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 1-3522
Pennsylvania Electric Company
(Exact name of registrant as specified in its charter)
Pennsylvania 25-0718085
(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 October 31, 1995, was as follows:
Common stock, par value $20 per share: 5,290,596 shares outstanding.
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Pennsylvania Electric 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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PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $2 631 135 $2 549 316
Less, accumulated depreciation 963 314 927 498
Net utility plant in service 1 667 821 1 621 818
Construction work in progress 84 216 98 329
Other, net 32 296 27 717
Net utility plant 1 784 333 1 747 864
Other Property and Investments:
Nuclear decommissioning trusts 39 027 29 871
Other, net 4 589 4 596
Total other property and investments 43 616 34 467
Current Assets:
Cash and temporary cash investments 4 629 1 191
Special deposits 2 648 3 242
Accounts receivable:
Customers, net 63 064 68 547
Other 17 144 21 897
Unbilled revenues 24 615 29 181
Materials and supplies, at average cost or less:
Construction and maintenance 54 089 49 342
Fuel 11 556 20 092
Deferred income taxes 2 116 (1 454)
Prepayments 13 179 4 726
Total current assets 193 040 196 764
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 64 617 13 214
Income taxes recoverable through future rates 218 165 227 177
Other 20 034 23 752
Total regulatory assets 302 816 264 143
Deferred income taxes 88 358 114 231
Other 13 102 8 148
Total deferred debits and other assets 404 276 386 522
Total Assets $2 425 265 $2 365 617
The accompanying notes are an integral part of the consolidated financial statements.
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PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 105 812 $ 105 812
Capital surplus 270 486 261 671
Retained earnings 347 457 290 786
Total common stockholder's equity 723 755 658 269
Cumulative preferred stock 36 777 36 777
Company-obligated mandatorily redeemable
preferred securities 105 000 105 000
Long-term debt 676 506 616 490
Total capitalization 1 542 038 1 416 536
Current Liabilities:
Securities due within one year 9 9
Notes payable 49 599 111 052
Obligations under capital leases 23 783 17 957
Accounts payable:
Affiliates 12 989 10 668
Others 61 811 62 642
Taxes accrued 24 866 13 347
Deferred energy credits 42 (10 826)
Interest accrued 11 694 16 356
Vacations accrued 10 238 12 004
Other 12 927 8 700
Total current liabilities 207 958 241 909
Deferred Credits and Other Liabilities:
Deferred income taxes 452 905 454 026
Unamortized investment tax credits 45 728 47 864
Three Mile Island Unit 2 future costs 86 693 85 273
Nuclear fuel disposal fee 13 495 12 918
Regulatory liabilities 34 886 42 878
Other 41 562 64 213
Total deferred credits and other liabilities 675 269 707 172
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 425 265 $2 365 617
The accompanying notes are an integral part of the consolidated financial statements.
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PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
(Unaudited)
<CAPTION>
In Thousands
Three Months Nine Months
Ended September 30, Ended September 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $249 234 $240 267 $741 097 $714 569
Operating Expenses:
Fuel 43 806 46 813 131 093 132 576
Power purchased and interchanged:
Affiliates 973 1 761 5 243 4 859
Others 54 648 34 912 135 690 116 019
Deferral of energy costs, net (3 341) 4 860 10 557 227
Other operation and maintenance 73 717 63 342 192 642 233 114
Depreciation and amortization 22 242 17 573 61 735 55 963
Taxes, other than income taxes 18 582 16 502 50 452 48 873
Total operating expenses 210 627 185 763 587 412 591 631
Operating Income Before Income Taxes 38 607 54 504 153 685 122 938
Income taxes 7 696 16 266 39 446 29 934
Operating Income 30 911 38 238 114 239 93 004
Other Income and Deductions:
Allowance for other funds used during
construction 507 482 1 548 1 333
Other income/(expense), net 58 888 (492) 55 259 (63 626)
Income taxes (24 594) 320 (23 235) 27 764
Total other income and deductions 34 801 310 33 572 (34 529)
Income Before Interest Charges and
Dividends on Preferred Securities 65 712 38 548 147 811 58 475
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 12 378 11 796 36 363 35 187
Other interest 1 647 707 5 608 5 893
Allowance for borrowed funds used
during construction (625) (501) (1 908) (1 445)
Dividends on company-obligated mandatorily
redeemable preferred securities 2 297 2 195 6 891 2 195
Total interest charges and dividends
on preferred securities 15 697 14 197 46 954 41 830
Net Income 50 015 24 351 100 857 16 645
Preferred stock dividends 386 734 1 158 2 551
Earnings Available for Common Stock $ 49 629 $ 23 617 $ 99 699 $ 14 094
The accompanying notes are an integral part of the consolidated financial statements.
