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 1-446
Metropolitan Edison Company
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0870160
(State or other jurisdiction of (I.R.S. Employer)
incorporation or organization) Identification No.)
2800 Pottsville Pike
Reading, Pennsylvania 19605
(Address of principal executive offices) (Zip Code)
(610) 929-3601
(Registrant's telephone number, including area code)
N/A
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
The number of shares outstanding of each of the issuer's classes of
voting stock, as of April 30, 1995, was as follows:
Common stock, no par value: 859,500 shares outstanding.
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Metropolitan Edison 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 18
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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METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
ASSETS
Utility Plant:
In service, at original cost $2 157 914 $2 137 996
Less, accumulated depreciation 720 249 700 746
Net utility plant in service 1 437 665 1 437 250
Construction work in progress 109 267 105 035
Other, net 35 426 37 275
Net utility plant 1 582 358 1 579 560
Other Property and Investments:
Nuclear decommissioning trusts 71 751 65 100
Other, net 9 578 9 567
Total other property and investments 81 329 74 667
Current Assets:
Cash and temporary cash investments 1 717 9 246
Special deposits 1 121 1 896
Accounts receivable:
Customers, net 55 711 53 421
Other 21 288 16 736
Unbilled revenues 20 694 25 112
Materials and supplies, at average cost or less:
Construction and maintenance 40 939 39 365
Fuel 13 311 16 843
Deferred income taxes 4 245 4 720
Prepayments 24 275 7 522
Total current assets 183 301 174 861
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 5 431 5 534
Income taxes recoverable through future rates 206 479 201 679
Other 42 526 41 668
Total regulatory assets 254 436 248 881
Deferred income taxes 148 881 149 892
Other 11 980 8 418
Total deferred debits and other assets 415 297 407 191
Total Assets $2 262 285 $2 236 279
The accompanying notes are an integral part of the consolidated financial
statements.
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METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 66 273 $ 66 273
Capital surplus 345 200 341 616
Retained earnings 168 157 190 742
Total common stockholder's equity 579 630 598 631
Cumulative preferred stock 23 598 23 598
Preferred securities of subsidiary 100 000 100 000
Long-term debt 559 784 529 783
Total capitalization 1 263 012 1 252 012
Current Liabilities:
Debt due within one year 40 517 40 517
Notes payable 57 421 -
Obligations under capital leases 32 185 33 810
Accounts payable:
Affiliates 8 057 14 571
Other 81 087 96 061
Taxes accrued 19 710 40 435
Deferred energy credits 827 1 950
Interest accrued 10 553 19 006
Other 22 561 21 636
Total current liabilities 272 918 267 986
Deferred Credits and Other Liabilities:
Deferred income taxes 379 996 371 841
Unamortized investment tax credits 35 024 35 470
Three Mile Island Unit 2 future costs 172 281 170 593
Nuclear fuel disposal fee 26 221 25 836
Regulatory liabilities 33 494 37 534
Other 79 339 75 007
Total deferred credits and other liabilities 726 355 716 281
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 262 285 $2 236 279
The accompanying notes are an integral part of the consolidated financial
statements.
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METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
(Unaudited)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Revenues $205 749 $213 159
Operating Expenses:
Fuel 22 392 26 964
Power purchased and interchanged:
Affiliates 8 958 4 860
Others 43 514 45 477
Deferral of energy costs, net (1 105) (8 401)
Other operation and maintenance 52 641 53 837
Depreciation and amortization 22 670 21 534
Taxes, other than income taxes 13 659 14 967
Total operating expenses 162 729 159 238
Operating Income Before Income Taxes 43 020 53 921
Income taxes 11 865 14 007
Operating Income 31 155 39 914
Other Income and Deductions:
Allowance for other funds used during
construction 455 174
Other income/(expense), net (2 161) 30 194
Income taxes 791 (12 672)
Total other income and deductions (915) 17 696
Income Before Interest Charges and
Dividends on Preferred Securities 30 240 57 610
Interest Charges and Dividends on
on Preferred Securities:
Interest on long-term debt 11 012 10 718
Other interest 989 9 496
Allowance for other funds used during
construction (395) (406)
Dividends on preferred securities of subsidiary 2 250 -
Total interest charges and dividends
on preferred securities 13 856 19 808
Net Income 16 384 37 802
Preferred stock dividends 236 908
Earnings Available for Common Stock $ 16 148 $ 36 894
The accompanying notes are an integral part of the consolidated financial
statements.
