UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1995
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-446
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 19640-0001
(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 October 31, 1995, was as follows:
Common stock, no par value: 859,500 shares outstanding.
Metropolitan Edison Company
Quarterly Report on Form 10-Q
September 30, 1995
Table of Contents
Page
PART I - Financial Information
Financial Statements:
Balance Sheets 3
Statements of Income 5
Statements of Cash Flows 6
Notes to Financial Statements 7
Management's Discussion and Analysis of
Financial Condition and Results of
Operations 18
PART II - Other Information 24
Signatures 25
_________________________________
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
September 30, December 31,
1995 1994
(Unaudited)
ASSETS
Utility Plant:
In service, at original cost $2 216 186 $2 137 996
Less, accumulated depreciation 756 363 700 746
Net utility plant in service 1 459 823 1 437 250
Construction work in progress 93 275 105 035
Other, net 47 978 37 275
Net utility plant 1 601 076 1 579 560
Other Property and Investments:
Nuclear decommissioning trusts 84 500 65 100
Other, net 9 860 9 567
Total other property and investments 94 360 74 667
Current Assets:
Cash and temporary cash investments 4 131 9 246
Special deposits 1 256 1 896
Accounts receivable:
Customers, net 60 256 53 421
Other 25 448 16 736
Unbilled revenues 23 594 25 112
Materials and supplies, at average cost or less:
Construction and maintenance 41 033 39 365
Fuel 7 141 16 843
Deferred income taxes 9 829 4 720
Prepayments 10 036 7 522
Total current assets 182 724 174 861
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 117 974 5 534
Income taxes recoverable through future rates 217 135 201 679
Other 96 103 41 668
Total regulatory assets 431 212 248 881
Deferred income taxes 92 085 149 892
Other 13 753 8 418
Total deferred debits and other assets 537 050 407 191
Total Assets $2 415 210 $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
September 30, December 31,
1995 1994
(Unaudited)
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 66 273 $ 66 273
Capital surplus 355 200 341 616
Retained earnings 259 997 190 742
Total common stockholder's equity 681 470 598 631
Cumulative preferred stock 23 598 23 598
Company-obligated mandatorily redeemable
preferred securities 100 000 100 000
Long-term debt 603 267 529 783
Total capitalization 1 408 335 1 252 012
Current Liabilities:
Securities due within one year 15 019 40 517
Notes payable 1 100 -
Obligations under capital leases 45 656 33 810
Accounts payable:
Affiliates 14 393 14 571
Other 84 126 96 061
Taxes accrued 16 322 40 435
Deferred energy credits 12 034 1 950
Interest accrued 11 839 19 006
Other 45 170 21 636
Total current liabilities 245 659 267 986
Deferred Credits and Other Liabilities:
Deferred income taxes 408 379 371 841
Unamortized investment tax credits 34 041 35 470
Three Mile Island Unit 2 future costs 173 432 170 593
Nuclear fuel disposal fee 26 989 25 836
Regulatory liabilities 27 859 37 534
Other 90 516 75 007
Total deferred credits and other liabilities 761 216 716 281
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 415 210 $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 Nine Months
Ended September 30, Ended September 30,
1995 1994 1995 1994
Operating Revenues $241 664 $204 903 $637 755 $614 736
Operating Expenses:
Fuel 24 826 23 453 67 619 73 741
Power purchased and interchanged:
Affiliates 8 930 6 959 22 830 14 860
Others 43 732 37 656 125 209 121 811
Deferral of energy costs, net 8 102 (866) 9 834 (12 304)
Other operation and maintenance 63 313 55 486 171 154 202 240
Depreciation and amortization 30 536 21 003 74 967 64 566
Taxes, other than income taxes 14 352 12 918 41 082 40 907
Total operating expenses 193 791 156 609 512 695 505 821
Operating Income Before Income Taxes 47 873 48 294 125 060 108 915
Income taxes 12 752 16 036 30 449 27 935
Operating Income 35 121 32 258 94 611 80 980
Other Income and Deductions:
Allowance for other funds used during
construction 297 214 1 156 580
Other income/(expense), net 134 038 656 129 926 (98 219)
Income taxes (56 950) (191) (55 321) 42 607
Total other income and deductions 77 385 679 75 761 (55 032)
Income Before Interest Charges and
Dividends on Preferred Securities 112 506 32 937 170 372 25 948
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 11 841 11 048 34 375 32 459
Other interest 1 291 983 3 864 10 756
Allowance for borrowed funds used during
construction (267) (497) (1 009) (1 363)
Dividends on company-obligated mandatorily
redeemable preferred securities 2 250 950 6 750 950
Total interest charges and dividends
on preferred securities 15 115 12 484 43 980 42 802
Net Income/(Loss) 97 391 20 453 126 392 (16 854)
Preferred stock dividends 236 908 708 2 724
Earnings/(Loss) Available for Common Stock $ 97 155 $ 19 545 $125 684 $(19 578)
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
Nine Months
Ended September 30,
1995 1994
Operating Activities:
Net income/(loss) $126 392 $(16 854)
Adjustments to reconcile income/(loss) to cash provided:
Depreciation and amortization 64 014 60 899
Amortization of property under capital leases 9 950 10 900
Three Mile Island Unit 2 costs (118 209) 127 640
Voluntary enhanced retirement programs - 35 246
Nuclear outage maintenance costs, net (3 003) 4 648
Deferred income taxes and investment
tax credits, net 58 774 (54 699)
Deferred energy costs, net 9 834 (12 304)
Accretion income - (1 003)
Allowance for other funds used
during construction (1 156) (580)
Changes in working capital:
Receivables (14 030) 15 166
Materials and supplies 8 034 3 445
Special deposits and prepayments (2 654) (5 907)
Payables and accrued liabilities (15 682) (11 491)
Other, net (20 451) (5 863)
Net cash provided by operating activities 101 813 149 243
Investing Activities:
Cash construction expenditures (85 958) (92 159)
Contributions to decommissioning trusts (7 504) (8 038)
Other, net 12 75
Net cash used for investing activities (93 450) (100 122)
Financing Activities:
Issuance of long-term debt 87 911 49 687
Increase/(Decrease) in notes payable, net 1 100 (81 600)
Retirement of long-term debt (40 519) (26 016)
Capital lease principal payments (11 262) (11 296)
Issuance of company-obligated mandatorily
redeemable preferred securities - 96 732
Contributions from parent corporation 10 000 -
Dividends paid on common stock (60 000) (15 000)
Dividends paid on preferred stock (708) (2 724)
Net cash provided/(required) by financing
activities (13 478) 9 783
Net increase/(decrease) in cash and temporary cash
investments from above activities (5 115) 58 904
Cash and temporary cash investments, beginning of year 9 246 938
Cash and temporary cash investments, end of period $ 4 131 $ 59 842
Supplemental Disclosure:
Interest paid $ 50 393 $ 51 095
Income taxes paid $ 52 353 $ 14 905
New capital lease obligations incurred $ 20 903 $ 2 930
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 Company and its affiliates; and Energy Initiatives, Inc., EI Power, Inc.
and EI Energy, Inc. (collectively, EI), which develop, own and operate
generation, transmission and distribution facilities in the United States and
in foreign countries. All of the Company's affiliates are wholly owned
subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, and EI are
referred to as the "GPU System".
These notes should be read in conjunction with the notes to 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 was derived from audited financial statements. For disclosures
required by generally accepted accounting principles, see the 1994 Annual
Report on Form 10-K.
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in 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 September 30, 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
September 30, 1995 $322 $2*
December 31, 1994 $311 $6*
* The Company has recovered substantially all of its investment in
TMI-2.
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
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construction and operation of nuclear facilities. The Company and its
affiliates may also incur costs and experience reduced output at their nuclear
plants because of the prevailing design criteria at the time of construction
and the age of the plants' systems and equipment. In addition, for economic
or other reasons, operation of these plants for the full term of their now-
assumed lives cannot be assured. Also, not all risks associated with the
ownership or operation of nuclear facilities may be adequately insured or
insurable. Consequently, the ability of electric utilities to obtain adequate
and timely recovery of costs associated with nuclear projects, including
replacement power, any unamortized investment at the end of each plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and after receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the United
States District Court for the Middle District of Pennsylvania. Some of the
claims also seek recovery for injuries from alleged emissions of radioactivity
before and after the accident.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for up to an aggregate of $335 million in
premium charges under such plan, and (c) an indemnity agreement with the NRC
for up to $85 million, bringing their total primary, secondary and tertiary
financial protection up to an aggregate of $560 million. Under the secondary
level, the Company and its affiliates are subject to a retrospective premium
charge of up to $5 million per reactor, or a total of $15 million, of which
the Company's share is $5 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers (the defendants) under a reservation of rights with respect to
any award of punitive damages. However, in March 1994, the defendants in the
TMI-2 litigation and the insurers agreed that the insurers would withdraw
their reservation of rights with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is scheduled to begin in June 1996. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the
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Price-Anderson Act to the extent that the funds to pay punitive damages do not
come out of the U.S. Treasury.
