchanged:
Affiliates 1 098 2 834
Others 168 271 144 714
Deferral of energy and capacity
costs, net (8 571) (8 777)
Other operation and maintenance 113 634 118 136
Depreciation and amortization 47 681 47 759
Taxes, other than income taxes 55 994 59 144
Total operating expenses 398 473 394 135
Operating Income Before Income Taxes 69 561 92 775
Income taxes 12 334 21 254
Operating Income 57 227 71 521
Other Income and Deductions:
Allowance for other funds used
during construction 228 57
Other income, net 3 618 15 434
Income taxes (1 439) (5 537)
Total other income
and deductions 2 407 9 954
Income Before Interest Charges 59 634 81 475
Interest Charges:
Interest on long-term debt 22 499 23 715
Other interest 1 993 5 313
Allowance for borrowed funds used
during construction (1 069) (650)
Total interest charges 23 423 28 378
Net Income 36 211 53 097
Preferred stock dividends 3 699 3 699
Earnings Available for Common Stock $ 32 512 $ 49 398
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
Statements of Cash Flows
(Unaudited)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Activities:
Income before preferred stock dividends $ 36 211 $ 53 097
Adjustments to reconcile income to cash provided:
Depreciation and amortization 52 074 52 974
Amortization of property under capital leases 6 636 8 605
Nuclear outage maintenance costs, net 5 796 5 609
Deferred income taxes and investment tax
credits, net (22 785) 9 277
Deferred energy and capacity costs, net (8 599) (8 840)
Accretion income (3 130) (3 388)
Allowance for other funds used
during construction (229) (57)
Changes in working capital:
Receivables 17 581 (18 439)
Materials and supplies (3 296) (6 456)
Special deposits and prepayments 25 588 43 685
Payables and accrued liabilities 35 620 27 749
Other, net (3 712) (14 148)
Net cash provided by operating activities 137 755 149 668
Investing Activities:
Cash construction expenditures (47 697) (46 552)
Contributions to decommissioning trusts (4 516) (4 453)
Other, net 1 038 (2 178)
Net cash used for investing activities (51 175) (53 183)
Financing Activities:
Issuance of long-term debt 49 625 -
Decrease in notes payable, net (110 500) -
Capital lease principal payments (3 785) (6 532)
Dividends paid on common stock - (40 000)
Dividends paid on preferred stock (3 699) (3 699)
Net cash required by financing activities (68 359) (50 231)
Net increase in cash and temporary cash
investments from above activities 18 221 46 254
Cash and temporary cash investments,
beginning of year 1 041 17 301
Cash and temporary cash investments, end of period $ 19 262 $ 63 555
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 24 433 $ 32 708
Income taxes paid $ (4 555) $ 76
New capital lease obligations incurred $ 1 951 $ 2 931
The accompanying notes are an integral part of the financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
NOTES TO FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was
incorporated under the laws of New Jersey in 1925, is a wholly owned
subsidiary of General Public Utilities Corporation (GPU), a holding company
registered under the Public Utility Holding Company Act of 1935. The Company
is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania
Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to
herein as the "Company and its affiliates." The Company is also affiliated
with GPU Service Corporation (GPUSC), a service company; GPU Nuclear
Corporation (GPUN), which operates and maintains the nuclear units of the
Company and its affiliates; and Energy Initiatives, Inc. (EI) and EI Power,
Inc., which develop, own and operate nonutility generating facilities. All of
the Company's affiliates are wholly owned subsidiaries of GPU. The Company
and its affiliates, GPUSC, GPUN, EI and EI Power Inc. are referred to as the
"GPU System."
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 March 31, 1995 and December 31,
1994, the Company's net investment in TMI-1, TMI-2 and Oyster Creek, including
nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2 Oyster Creek
March 31, 1995 $161 $ 88 $803
December 31, 1994 $162 $ 89 $817
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, safety standards and experience gained in the
construction and operation of nuclear facilities. The Company and its
affiliates may also incur costs and experience reduced output at its nuclear
plants because of the prevailing design criteria at the time of construction
and the age of the plants' systems and equipment. In addition, for economic
or other reasons, operation of these plants for the full term of their now-
assumed lives cannot be assured. Also, not all risks associated with the
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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 not likely to begin before 1996. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable federal safety standards regarding permissible radiation
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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).