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METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(Unaudited)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Activities:
Income before preferred stock dividends $ 16 384 $ 37 802
Adjustments to reconcile income to cash provided:
Depreciation and amortization 20 075 20 309
Amortization of property under capital leases 3 795 3 450
Nuclear outage maintenance costs, net 1 638 1 570
Deferred income taxes and investment
tax credits, net (139) 11 388
Deferred energy costs, net (1 105) (8 401)
Accretion income - (334)
Allowance for other funds used
during construction (455) (174)
Changes in working capital:
Receivables (2 424) (36 103)
Materials and supplies 1 958 6 909
Special deposits and prepayments (16 758) (20 621)
Payables and accrued liabilities (36 543) 1 568
Other, net 3 501 (5 068)
Net cash provided (required) by operating
activities (10 073) 12 295
Investing Activities:
Cash construction expenditures (37 999) (30 421)
Contributions to decommissioning trusts (2,550) (2 939)
Other, net 41 40
Net cash used for investing activities (40 508) (33 320)
Financing Activities:
Issuance of long-term debt 29 820 49 687
Increase in notes payable, net 57 300 2 662
Retirement of long-term debt - (26 000)
Capital lease principal payments (3 832) (4 276)
Dividends paid on common stock (40 000) -
Dividends paid on preferred stock (236) ( 908)
Net cash provided by financing
activities 43 052 21 165
Net increase (decrease) in cash and temporary
cash investments from above activities (7 529) 140
Cash and temporary cash investments, beginning
of period 9 246 938
Cash and temporary cash investments, end of period $ 1 717 $ 1 078
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 24 329 $ 20 487
Income taxes paid $ 29 344 $ 4 606
New capital lease obligations incurred $ 1 858 $ 2 655
The accompanying notes are an integral part of the consolidated financial
statements.
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METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Metropolitan Edison Company (the Company), a Pennsylvania corporation
incorporated in 1922, 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 York
Haven Power Company, the owner of a small hydroelectric generating station,
and Met-Ed Preferred Capital, Inc., which is the general partner of Met-Ed
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 Jersey Central Power & Light Company (JCP&L) and
Pennsylvania Electric Company (Penelec). The Company, JCP&L 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 Subsidiaries; 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 consolidated
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 two major nuclear projects--Three
Mile Island Unit 1 (TMI-1), which is an operational generating facility, 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, JCP&L and Penelec in the
percentages of 50%, 25% and 25%, respectively. At March 31, 1995 and December
31, 1994, the Company's net investment in TMI-1 and TMI-2, including nuclear
fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2
March 31, 1995 $307 $6
December 31, 1994 $311 $6
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
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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 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-
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Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment. In July 1994, the Court
granted defendants' motion for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals 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 TMI-1 by 2014, the end of the plant's license term. 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 $79 million. 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 a site-specific study of TMI-1
that considered various decommissioning plans and estimated the cost of
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decommissioning the radiological portions of TMI-1 to range from approximately
$225 to $309 million, of which the Company's share would range from $113
million to $155 million (in 1994 dollars). In addition, the study estimated
the cost of removal of nonradiological structures and materials for TMI-1 at
$74 million, of which the Company's share is $37 million (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 1991 to TMI-2's
external trust and will await resolution of the case pending before the
Pennsylvania Supreme Court before making any further contributions for amounts
written off by the Company in 1994. Amounts deposited in external trusts,
including the interest earned on these funds, are classified as Nuclear
Decommissioning Trusts on the balance sheet.
TMI-1:
The Pennsylvania Public Utility Commission (PaPUC) previously granted
the Company revenues for decommissioning costs of TMI-1 based on its share of
the NRC funding target and nonradiological cost of removal as estimated in the
site-specific study. 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
$25 million at March 31, 1995. TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 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 $1 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 $127 $125
Nonradiological Cost of Removal 36 36
Incremental Monitored Storage 9 9
Total $172 $170
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At March 31, 1995, $44 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet.
In 1993, a PaPUC rate order for the Company allowed for the future
recovery of certain TMI-2 retirement costs. The Pennsylvania Office of
Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's
1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order.