In an order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
In October 1995, the U.S. Court of Appeals for the Third Circuit ruled
that the Price-Anderson Act provides coverage under its primary and secondary
levels for punitive as well as compensatory damages, but that punitive damages
could not be recovered against the Federal Government. In so doing, the Court
of Appeals referred to the "finite fund" (the $560 million of financial
protection under the Price-Anderson Act) to which plaintiffs must resort to
get compensatory as well as punitive damages.
The Court of Appeals also found that the standard of care owed by the
defendants to a plaintiff was determined by the specific level of radiation
which was released into the environment, as measured at the site boundary,
rather than as measured at the specific site where the plaintiff was located
at the time of the accident (as GPU and the Company and its affiliates
proposed). The Court of Appeals also held, however, that each plaintiff still
must demonstrate exposure to radiation released during the TMI-2 accident and
that such exposure had resulted in injuries.
GPU and Company and its affiliates believe that any liability to which
they might be subject by reason of the TMI-2 accident and these Court of
Appeals decisions will not exceed the financial protection under the Price-
Anderson Act. GPU and the Company and its affiliates have filed a petition
with the Third Circuit Court seeking a rehearing and en banc reconsideration
of its decision that punitive damages are recoverable under the Price-Anderson
Act.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in
compliance with NRC regulations, setting forth a funding plan (employing the
external sinking fund method) for the decommissioning of their nuclear
reactors. Under this plan, the Company and its affiliates intend to complete
the funding for 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 1995 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
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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
decommissioning the radiological portions of the plant to range from
approximately $225 million to $309 million, of which the Company's share would
range from $113 million to $155 million (in 1995 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 1995 dollars).
The ultimate cost of retiring the Company's and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies. Such costs are subject to
(a) the type of decommissioning plan selected, (b) the escalation of various
cost elements (including, but not limited to, general inflation), (c) the
further development of regulatory requirements governing decommissioning,
(d) the absence to date of significant experience in decommissioning such
facilities and (e) the technology available at the time of decommissioning.
The Company and its affiliates charge to expense and contribute to external
trusts amounts collected from customers for nuclear plant decommissioning and
nonradiological costs. In addition, the Company has contributed amounts
written off for TMI-2 nuclear plant decommissioning in 1991 to TMI-2's
external trust (see TMI-2 Future Costs). Amounts deposited in external
trusts, including the interest earned on these funds, are classified as
Nuclear Decommissioning Trusts on the Balance Sheet.
In August 1995, a consultant to GPUN commenced site specific studies of
the TMI site, including both Units 1 and 2. GPUN expects these studies to be
completed in the fourth quarter of 1995.
The Financial Accounting Standards Board (FASB) is reviewing the utility
industry's accounting practices for nuclear plant retirement costs. If the
FASB's tentative conclusions are adopted, TMI-1 future retirement costs will
have to be recognized as a liability currently, rather than recorded over the
life of the plant (as is currently the practice), with an offsetting asset
recorded for amounts collectible through rates. Any amounts not collectible
through rates will have to be charged to expense. The FASB is expected to
release an Exposure Draft on decommissioning accounting practices in the
fourth quarter of 1995.
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
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site-specific study. Collections from customers for retirement expenditures
are deposited in external trusts. Provision for the future expenditure of
these funds has been made in accumulated depreciation, amounting to
$28 million at September 30, 1995. TMI-1 retirement costs are charged to
depreciation expense over its expected service life.