The ultimate cost of retiring the Company and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies. Such costs are subject to
(a) the type of decommissioning plan selected, (b) the escalation of various
cost elements (including, but not limited to, general inflation), (c) the
further development of regulatory requirements governing decommissioning,
(d) the absence to date of significant experience in decommissioning such
facilities and (e) the technology available at the time of decommissioning.
The Company and its affiliates charge to expense and contribute to external
trusts amounts collected from customers for nuclear plant decommissioning and
nonradiological costs. In addition, the Company has contributed amounts
written off for TMI-2 nuclear plant decommissioning in 1990 to TMI-2's
external trust. Amounts deposited in external trusts, including the interest
earned on these funds, are classified as Nuclear Decommissioning Trusts on the
balance sheet.
TMI-1 and Oyster Creek:
The Company is collecting revenues for decommissioning, which are
expected to result in the accumulation of its share of the NRC funding target
for each plant. The Company is also collecting revenues, based on its share
($3.83 million) of an estimate of $15.3 million for TMI-1 and $31.6 million
for Oyster Creek adopted in 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 expenditures of these funds has been made in accumulated depreciation,
amounting to $18 million for TMI-1 and $109 million for Oyster Creek at March
31, 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 nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $2
million, of which the Company's share is $.5 million, as of March 31, 1995.
Estimated TMI-2 Future Costs as of March 31, 1995 and December 31, 1994 for
the Company are as follows:
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March 31, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $ 63 $ 63
Nonradiological Cost of Removal 18 18
Incremental Monitored Storage 5 5
Total $ 86 $ 86
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At March 31, 1995, $45 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and
$46 million was recoverable from customers and included in Three Mile Island
Unit 2 Deferred Costs on the balance sheet. The Company 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 is 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
insurance proceeds would be available for the repair and restoration of that
station.
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The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial protection, a nuclear incident at
any licensed nuclear power reactor in the country, including those owned by
the GPU System, could result in assessments of up to $79 million per incident
for each of the GPU System's two operating reactors (TMI-2 being excluded
under an exemption received from the NRC in 1994), subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, the GPU System is also
subject to retrospective premium assessments of up to $68 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 March 31, 1995, facilities covered by these agreements having 882 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
1,176 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 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, including (1) attempting to
convert must-run agreements to dispatchable agreements; (2) attempting to
renegotiate prices of the agreements and (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.
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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 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 Balance Sheet, and regulatory liabilities are reflected in the
Deferred Credits and Other Liabilities section of the Balance Sheet.
Regulatory assets and liabilities, as reflected in the March 31, 1995 Balance
Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 136,706 $ 38,854
TMI-2 deferred costs 134,663 -
Unamortized property losses 103,167 -
N.J. unit tax 55,481 -
Unamortized loss on reacquired debt 36,420 -
DOE enrichment facility decommissioning 26,673 -
Load and demand side management programs 43,385 -
Other postretirement benefits 25,675 -
Manufactured gas plant remediation 28,584 -
Nuclear fuel disposal fee 26,309 -
Storm damage 22,953 -
N.J. low level radwaste disposal 18,299 -
Oyster Creek deferred costs 16,108 -
Other 2,303 1,961
Total $ 676,726 $ 40,815
Income taxes recoverable/refundable through future rates: Represents amounts
deferred due to the implementation of FAS 109, "Accounting for Income Taxes",
in 1993.
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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 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.
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 clauses.
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 an NJBPU order dated February 1993, and other DSM program
expenditures that are recovered annually.
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: In 1993, the NJBPU approved a mechanism
for the recovery by the Company of future costs when expenditures exceed prior
collections. The NJBPU order provides for interest to be credited to
customers until the overrecovery is eliminated and for future costs to be
amortized over seven years with interest. 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.