In December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to
review that decision. Oral argument was held on April 27, 1995, and the
matter is pending. As a consequence of the Commonwealth Court decision, the
Company recorded pre-tax charges totaling $127.6 million during 1994. The
Company will await resolution of the appeal pending before the Pennsylvania
Supreme Court before making any nonrecoverable funding contributions to
external trusts for their share of these costs. The Company will be similarly
required to charge to expense its share of future increases in the estimate of
the costs of retiring TMI-2 if the Pennsylvania Supreme Court does not reverse
the Commonwealth Court's decision. Future earnings on trust fund deposits for
the Company will be recorded as income. Prior to the Commonwealth Court's
decision, the Company contributed $40 million to external trusts relating to
its share of the accident-related portion of the decommissioning liability.
This contribution was not recovered from customers and has been expensed.
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 $.50
million. The Company and its affiliates estimate that the remaining annual
storage costs will total $19 million, of which the Company's share is $9
million, through 2014, the expected retirement date of TMI-1.
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 totals $2.7 billion. 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
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and decommissioning costs. Consequently, there can be no assurance that in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial protection, a nuclear incident at
any licensed nuclear power reactor in the country, including those owned by
the GPU System, could result in assessments of up to $79 million per incident
for each of the GPU System's two operating reactors (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 $18 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 $2.6 million 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 239 MW of
capacity were in service and 117 MW were scheduled to commence operation in
1995. 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 $114 million, $170 million,
$280 million, $415 million and $418 million, respectively. These agreements,
in the aggregate, will provide approximately 833 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
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competitively priced at least for the near- to intermediate-term. The
projected cost of energy from new generation supply sources has also decreased
due to improvements in power plant technologies and reduced forecasted fuel
prices. As a result of these developments, the rates under virtually all of
the Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources.
The Company and its affiliates are seeking to reduce the above market
costs of these nonutility generation agreements, 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 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 PaPUC and the New
Jersey Board of Public Utilities (NJBPU), 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 $90 million to $140 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
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charged to and collected from customers. This criteria requires
consideration of anticipated changes in levels of demand or
competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various
reasons, including deregulation, a change in the method of regulation, or a
change in the competitive environment for the utility's regulated services.
Regardless of the reason, a utility whose operations cease to meet those
criteria should discontinue application of FAS 71 and report that
discontinuation by eliminating from its balance sheet the effects of any
actions of regulators that had been recognized as assets and liabilities
pursuant to FAS 71 but which would not have been recognized as assets and
liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and
meets the above criteria, FAS 71 accounting may only be applied to that
portion. Write-offs of utility plant and regulatory assets may result for
those operations that no longer meet the requirements of FAS 71. In addition,
under deregulation, the uneconomical costs of certain contractual commitments
for purchased power and/or fuel supplies may have to be expensed currently.
Management believes that to the extent that the Company no longer qualifies
for FAS 71 accounting treatment, a material adverse effect on its results of
operations and financial position may result.
In accordance with the provisions of FAS 71, the Company has deferred
certain costs pursuant to actions of the PaPUC 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 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 March 31, 1995 Consolidated Balance Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 206,479 $ 29,287
TMI-2 deferred costs 5,431 -
TMI-2 tax refund - 4,207
Unamortized property losses 2,604 -
Unamortized loss on reacquired debt 7,486 -
DOE enrichment facility decommissioning 11,477 -
Other postretirement benefits 20,656 -
Other 303 -
Total $ 254,436 $ 33,494
Income taxes recoverable/refundable through future rates: Represents amounts
deferred due to the implementation of FAS 109, "Accounting for Income Taxes,"
in 1993.
TMI-2 deferred costs: Represents costs that are being recovered through retail
rates for the remaining investment in the plant and fuel core.
-15-
<PAGE>
TMI-2 tax refund: Represents the tax refund related to the tax abandonment of
TMI-2. This balance is being amortized by the Company concurrent with its
return to customers through a base rate credit.
Unamortized property losses: The NRC has mandated that the design of nuclear
reactors be documented. As a result, the Company's share of the costs
incurred in documenting TMI-1 plant design, in addition to costs incurred in a
study used to assess the vulnerability of nuclear reactors to severe
accidents, are recorded in this account. The study costs are amortized over
the life of the plant.
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.
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.
Amounts related to the decommissioning of TMI-1, 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 $145 million for air pollution
control equipment by the year 2000. In developing its least-cost plan to
comply with the Clean Air Act, the GPU System 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. In September
1994, the Ozone Transport Commission (OTC), consisting of representatives of
12 northeast states (including New Jersey and Pennsylvania) and the District
-16-
<PAGE>
of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes
necessary to meet ambient air quality standards for ozone and the statutory
deadlines set by the Clean Air Act. The Company expects that the U.S.