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 the nonradiological cost of
removal consistent with the TMI-1 site-specific study and have spent $3
million as of September 30, 1995, of which the Company's share is $1.5
million. Estimated TMI-2 Future Costs as of September 30, 1995 and December
31, 1994 are as follows:
September 30, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $128 $125
Nonradiological Cost of Removal 36 36
Incremental Monitored Storage 9 9
Total $173 $170
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the Balance Sheet. At September 30, 1995, $45 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet,
and $116 million was recoverable from customers and included in Three Mile
Island Unit 2 Deferred Costs on the Balance Sheet. Earnings on trust fund
deposits collected from customers are included in amounts shown on the Balance
Sheet under Three Mile Island Unit 2 Deferred Costs.
In 1993, a PaPUC rate order permitted the Company future recovery of
certain TMI-2 retirement costs. The Pennsylvania Office of Consumer Advocate
appealed that order to the Commonwealth Court, which reversed the PaPUC order
in 1994. Consequently, the Company recorded pre-tax charges totaling $127.6
million during 1994. These charges appear in the Other Income and Deductions
section of the 1994 Consolidated Statement of Income and are composed of
$82.6 million for radiological decommissioning costs, $35 million for the
nonradiological cost of removal and $10 million for incremental monitored
storage costs. In September 1995, the Pennsylvania Supreme Court reversed the
Commonwealth Court decision. The Company has therefore reversed the previous
write-off, resulting in pre-tax income of $127.6 million being credited to the
Other Income and Deductions section of the 1995 Consolidated Statement of
Income. However, notwithstanding the Supreme Court's decision, the Company
has determined that the recovery of the incremental monitored storage costs is
no longer probable, and has recorded a pre-tax charge to operating income of
$10 million in the third quarter of 1995.
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In 1991, the Company contributed $40 million to an external trust
relating to its share of the accident-related portion of the decommissioning
liability. This contribution was not recovered from customers and has been
expensed.
The Company intends to seek recovery for any increases in the non-
accident related portion of 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 $.5
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
and decommissioning costs. Consequently, there can be no assurance that in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third
parties for a nuclear incident at one of its sites to approximately
$8.9 billion. Coverage for the first $200 million of such liability is
provided by private insurance. The remaining coverage, or secondary financial
protection, is provided by retrospective premiums payable by all nuclear
reactor owners. Under secondary financial protection, a nuclear incident at
any licensed nuclear power reactor in the country, including those owned by
the GPU System, could result in assessments of up to $79 million per incident
for each of the GPU System's two operating reactors, subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, the GPU System is also
subject to retrospective premium assessments of up to $69 million, of which
the Company's share is $19 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 their
nuclear plants. Coverage commences after the first 21 weeks of the outage and
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continues for three years beginning at $2.6 million per week for TMI-1 for the
first year, and decreasing to 80 percent of such amounts 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 26 years. The majority of these
agreements contain certain contract limitations and subject the nonutility
generators to penalties for nonperformance. While some of these facilities
are dispatchable, most are must-run and generally obligate the Company to
purchase, at the contract price, the net output up to the contract limits. As
of September 30, 1995, facilities covered by these agreements having 335 MW of
capacity were in service. Estimated payments to nonutility generators from
1995 through 1999, assuming that all facilities which have existing
agreements, or which have obtained orders granting them agreements, enter
service, are $118 million, $151 million, $155 million, $243 million, and $311
million, respectively. These agreements, in the aggregate, will provide
approximately 485 MW of capacity and energy to the Company, at varying prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the GPU System's energy supply needs which has
caused the Company and its affiliates to change their supply strategy to seek
shorter-term agreements offering more flexibility. Due to the current
availability of excess capacity in the marketplace, the cost of near- to
intermediate-term (i.e., one to eight years) energy supply from existing
generation facilities is currently and expected to continue to be
competitively priced at least for the near- to intermediate-term. The
projected cost of energy from new generation supply sources has also decreased
due to improvements in power plant technologies and reduced forecasted fuel
prices. As a result of these developments, the rates under virtually all of
the Company's and its affiliates' nonutility generation agreements are
substantially in excess of current and projected prices from alternative
sources.
The Company and its affiliates are seeking to reduce the above market
costs of these nonutility generation agreements by (1) attempting to convert
must-run agreements to dispatchable agreements; (2) attempting to renegotiate
prices of the agreements; (3) offering contract buy-outs while seeking to
recover the costs through their energy clauses (see Managing Nonutility
Generation, in Management's Discussion and Analysis of Financial Condition and
Results of Operations) and (4) initiating proceedings before federal and state
administrative agencies, and in the courts, where appropriate. In addition,
the Company and its affiliates intend to avoid, to the maximum extent
practicable, entering into any new nonutility generation agreements that are
not needed or not consistent with current market pricing and are supporting
legislative efforts to repeal PURPA. These efforts may result in claims
against the GPU System for substantial damages. There can, however, be no
assurance as to what extent the Company's and its affiliates' efforts will be
successful in whole or in part.