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PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(Unaudited)
<CAPTION>
In Thousands
Nine Months
Ended September 30,
1995 1994
<S> <C> <C>
Operating Activities:
Net income $ 100 857 $ 16 645
Adjustments to reconcile net income to
cash provided:
Depreciation and amortization 56 519 51 793
Amortization of property under capital leases 5 695 6 332
Three Mile Island Unit 2 costs (51 796) 56 304
Voluntary enhanced retirement programs - 44 856
Nuclear outage maintenance costs, net (1 407) 2 326
Deferred income taxes and investment tax
credits, net 19 771 (42 919)
Deferred energy costs, net 10 868 357
Accretion income - (200)
Allowance for other funds used during construction (1 548) (1 333)
Changes in working capital:
Receivables 14 802 364
Materials and supplies 3 789 620
Special deposits and prepayments (7 859) (2 517)
Payables and accrued liabilities 1 652 (22 913)
Other, net 3 275 23 284
Net cash provided by operating activities 154 618 132 999
Investing Activities:
Cash construction expenditures (98 089) (129 718)
Contributions to decommissioning trusts (3 947) (4 270)
Other, net - 11
Net cash used for investing activities (102 036) (133 977)
Financing Activities:
Issuance of long-term debt 59 670 129 100
Decrease in notes payable, net (61 453) (86 268)
Capital lease principal payments (6 194) (6 525)
Issuance of company-obligated mandatorily
redeemable preferred securities - 101 304
Contributions from parent corporation 5 000 -
Retirement of long-term debt (9) (78 008)
Redemption of preferred stock - (26 168)
Dividends paid on common stock (45 000) (30 000)
Dividends paid on preferred stock (1 158) (2 726)
Net cash provided/(required) by
financing activities (49 144) 709
Net increase/(decrease) in cash and temporary
cash investments from above activities 3 438 (269)
Cash and temporary cash investments, beginning of year 1 191 1 622
Cash and temporary cash investments, end of period $ 4 629 $ 1 353
Supplemental Disclosure:
Interest paid $ 50 846 $ 46 225
Income taxes paid $ 40 701 $ 45 336
New capital lease obligations incurred $ 10 451 $ 2 320
The accompanying notes are an integral part of the consolidated financial statements.
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PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pennsylvania Electric Company (the Company), a Pennsylvania corporation
incorporated in 1919, 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
Penelec Preferred Capital, Inc., which is the general partner of Penelec
Capital L.P., a special purpose finance subsidiary. The Company also has two
minor wholly-owned subsidiaries. The Company is affiliated with Jersey
Central Power & Light Company (JCP&L) and Metropolitan Edison Company
(Met-Ed). The Company, JCP&L and Met-Ed 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 Met-Ed in the
percentages of 25%, 25% and 50%, 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 $158 $8*
December 31, 1994 $154 $8*
* 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
construction and operation of nuclear facilities. The Company and its
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affiliates may also incur costs and experience reduced output at their nuclear
plants because of the prevailing design criteria at the time of construction
and the age of the plants' systems and equipment. In addition, for economic
or other reasons, operation of these plants for the full term of their now-
assumed lives cannot be assured. Also, not all risks associated with the
ownership or operation of nuclear facilities may be adequately insured or
insurable. Consequently, the ability of electric utilities to obtain adequate
and timely recovery of costs associated with nuclear projects, including
replacement power, any unamortized investment at the end of each plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and after receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the United
States District Court for the Middle District of Pennsylvania. Some of the
claims also seek recovery for injuries from alleged emissions of radioactivity
before and after the accident.
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 $2.5 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 the Company and its affiliates believe that any liability to
which they might be subject by reason of the TMI-2 accident and these Court of
Appeals decisions will not exceed the financial protection under the Price-
Anderson Act. GPU and the Company and its affiliates have filed a petition
with the Third Circuit Court seeking a rehearing and en banc reconsideration
of its decision that punitive damages are recoverable under the Price-Anderson
Act.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in
compliance with NRC regulations, setting forth a funding plan (employing the
external sinking fund method) for the decommissioning of their nuclear
reactors. Under this plan, the Company and its affiliates intend to complete
the funding for 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 $39 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 $56 million to $77 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 $19
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 approved a
rate change for the Company that increased the collection of revenues for
decommissioning costs for TMI-1 based on its share of the NRC funding target
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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 expenditure of these funds has been
made in accumulated depreciation, amounting to $13 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 $.7 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 $64 $62
Nonradiological Cost of Removal 18 18
Incremental Monitored Storage 5 5
Total $87 $85
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the Balance Sheet. At September 30, 1995, $22 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet,
and $56 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 Met-Ed 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.