Environmental Protection Agency (EPA) will approve the proposal, and that as a
result, the Company will spend an estimated $10 million, beginning in 1997, to
meet the reductions set by the OTC. The OTC requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met, at that time, have not been finalized. The Company and its affiliates
are unable to determine what, if any, additional costs will be incurred.
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 4 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 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 $115 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 long-term contracts with nonaffiliated
mining companies for the purchase of coal for certain generating stations in
which it has ownership interests. The contracts, which expire between 1995
and the end of the expected service lives of the generating stations, require
the purchase of either fixed or minimum amounts of the stations' coal
requirements. The price of the coal under the contracts is based on
adjustments of indexed cost components. The Company's share of the cost of
coal purchased under these agreements is expected to aggregate $27 million for
1995.
-17-
<PAGE>
At the request of the PaPUC, the Company, as well as other affected
Pennsylvania electric utilities, have supplied to the PaPUC proposals for the
establishment of a nuclear performance standard. The PaPUC has not yet acted
on these proposals.
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.
-18-
<PAGE>
Metropolitan Edison Company and Subsidiary Companies
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 $16.1 million compared to $36.9 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 $13 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). Earnings were also negatively affected
by lower sales due to warmer winter weather this year as compared to last year
and higher reserve capacity expense.
OPERATING REVENUES:
Total revenues for the first quarter of 1995 decreased 3.5% to $205.7
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) $ (7.2)
Energy revenues 1.7
Other revenues (1.9)
Decrease in revenues $ (7.4)
Kilowatt-hour revenues
KWH revenues decreased due primarily to lower residential 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 increased primarily as a result of increased sales
to other utilities.
-19-
<PAGE>
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 higher payments to the
Pennsylvania-New Jersey-Maryland Interconnection and the buy-out of a
nonutility generation power purchase agreement.
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.
Depreciation and amortization
Depreciation and amortization expense increased primarily as a result of
increases in depreciable plant. Additions to utility plant consisted
primarily of additions to existing generating facilities to maintain system
reliability and additions to the transmission and distribution system related
to customer growth.
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 was primarily attributable to lower interest income as
compared to last year, when the Company recognized $29.8 million in 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:
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 $7 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.
-20-
<PAGE>
Dividends on preferred securities of subsidiary
During the third quarter of 1994, the Company issued $100 million of
monthly income preferred securities through a special-purpose finance
subsidiary. Dividends on these securities are payable monthly.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the first quarter of 1995 consisted of
cash construction expenditures of $38 million. Construction expenditures for
the year are forecasted to be $115 million. Expenditures for maturing debt
are expected to be $41 million for 1995. Management estimates that
approximately one-half of the capital needs in 1995 will be satisfied through
internally generated funds.
FINANCING:
During the first quarter of 1995, the Company issued $30 million of long-
term debt. The proceeds from the issuance were used to reduce short-term
debt.
GPU has obtained regulatory authorization from the Securities and
Exchange Commission (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 1995. Under existing authorization, the Company may issue senior
securities in the amount of $220 million, of which $100 million may consist of
preferred stock. The Company, through its special-purpose subsidiary, has
remaining regulatory authority to issue an additional $25 million of monthly
income preferred securities. 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. As a result of the second quarter 1994
write-off of TMI-2 retirement costs, together with certain other costs
recognized in the same period, the Company will be unable to meet the interest
and preferred dividend coverage requirements of its indenture and charter,
respectively, until the third quarter of 1995. Therefore, the Company's
ability to issue senior securities through June 1995 will be limited to the
issuance of first mortgage bonds on the basis of $35 million of previously
issued and retired bonds. The ability of the Company to issue, through its
special-purpose subsidiary, its remaining authorized monthly income preferred
securities, is not affected by these write-offs since these securities have no
such coverage restrictions.
-21-
<PAGE>
COMPETITIVE ENVIRONMENT:
In March 1995, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking (NOPR) on open access non-discriminatory
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.
-22-
<PAGE>
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 the 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 Pennsylvania Public Utility Commission (PaPUC) and New Jersey Board of
Public Utilities 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.
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.
THE SUPPLY PLAN:
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
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 April 1995, the Company reached a buy-out agreement with the developer
of a 13 MW nonutility generating facility. The Company estimates that the
buy-out of the uneconomic power purchase contract will save its customers $16
million over 25 years. The Company has petitioned the PaPUC for approval to
recover from customers the $1.65 million buy-out cost.