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While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the PaPUC and 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 $240 million to $350 million annually, of
which the Company's share will range from $50 million to $80 million annually.
Regulatory Assets and Liabilities:
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of
regulatory commissions, the electric utility industry is moving toward a
combination of competition and a modified regulatory environment. In
accordance with Statement of Financial Accounting Standards No. 71 (FAS 71),
"Accounting for the Effects of Certain Types of Regulation", the Company's
financial statements reflect assets and costs based on current cost-based
ratemaking regulations. Continued accounting under FAS 71 requires that the
following criteria be met:
a) A utility's rates for regulated services provided to its customers
are established by, or are subject to approval by, an independent
third-party regulator;
b) The regulated rates are designed to recover specific costs of
providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of
competition, direct and indirect, it is reasonable to assume that
rates set at levels that will recover a utility's costs can be
charged to and collected from customers. This criteria requires
consideration of anticipated changes in levels of demand or
competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various
reasons, including deregulation, a change in the method of regulation, or a
change in the competitive environment for the utility's regulated services.
Regardless of the reason, a utility whose operations cease to meet those
criteria should discontinue application of FAS 71 and report that
discontinuation by eliminating from its Balance Sheet the effects of any
actions of regulators that had been recognized as assets and liabilities
pursuant to FAS 71 but which would not have been recognized as assets and
liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and
meets the above criteria, FAS 71 accounting may only be applied to that
portion. Write-offs of utility plant and regulatory assets may result for
those operations that no longer meet the requirements of FAS 71. In addition,
under deregulation, the uneconomical costs of certain contractual commitments
for purchased power and/or fuel supplies may have to be expensed currently.
Management believes that to the extent that the Company no longer qualifies
for FAS 71 accounting treatment, a material adverse effect on its results of
operations and financial position may result.
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In accordance with the provisions of FAS 71, the Company has deferred
certain costs pursuant to actions of the PaPUC and Federal Energy Regulatory
Commission (FERC) and is recovering or expects to recover such costs in
electric rates charged to customers. Regulatory assets are reflected in the
Deferred Debits and Other Assets section of the Consolidated Balance Sheet,
and regulatory liabilities are reflected in the Deferred Credits and Other
Liabilities section of the Consolidated Balance Sheet. Regulatory assets and
liabilities, as reflected in the September 30, 1995 Consolidated Balance
Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 217,135 $ 25,872
TMI-2 deferred costs 117,974 -
Unamortized property losses 2,622 -
NUG contract termination costs 51,499 -
Other postretirement benefits 24,595 -
Unamortized loss on reacquired debt 7,125 -
DOE enrichment facility decommissioning 10,066 -
Nuclear fuel disposal fee (1,006) -
Other 1,202 1,987
Total $ 431,212 $ 27,859
Income taxes recoverable/refundable through future rates: Represents amounts
deferred due to the implementation of FAS 109, "Accounting for Income Taxes",
in 1993.
TMI-2 deferred costs: Represents costs that are recoverable through rates for
the Company's remaining investment in the plant and fuel core, radiological
decommissioning in accordance with the NRC's funding target and allowances for
the cost of removal of nonradiological structures and materials. For
additional information, see TMI-2 Future Costs.
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.
NUG contract termination costs: Represents one-time costs incurred for
terminating power purchase contracts with nonutility generators (NUGs), for
which rate recovery is probable (See Managing Nonutility Generation, in
Management's Discussion and Analysis of Financial Condition and Results of
Operations).
Other postretirement benefits: Includes costs associated with the adoption of
FAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions", which are deferred in accordance with Emerging Issues Task Force
Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises".
-15-
Unamortized loss on reacquired debt: Represents premiums and expenses incurred
in the early redemption of long-term debt. In accordance with FERC
regulations, reacquired debt costs are amortized over the remaining original
life of the retired debt.