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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
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 (NJDEP) investigation and remediation of 17
formerly owned manufactured gas plant sites. A portion of one of these sites
has been repurchased by the Company. The Company has also entered into
various cost-sharing agreements with other utilities for some of the sites.
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As of March 31, 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
collections. The NJBPU decision provides for interest to be credited to
customers until the overrecovery is eliminated and for future costs to be
amortized over seven years with interest. A final NJBPU order dated December
16, 1994 indicated that interest is to be accrued retroactive to June 1993.
The Company is pursuing reimbursement of the remediation costs from its
insurance carriers. In November 1994, the Company filed a complaint with the
Superior Court of New Jersey against several of its insurance carriers,
relative to these manufactured gas plant sites. The Company requested the
Court to order the insurance carriers to reimburse 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 stations'
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.
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The Company and its affiliates have entered contract negotiations with
three other utilities to purchase capacity and energy for various periods
through 2004. These agreements, including contracts under negotiation, will
provide for up to 1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW
by 2004. For the years 1995 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's contract negotiations are the result of its all-source solicitation
for short- to intermediate-term energy and capacity.
The Company has commenced construction of a 141 MW gas-fired combustion
turbine at its Gilbert Generating station. This 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. On February 28, 1995, the NJDEP issued an air permit for
the facility based, in part, on the NJBPU's December 21, 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 to the Appellate Division of the New
Jersey Superior Court, and has stated that it also intends to appeal the April
19, 1995 order of the NJBPU denying such group's motion for reconsideration of
the NJBPU's December 21, 1994 order. 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 1993, the Company and the other New Jersey electric utilities filed motions
for summary judgment with the NJBPU. Ratepayer Advocate has filed a brief in
opposition to the utilities' summary judgment motions including a statement
from its consultant that in his view, the "double recovery" for the Company
for the 1988-92 LEAC periods would be approximately $102 million. In 1994,
the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent
LEACs remain open for further investigation. This matter is pending before a
NJBPU Administrative Law Judge. The Company estimates that the potential
exposure from the 1992 LEAC period through February 1996, the end of the
current LEAC period, is approximately $55 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.
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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
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 first quarter ended March
31, 1995, were $32.5 million compared with $49.4 million for the first quarter
of 1994. The decrease in first quarter earnings was due primarily to lower
interest income as compared to last year, when the Company recognized
nonrecurring net interest income of $7.4 million after-tax which resulted from
refunds of previously paid federal income taxes related to the tax retirement
of Three Mile Island Unit 2 (TMI-2), and lower sales due to warmer winter
weather this year as compared to last year. Also contributing to the earnings
decline was higher reserve capacity expense and the recognition in 1994 of a
performance award for the efficient operation of the Company's nuclear
generating stations.
These reductions were partially offset by lower operation and
maintenance expense (O&M) and increased sales from new customer growth.
OPERATING REVENUES:
Total revenues for the first quarter of 1995 decreased 3.9% to $468
million as compared to the first quarter of 1994. The components of the
changes are as follows:
(In Millions)
Kilowatt-hour (KWH) revenues
(excluding energy portion) $(13.1)
Energy revenues (3.1)
Other revenues (2.7)
Decrease in revenues $(18.9)
Kilowatt-hour revenues
KWH revenues decreased due to lower residential and commercial sales
resulting from warmer winter temperatures this year as compared to last year.
New customer additions in the residential and commercial sectors partially
offset the decrease due to weather.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues decreased primarily as a result of lower sales to
customers offset partially by higher sales to other utilities.
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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 first quarter were negatively impacted by higher
reserve capacity expense resulting primarily from a one-time $5.9 million pre-
tax charge from another utility and higher payments to the Pennsylvania-
New Jersey-Maryland Interconnection.
Other operation and maintenance
The decrease in other O&M expense included payroll and benefits savings
resulting from a workforce reduction in 1994 and lower 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, net
The decrease was primarily attributable to lower interest income as
compared to last year, when the Company recognized $14.7 million of interest
income from refunds of previously paid federal income taxes related to the tax
retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for the
tax years after TMI-2 was retired.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt
Interest on long-term debt was lower primarily as a result of lower debt
levels for the three month period this year as compared to last year.