The Company, which is also subject to PaPUC regulation, recorded pre-tax
charges of $56.3 million during 1994, for its share of such costs applicable
to its retail customers. These charges appear in the Other Income and
Deductions section of the 1994 Consolidated Statement of Income and are
composed of $38.4 million for radiological decommissioning costs,
$13.2 million for the nonradiological cost of removal and $4.7 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-offs, resulting in pre-tax income of
$56.3 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
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pre-tax charge to operating income of $4.7 million in the third quarter of
1995.
In 1991, the Company contributed $20 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
$.25 million. The Company and its affiliates estimate that the remaining
annual storage costs will total $19 million, of which the Company's share is
$5 million, through 2014, the expected retirement date of TMI-1.
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 $9 million, in any one year under insurance policies
applicable to nuclear operations and facilities.
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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
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 25 years. The majority of these
agreements contain certain contract limitations and subject the nonutility
generators to penalties for nonperformance. All of these facilities 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 397 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 $152 million, $176
million, $184 million, $197 million, and $278 million, respectively. These
agreements, in the aggregate, will provide approximately 575 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 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.
-13-
<PAGE>
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 $90 million to $120 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.
-14-
<PAGE>
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 $ 218,165 $ 34,221
TMI-2 deferred costs 64,617 -
Unamortized property losses 1,901 -
Unamortized loss on reacquired debt 9,310 -
DOE enrichment facility decommissioning 5,033 -
Nuclear fuel disposal fee (24) -
Other 3,814 665
Total $ 302,816 $ 34,886
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.
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.
-15-
<PAGE>
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 $177 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 $50 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.
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 2 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
-16-
<PAGE>
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 $124 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. One contract also includes a
provision for the payment of environmental and postretirement benefit costs.
The Company's share of the cost of coal purchased under these agreements is
expected to aggregate $44 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 defendants in litigation in which
compensatory and punitive damages are sought by the public, customers,
contractors, vendors and other suppliers of equipment and services and by
employees alleging unlawful employment practices. While management does not
expect that the outcome of these matters will have a material effect on the
Company's financial position or results of operations, there can be no
assurance that this will continue to be the case.
-17-
<PAGE>
Pennsylvania Electric 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 quarter ended September 30, 1995 were $49.6 million,
compared to $23.6 million for the same quarter ended last year. The increase
in quarterly earnings was due to the reversal of $32.1 million (after-tax) of
certain future Three Mile Island Unit 2 (TMI-2) retirement costs written-off
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 disallowing the recovery of certain future TMI-2
retirement costs from customers. In addition, there was a charge to income of
$2.7 million (after-tax) for TMI-2 monitored storage costs the Company
believes will not be recoverable through ratemaking.
Earnings for the nine months ended September 30, 1995 were $99.7 million,
compared to $14.1 million for the same period ended last year. The same
factors mentioned above contributed to the earnings increase 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
$61.8 million (after-tax). The 1994 one-time items included a write-off of
$32.1 million of certain future TMI-2 retirement costs, $25.6 million for
early retirement program costs, the write-off of $10.6 million of
postretirement benefit costs; and net interest income of $6.5 million
resulting from refunds of previously paid federal income taxes related to the
tax retirement of TMI-2.
Also contributing to the earnings increase for the quarter and nine month
periods was higher sales resulting from new customer growth in the residential
and commercial sectors. Hotter summer temperatures also contributed to the
third quarter earnings increase; however, this increase was more than offset
in the nine month period by milder winter weather in 1995 compared to the
previous year.
OPERATING REVENUES:
Total revenues for the third quarter of 1995 increased 3.7% to $249.2
million, as compared to the third quarter of 1994. Total revenues for the
nine months ended September 30, 1995 increased 3.7% to $741.1 million, as
compared with the same period in 1994. The components of these changes are as
follows:
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<PAGE>
(In Millions)
Three Months Nine Months
Ended Ended
September 30, 1995 September 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ 3.8 $ (2.3)
Energy revenues 8.4 26.3
Other revenues (3.3) 2.5
Increase in revenues $ 8.9 $ 26.5
Kilowatt-hour Revenues
The increase in KWH revenues for the three month period was due primarily
to higher residential sales from hotter summer temperatures compared to last
year. The decrease in KWH revenues for the nine month period was due to lower
residential sales from milder winter temperatures in 1995 compared to the
previous winter.