DOE enrichment facility decommissioning: These costs, representing payments
to the DOE over a 15-year period beginning in 1994, are currently being
collected through the Company's energy adjustment clause.
Nuclear fuel disposal fee: Represents amounts recoverable through rates for
estimated future disposal costs for spent nuclear fuel at TMI-1 in accordance
with the Nuclear Waste Policy Act of 1982.
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 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. In 1994, the
Ozone Transport Commission (OTC), consisting of representatives of 12
northeast states (including Pennsylvania and New Jersey) and the District 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 state implementation plans
consistent with 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 has stated that it anticipates that additional NOx reductions
will be necessary 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 additional costs, if any, will be
incurred.
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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 $113 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 $23 million for
1995.
During the normal course of the operation of its business, in addition
to the matters described above, the Company is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by the public, customers,
contractors, vendors and other suppliers of equipment and services and by
employees alleging unlawful employment practices. While management does not
expect that the outcome of these matters will have a material effect on the
Company's financial position or results of operations, there can be no
assurance that this will continue to be the case.
-17-
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 for the third quarter of 1995 were $97.2 million, compared to
$19.5 million for the same period ended 1994. The increase in third quarter
earnings was primarily due to the reversal of $72.8 million (after-tax) of
certain future Three Mile Island Unit 2 (TMI-2) retirement costs written-off
by the Company in the second quarter of 1994. The reversal of the TMI-2 write-
off resulted from a Pennsylvania Supreme Court decision that overturned a 1994
Pennsylvania Commonwealth Court order, and restored a March 1993 Pennsylvania
Public Utility Commission (PaPUC) order that allowed the Company to recover
certain future TMI-2 retirement costs from customers. In addition, there was a
charge to income of $5.7 million (after-tax) for TMI-2 monitored storage costs
which the Company believed would not be recoverable through ratemaking. Also
contributing to the third quarter earnings increase were higher sales
resulting from hotter summer temperatures compared to last year.
For the nine months ended September 30, 1995, earnings were $125.7
million, compared to a net loss of $19.6 million for the same period last
year. The same factors affecting the quarterly results also affected the
results for the nine month period. In addition, earnings for the nine months
ended last year included several one-time items that resulted in a net
earnings reduction of $79.9 million (after-tax).
The 1994 one-time items included a write-off of $72.8 million of certain
future TMI-2 retirement costs, $20.1 million for early retirement program
costs; and net interest income of $13.0 million resulting from refunds of
previously paid federal income taxes related to the tax retirement of TMI-2.
Lower operation and maintenance (O&M) expense, which included payroll and
benefit savings from the early retirement programs in 1994, as well as higher
sales resulting from new customer growth, also contributed to the 1995
increase. This increase was partially offset by lower sales in 1995 from
warmer winter and cooler spring weather compared to last year.
OPERATING REVENUES:
Total revenues for the third quarter of 1995 increased 17.9% to
$241.7 million, as compared to the third quarter of 1994. For the nine months
ended September 30, 1995, revenues increased 3.7% to $637.8 million, as
compared to the same period last year. The components of the changes are as
follows:
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(In Millions)
Three Months Nine Months
Ended Ended
September 30, 1995 September 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $10.4 $(5.7)
Energy revenues 21.2 29.5
Other revenues 5.2 (0.8)
Increase in revenues $36.8 $23.0
Kilowatt-hour revenues
The increase in KWH revenues for the three month period was due primarily
to higher sales from hotter summer temperatures in 1995. The decrease in KWH
revenues for the nine month period was due to lower residential sales from
milder winter and cooler spring weather in 1995.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased in both the three and nine month periods
primarily from higher energy cost rates and increased sales to other
utilities.
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, lower reserve capacity expense for both the three and nine month
periods contributed to earnings.
Fuel and Deferral of energy costs, net
Generally, changes in fuel expense and deferral of energy costs do not
affect earnings as they are offset by corresponding changes in energy
revenues.
Other operation and maintenance
The increase in other O&M for the three month period was due primarily to
a one-time $10.0 million (pre-tax) charge by the Company in 1995 for TMI-2
monitored storage costs deemed not recoverable through ratemaking. The
decrease in other O&M expense for the nine month period was primarily
attributable to a one-time $35.2 million (pre-tax) charge in 1994 related to
-19-
early retirement programs. Also contributing to the nine month O&M reduction
were payroll and benefits savings from the early retirement programs.