Other interest
Other interest expense decreased due 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.
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LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the first quarter of 1995 consisted of
cash construction expenditures of $48 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 first quarter of 1995, the Company issued $50 million of long-
term debt. The proceeds from the issuance will be used to moderate future
short-term debt levels. In the second quarter of 1995, the Company
repurchased in the market, 60,000 shares of its 7.52% Series K cumulative
preferred stock. This repurchase, along with the expected issuance of monthly
income preferred securities, is one component of the Company's effort to
reduce preferred equity capital costs, while striving to obtain a preferred
equity target ratio of 8%-10% of capitalization. The repurchased shares may
be used to satisfy future sinking fund requirements.
The Company is awaiting Securities and Exchange Commission (SEC)
authorization to issue, through a special-purpose finance subsidiary, up to
$125 million of monthly income preferred securities. The securities are
expected to be issued in 1995 and the proceeds used primarily to repay
outstanding short-term debt.
GPU has obtained regulatory authorization from the SEC to issue up to
five million shares of additional common stock through 1996. The proceeds
from any sale of such additional common stock are expected to be used to
increase the Company and its affiliates' common equity ratios and reduce GPU
short-term debt. GPU will monitor the capital markets as well as its
capitalization ratios relative to its targets to determine whether, and when,
to issue such shares.
The Company has regulatory authority to issue and sell first mortgage
bonds, which may be issued as secured medium-term notes, and preferred stock
through June 1995. The Company is seeking to extend such authorization
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 currently has interest and
dividend coverage ratios well in excess of indenture and charter restrictions.
COMPETITIVE ENVIRONMENT:
In March 1995, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking (NOPR) on open access non-discriminatory
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transmission services by public utilities and transmitting utilities, and a
supplemental NOPR on recovery of stranded costs superseding an earlier June
1994 NOPR, and other related NOPRs. The new rules, if adopted, would in
essence provide open access to the interstate electric transmission network
and thereby encourage a fully competitive wholesale electric power market.
Among other things, the FERC's proposal would (a) require electric
utilities to file non-discriminatory open access transmission tariffs for both
network and point-to-point service which would be available to all wholesale
sellers and buyers of electricity; (b) require utilities to accept service
under these new tariffs for their own wholesale transactions and (c) permit
utilities to recover their legitimate and verifiable "stranded costs" incurred
when a franchise customer elects to purchase power from another supplier using
the utility's transmission system.
While the proposed rule does not provide for "corporate unbundling",
which the FERC defines as the disposing of ancillary services or creating
separate affiliates to manage transmission services, it does provide for
"functional unbundling". In the NOPR, the FERC describes "functional
unbundling" to mean that (a) the utility must make the same charges for
transmission services to its new wholesale customers as are provided by the
tariff under which it offers these services to others; (b) the tariff must
include separate rates for transmission and ancillary services; and (c) the
utility is restricted to using the same electronic network as is used by its
customers to obtain system transmission information when engaging in wholesale
transactions, and the utility may not have access to any internal system
transmission data which is not otherwise available to non-affiliated third
parties.
With respect to stranded costs, the FERC proposed to provide recovery
mechanisms where stranded costs result from municipalization or other
instances where former retail customers become wholesale customers, as well as
for wholesale stranded costs. The states would be expected to provide for
recovery of stranded costs attributable to retail wheeling or direct access
programs, and the FERC would intervene only when the state regulatory agency
lacked necessary authority.
Also in March 1995, prior to the FERC's issuance of the NOPR, the Company
filed with the FERC proposed open access transmission tariffs. Such proposed
tariffs provide 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. While the Company believes that the proposed transmission tariffs
are consistent with the FERC's previously issued Transmission Pricing Policy
Statement, it does not know whether or to what extent the FERC will require
modifications to any of the proposed terms and conditions of transmission
tariffs.