In April 1995, the Company filed a petition with the PaPUC requesting
that the PaPUC rescind its 1992 order directing the Company to enter into a
long-term power purchase agreement with the developers of a proposed 100 MW
nonutility generating facility in the City of Scranton, Pennsylvania. The
Company is seeking relief from that order on the grounds that the project
developers no longer plan to construct the project in the City of Scranton
which was a principal reason for the PaPUC's order. The Company also contends
that the rates payable under the contract, which is not in effect since the
PaPUC has not granted the Company energy cost rate recovery, are $298 million
in excess of the projected costs of alternative power.
-23-
<PAGE>
In May 1995, the Company filed a petition for enforcement and declaratory
order with the FERC requesting that the FERC declare the PaPUC's PURPA
implementation procedures unlawful. Specifically, the Company contends that
the PaPUC's procedures that result in orders to enter into contracts with
qualifying facilities at prices based on the costs of a "coal proxy" plant
violate PURPA and the FERC's implementing regulations. The Company has
requested that the FERC declare void power purchase agreements and related
obligations representing 327 MW of capacity and energy which the PaPUC has
ordered the Company to enter into under this procedure.
In 1994, a nonutility generator requested that the PaPUC order the
Company to enter into a long-term agreement to buy capacity and energy. The
Company sought to dismiss the request based on a May 1994 PaPUC order, which
granted the Company permission to obtain additional nonutility purchases
through competitive bidding until new PaPUC regulations have been adopted. In
September 1994, the Pennsylvania Commonwealth Court granted the PaPUC's
application to revise its May 1994 order for the purpose of reevaluating the
nonutility generator's right to sell power to the Company. The PaPUC
subsequently ordered that hearings be held in this matter. In March 1995, the
Company filed a motion seeking to dismiss the nonutility generator's petition.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 239 MW of capacity are currently
in service and an additional 594 MW are currently scheduled or anticipated to
be in service by 1999.
Conservation and Load Management
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of demand side management (DSM) costs and directed utilities to implement DSM
programs. The Company subsequently filed a DSM program that was expected to
be approved by the PaPUC in the first quarter of 1995. However, an industrial
intervenor had contested the PaPUC's guidelines and, in January 1995, the
Commonwealth Court reversed the PaPUC order. The PaPUC is appealing that
decision to the Pennsylvania Supreme Court. As a result, the nature and scope
of the Company's DSM program is uncertain at this time.
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.
-24-
<PAGE>
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.
-25-
<PAGE>
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 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).
-26-
<PAGE>
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
METROPOLITAN EDISON COMPANY
May 4, 1995 By: /s/ F. D. Hafer
F. D. Hafer, President
May 4, 1995 By: /s/ D. L. O'Brien
D. L. O'Brien, Comptroller
(Principal Accounting Officer)
-27-
Exhibit 12
METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES
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, March 31,
1995 1994
OPERATING REVENUES $205 749 $213 159
OPERATING EXPENSES (excluding
taxes based on income) 162 729 159 238
Interest portion of rentals (A) 1 144 1 385
Net expense 163 873 157 853
OTHER INCOME:
Allowance for funds used
during construction 850 580
Other income, net (2 161) 30 194
Total other income (1 311) 30 774
EARNINGS AVAILABLE FOR FIXED CHARGES $ 40 565 $ 86 080
FIXED CHARGES:
Interest on funded indebtedness $ 11 012 $ 10 718
Other interest (B) 3 239 9 496
Interest portion of rentals (A) 1 144 1 385
Total fixed charges $ 15 395 $ 21 599
RATIO OF EARNINGS TO FIXED CHARGES 2.63 3.99
Preferred stock dividend requirement $ 236 $ 908
Ratio of income before provision for
income taxes to net income (C) 167.6% 170.6%
Preferred stock dividend requirement
on a pre-tax basis 396 1 549
Fixed Charges, as above 15 395 21 599
Total fixed charges and preferred
stock dividends $ 15 791 $ 23 148
RATIO OF EARNINGS TO COMBINED FIXED
CHARGES AND PREFERRED STOCK DIVIDENDS 2.57 3.72
NOTES:
(A)The Company included the equivalent of the interest portion of all rentals
charged to income as fixed charges for this statement and excluded such
components from Operating Expenses.
(B)Includes dividends on preferred securities of subsidiary of $2,250 for 1995.
(C)Represents income before provision of income taxes of $27,458 and $64,481 for
1995 and 1994, respectively, divided by income of $16,384 and $37,802.
<PAGE>
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<PAGE>
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