Depreciation and amortization
The increase in depreciation and amortization expense for the three and
nine month periods were due primarily to additions to plant in service, and
adjustments for TMI-2 decommissioning.
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 increase in other income/(expense) for the three month period was
attributable to the reversal of $127.6 million (pre-tax) of expense resulting
from a Pennsylvania Supreme Court decision. The Pennsylvania Supreme Court
decision overturned a 1994 Pennsylvania Commonwealth Court order, and restored
a March 1993 PaPUC order that allowed the Company to recover certain future
TMI-2 retirement costs from customers. In addition, $5.6 million (pre-tax) of
expense was reversed for escalations recorded since June 1994 for radiological
decommissioning, and nonradiological cost of removal.
The same factors affecting the three month period also affected the nine
month period. In addition, the nine month period increase included write-offs
in 1994 of $127.6 million (pre-tax) for certain future TMI-2 retirement costs
resulting from a Pennsylvania Commonwealth Court order. This increase was
partially offset by lower interest income of $29.8 million (pre-tax) resulting
from 1994 refunds of previously paid federal income taxes related to the tax
retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for tax
years after TMI-2 was retired.
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Other interest
Other interest expense for the nine month period decreased primarily from
the recognition in the first quarter of 1994 of interest expense related to
the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $7.0
million (pre-tax) charge to interest expense on additional amounts owed for
tax years in which depreciation deductions with respect to TMI-2 had been
taken.
Dividends on company-obligated mandatorily redeemable preferred securities
In 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.
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LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the nine months ended September 30, 1995
consisted of cash construction expenditures of $86 million. Construction
expenditures for the year are forecasted to be $113 million. Expenditures for
securities maturing in 1995 will total $41 million. Management estimates that
approximately one-half of the capital needs in 1995 will be satisfied through
internally generated funds.
FINANCING:
GPU has regulatory authority to issue up to four million shares of
additional common stock through 1996. GPU expects to use the proceeds from
any sale of additional common stock to reduce GPU short-term debt and make
capital contributions to the Company and its affiliates, and EI.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), which may be issued as secured medium-term notes, and preferred
stock through December 1997. Under existing authorizations, the Company may
issue such senior securities in the amount of $190 million, of which $100
million may consist of preferred stock. The Company, through its special-
purpose finance subsidiary, has remaining regulatory authority to issue an
additional $25 million of monthly income preferred securities through June
1996. The Company also has regulatory authority to incur short-term debt, a
portion of which may be through the issuance of commercial paper.
In the third quarter of 1995, the Company redeemed, at maturity, $12
million principal amount of FMBs. The Company also issued $28.5 million
principal amount of FMBs as collateral for a like amount of pollution control
revenue refunding bonds issued by the Northampton County Industrial
Development Authority. The proceeds from the sale of the Authority bonds were
used to redeem at maturity a like amount of the Authority's pollution control
bonds issued in 1985.
The Company's bond indenture and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Company may issue. The Company's interest and preferred
dividend coverage ratios are currently in excess of indenture and charter
restrictions.
COMPETITIVE ENVIRONMENT:
In September 1995, the Federal Energy Regulatory Commission (FERC)
accepted for filing, subject to possible refund, the Company's proposed open
access transmission tariffs. The tariffs were submitted to the FERC in March
1995, prior to the FERC's issuance of the Notice of Proposed Rulemaking on
open access non-discriminatory transmission services. The FERC has ordered
that hearings be held on a number of aspects of these tariffs, including
whether they are consistent in certain respects with FERC policy on open
access and comparability of service. The tariffs provide for both firm and
interruptible service on a point-to-point basis. Network service, where
requested, will be negotiated on a case by case basis.
-21-
In April 1994, the PaPUC initiated an investigation into the role of
competition in Pennsylvania's electric utility industry and solicited comments
on various issues. The Company and its affiliate Pennsylvania Electric
Company (Penelec) jointly filed responses in November 1994 suggesting, among
other things, that the PaPUC provide for the equitable recovery of stranded
investments, enable utilities to offer flexible pricing to customers with
competitive alternatives, and address regulatory requirements that impose
costs unequally on Pennsylvania utilities as compared with unregulated or out-
of-state suppliers. In August 1995, the PaPUC released a Staff report in
which the Staff decided not to recommend retail wheeling at this time.