In March 1995, energy rate flexibility legislation was introduced in the
New Jersey Senate. If enacted, the legislation would enable electric
utilities to offer rate discounts to certain customers and allow these
customers access to competitive markets for power. The bill would also allow
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utilities to recover 80% of lost revenue as a result of a rate discount if
certain conditions are met. It would also provide utilities the opportunity
to propose to the New Jersey Board of Public Utilities (NJBPU) alternative
ways to set rates.
In April 1995, legislation was introduced in the U.S. Senate that would
repeal Section 210 of the Public Utility Regulatory Policies Act of 1978
(PURPA). Under that section of PURPA, among other things, electric utilities
are required to purchase power from certain qualifying nonutility generators.
In March 1994, GPU announced its intention to form a new subsidiary, GPU
Generation Corporation (GPUGC), to operate, maintain and repair the non-
nuclear generation facilities owned by Company and its affiliates as well as
undertake responsibility to construct any new non-nuclear generation
facilities which the Company and its affiliates may need in the future.
During 1994, the Company and its affiliates received regulatory approvals from
the NJBPU and Pennsylvania Public Utility Commission to enter into an
operating agreement with GPUGC. In June 1994, however, Allegheny Electric
Cooperative (AEC), a wholesale customer of an affiliate, filed a request for
evidentiary hearing in the application filed with the SEC to form GPUGC. The
intervention does not challenge the formation of GPUGC, but purports to be
concerned with costs that GPUGC will charge the Company and its affiliates,
from which AEC ultimately purchases power. The Company and its affiliates
have opposed AEC's request and the matter is pending before the SEC.
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 to the Appellate Division of the New Jersey Superior Court, and
has stated that it also intends to appeal the April 1995 order of the NJBPU
denying such group's motion for reconsideration of the NJBPU's December 1994
order. There can be no assurance as to the outcome of this proceeding.
Managing Nonutility Generation
The Company is 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. In addition, the Company
intends to avoid, to the maximum extent practicable, entering into any new
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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 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. The Company intends to petition the U.S. Supreme
Court to review the Court of Appeals decision. 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 rulings, the FERC has 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 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, where the matter is now pending.
In May 1994, the NJBPU issued an order granting two nonutility
generators, aggregating 200 MW, a final in-service date extension for projects
originally scheduled to be operational in 1997. In June 1994, the Company
appealed the NJBPU's decision to the Appellate Division of the New Jersey
Superior Court. Oral argument on the appeal was held in March 1995 and the
matter is pending before the Appellate Division. The NJBPU order extends the
in-service dates for one year plus the appeal period.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 882 MW of capacity are currently
in service and an additional 294 MW are currently scheduled or anticipated to
be in service by 1999.
ACCOUNTING ISSUES:
In March 1995, the Financial Accounting Standards Board (FASB) issued FAS
121, "Accounting for the Impairment of Long-Lived Assets", which is effective
for fiscal years beginning after June 15, 1995. FAS 121 requires that long-
lived assets, identifiable intangibles, capital leases and goodwill be
reviewed for impairment whenever events occur or changes in circumstances
indicate that the carrying amount of the assets may not be recoverable. In
addition, FAS 121 requires that regulatory assets meet the recovery criteria
of FAS 71, "Accounting for the Effects of Certain Types of Regulation", on an
ongoing basis in order to avoid a writedown.
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FAS 121 implementation in 1996 is not expected to have an impact on the
Company since the carrying amount of all assets, including regulatory assets,
is considered recoverable. However, as the Company enters a more competitive
environment, some assets could potentially be subject to impairment, thereby
necessitating writedowns or writeoffs, which could have a material adverse
effect on the Company's results of operations and financial position.
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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
GPUN believes that the Oyster Creek nuclear station will require
additional on-site storage capacity, beginning in 1996, in order
to maintain its full core reserve margin, 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 March 1994, the Lacey Township Zoning Board of Adjustment
issued a use variance for the on-site storage facility. In May
1994, however, Berkeley Township and another party appealed to the
New Jersey Superior Court to overturn the decision. In April
1995, the Superior Court remanded the variance application to the
Board of Adjustment for the limited purpose of permitting the
plaintiffs to present expert testimony. Construction of the
facility, which is scheduled for completion in September 1995, is
continuing.