Evidentiary hearings on this matter are scheduled to begin in December 1995.
THE SUPPLY PLAN:
Managing Nonutility Generation
The Company and its affiliates are seeking to reduce the above market
costs of nonutility generation agreements, including (1) attempting to convert
must-run agreements to dispatchable agreements; (2) attempting to renegotiate
prices of the agreements; (3) offering contract buy-outs while seeking to
recover the costs through their energy clauses and (4) initiating proceedings
before federal and state administrative agencies, and in the courts, where
appropriate. In addition, the Company and its affiliates intend to avoid, to
the maximum extent practicable, entering into any new nonutility generation
agreements that are not needed or not consistent with current market pricing,
and are supporting legislative efforts to repeal the Public Utility Regulatory
Policies Act of 1978 (PURPA). These efforts may result in claims against the
Company and its affiliates for substantial damages. There can, however, be no
assurance as to what extent the Company's and its affiliates' efforts will be
successful in whole or in part. The following is a discussion of some major
nonutility generation activities involving the Company.
In May 1995, the Company filed a petition for enforcement and declaratory
order with the FERC requesting that the FERC effectively invalidate two
contracts with nonutility generators, aggregating 327 MW of capacity, on the
grounds that the PaPUC's implementation of PURPA directing the Company to
enter into these agreements was unlawful. Specifically, the Company contended
that the PaPUC's procedures imposing contract prices based on the costs of a
"coal proxy" plant violated PURPA and the FERC's implementing regulations. In
June 1995, the FERC denied the petition, and in September 1995, the FERC
denied the Company's petition for rehearing. The Company has not determined
whether it will seek judicial review of the FERC's order. Subsequent to the
FERC's decision, the Company entered into cancellation agreements, as
described below, with the developers of these two projects.
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 the proposed 100 MW
Scranton facility. In August 1995, the developers agreed to cancel the project
and terminate the power purchase agreement for up to a $30 million payment
from the Company (but not less than $20 million). In September 1995, the
Company filed with the PaPUC for recovery of the costs through energy cost
rates (ECR).
-22-
In 1992, the Company, as required by a PaPUC order, entered into a long-
term power-purchase agreement with the developers of a proposed 227 MW York
County coal-fired cogeneration plant. In September 1995, the Company and the
developer agreed to cancel the proposed project and attempt to restructure the
power-purchase agreement to allow for the development of a natural gas-fired
facility. Under the agreement, the Company will pay the developer up to $30
million to terminate the coal-fired facility, and an additional $5 million if
the agreement cannot be restructured. When the amount to be paid is
finalized, the Company will file a petition with the PaPUC for ECR recovery.
In August 1995, the Company and its affiliates entered into a three-year
fuel management agreement with New Jersey Natural Energy Corporation, an
affiliate of New Jersey Natural Gas Company, to manage the Company's and its
affiliates' natural gas purchases and interstate pipeline capacity. It is
intended that the Company's and its affiliates' gas-fired facilities, as well
as up to approximately 1,100 MW of nonutility generation capacity, will be
pooled and managed under this agreement, allowing the Company and its
affiliates to reduce power purchase expenses.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 335 MW of capacity are currently
in service and an additional 150 MW are currently scheduled or anticipated to
be in service by 1999.
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PART II
ITEM 1 - LEGAL PROCEEDINGS
Information concerning the current status of certain legal
proceedings instituted against the Company and its affiliates as a
result of the March 28, 1979 nuclear accident at Unit 2 of the
Three Mile Island nuclear generating station discussed in Part I
of this report in Notes to Consolidated Financial Statements is
incorporated herein by reference and made a part hereof.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(27) Financial Data Schedule
(b) Reports on Form 8-K:
For the month of October 1995, dated October 4, 1995, under
Item 5 (Other Events)
For the month of October 1995, dated October 20, 1995, under
Item 5 (Other Events), as amended by Form 8-K/A No. 1, dated
October 27, 1995
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this quarterly report to be signed on its behalf by
the undersigned thereunto duly authorized.
METROPOLITAN EDISON COMPANY
November 8, 1995 By: /s/ F. D. Hafer
F. D. Hafer, President
November 8, 1995 By: /s/ D. L. O'Brien
D. L. O'Brien, Comptroller
(Principal Accounting Officer)
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