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:
For the month of April 1995, dated April 20, 1995, under Item
5 (Other Events).
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Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
JERSEY CENTRAL POWER & LIGHT COMPANY
May 4, 1995 By: /s/ D. Baldassari
D. Baldassari, President
May 4, 1995 By: /s/ D. W. Myers
D. W. Myers, Vice President -
Operations Support and Comptroller
(Principal Accounting Officer)
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Exhibit 12
Page 1 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
UNAUDITED
Three Months Ended
March 31, 1995 March 31, 1994
OPERATING REVENUES $468 034 $486 910
OPERATING EXPENSES 398 473 394 135
Interest portion
of rentals (A) 3 359 2 833
Net expense 395 114 391 302
OTHER INCOME:
Allowance for funds
used during
construction 1 297 707
Other income, net 3 618 15 434
Total other income 4 915 16 141
EARNINGS AVAILABLE FOR FIXED
CHARGES AND PREFERRED
STOCK DIVIDENDS
(excluding taxes
based on income) $ 77 835 $111 749
FIXED CHARGES:
Interest on funded
indebtedness $ 22 499 $ 23 715
Other interest 1 993 5 313
Interest portion
of rentals (A) 3 359 2 833
Total fixed charges $ 27 851 $ 31 861
RATIO OF EARNINGS TO
FIXED CHARGES 2.79 3.51
Preferred stock dividend
requirement 3 699 3 699
Ratio of income before
provision for income
taxes to net income (B) 138.0% 150.5%
Preferred stock dividend
requirement on a pretax
basis 5 104 5 567
Fixed charges, as above 27 851 31 861
Total fixed charges
and preferred
stock dividends $ 32 955 $ 37 428
RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS 2.36 2.99
<PAGE>
Exhibit 12
Page 2 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503
(In Thousands)
UNAUDITED
NOTES:
(A) The Company has included the equivalent of the interest portion of all
rentals charged to income as fixed charges for this statement and has
excluded such components from Operating Expenses.
(B) Represents income before provision for income taxes of $49,984 and
$79,888, for the three months ended March 31, 1995 and March 31, 1994,
respectively, divided by net income of $36,211 and $53,097, respectively.
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> MAR-31-1995
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,875,595
<OTHER-PROPERTY-AND-INVEST> 274,165
<TOTAL-CURRENT-ASSETS> 364,230
<TOTAL-DEFERRED-CHARGES> 818,231
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,332,221
<COMMON> 153,713
<CAPITAL-SURPLUS-PAID-IN> 435,715
<RETAINED-EARNINGS> 804,752
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,394,180
150,000
37,741
<LONG-TERM-DEBT-NET> 1,218,496
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0
<CAPITAL-LEASE-OBLIGATIONS> 4,150
<LEASES-CURRENT> 95,935
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,384,280
<TOT-CAPITALIZATION-AND-LIAB> 4,332,221
<GROSS-OPERATING-REVENUE> 468,034
<INCOME-TAX-EXPENSE> 12,334
<OTHER-OPERATING-EXPENSES> 398,473
<TOTAL-OPERATING-EXPENSES> 410,807
<OPERATING-INCOME-LOSS> 57,227
<OTHER-INCOME-NET> 2,407
<INCOME-BEFORE-INTEREST-EXPEN> 59,634
<TOTAL-INTEREST-EXPENSE> 23,423
<NET-INCOME> 36,211
3,699
<EARNINGS-AVAILABLE-FOR-COMM> 32,512
<COMMON-STOCK-DIVIDENDS> 0 <F1>
<TOTAL-INTEREST-ON-BONDS> 22,499
<CASH-FLOW-OPERATIONS> 137,755
<EPS-PRIMARY> 0
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<FN>
<F1> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