Energy Revenues
Changes in energy revenues do not normally affect net income as they
reflect corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased for both the three and nine month periods
primarily as a result of increased sales to other utilities. Higher energy
cost rates, partially offset by lower sales to customers also contributed to
the nine month increase.
Other Revenues
Generally, changes in other revenues do not affect earnings as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Company's energy clause.
However, earnings for the nine month period were negatively affected by higher
reserve capacity expense resulting primarily from higher payments to the
Pennsylvania-New Jersey-Maryland Interconnection.
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 (O&M)
The increase in other O&M for the three month period was due primarily to
the write-off of $4.7 million (pre-tax) of future TMI-2 monitored storage
costs deemed not recoverable through ratemaking and higher credit and
collection activity.
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<PAGE>
The decrease in other O&M expense for the nine month period was primarily
attributable to a one-time $44.9 million (pre-tax) charge in 1994 related to
early retirement programs. Also contributing to the nine month O&M reduction
were lower winter storm repair costs and payroll and benefit savings resulting
from the retirement programs.
Depreciation and amortization
The increases 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 $56.3 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 Metropolitan Edison Company (an
affiliate of the Company) to recover certain future TMI-2 retirement costs
from customers. In addition, $2.6 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 $56.3 million (pre-tax) for certain future TMI-2 retirement costs
resulting from a Pennsylvania Commonwealth Court order, and $18.6 million
(pre-tax) for postretirement benefit costs not believed to be recoverable in
rates. These increases were partially offset by lower interest income of
$14.9 million (pre-tax) resulting from 1994 refunds of previously paid federal
income taxes related to the tax retirement of TMI-2. The tax retirement of
TMI-2 resulted in a refund for the tax years after TMI-2 was retired.
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES:
Other interest
Other interest expense for the nine month period decreased due to the
recognition in the first quarter of 1994 of interest expense related to the
tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $3.5
million (pre-tax) charge to interest expense on additional amounts owed for
tax years in which depreciation deductions with respect to TMI-2 had been
taken.
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<PAGE>
Dividends on company-obligated mandatorily redeemable preferred securities
In the third quarter of 1994, the Company issued $105 million of monthly
income preferred securities through a special-purpose finance subsidiary.
Dividends on these securities are payable monthly.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs for the nine months ended September 30, 1995
consisted of cash construction expenditures of $98 million. Construction
expenditures for the year are forecasted to be $124 million. The Company has
no long-term securities maturing in 1995. Management estimates that
approximately three-fourths of the capital needs in 1995 will be satisfied
through internally generated funds.
FINANCING:
GPU has regulatory authority to issue up to four million shares of
additional common stock through 1996. GPU expects to use the proceeds from
any sale of additional common stock to reduce GPU short-term debt and make
capital contributions to the Company and its affiliates, and EI.
The Company has regulatory authority to issue and sell first mortgage
bonds (FMBs), which may be issued as secured medium-term notes, and preferred
stock through June 1997. Under existing authorizations, the Company may issue
such senior securities in the amount of $160 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
$20 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 October 1995, the Company issued $70 million principal amount of FMBs,
the proceeds of which will be used to redeem, prior to maturity, $30 million
principal amount of FMBs and reduce outstanding short-term debt.
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
-21-
<PAGE>
and interruptible service on a point-to-point basis. Network service, where
requested, will be negotiated on a case by case basis.
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 Metropolitan Edison Company
(Met-Ed) 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 160 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.
In November 1994, the Company requested the Pennsylvania Supreme Court to
review a Commonwealth Court decision upholding a PaPUC order requiring the
Company to purchase a total of 160 MW from two nonutility generators. The
PaPUC had ordered the Company in 1993 to enter into power purchase agreements
with the nonutility generators for 80 MW of power each under long-term
contracts commencing in 1997 or later. In August 1994, the Commonwealth Court
denied the Company's appeal of the PaPUC order. The Company's petition to the
Supreme Court contends that the Commonwealth Court imposed unnecessary and
excessive costs on the Company's customers by finding that the Company had a
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<PAGE>
need for capacity. The petition also questions the Commonwealth Court's
upholding of the PaPUC's determination that the nonutility generators had
incurred a legal obligation entitling them to payments under PURPA. In May
1995, the PaPUC assigned the matter to an ALJ for a recommended decision. In
August 1995, however, the Pennsylvania Supreme Court granted the Company's
petition for review of the Commonwealth Court's decision. The Commonwealth
Court has remanded pricing issues to the PaPUC, which has now assigned the
matter to an ALJ for hearings.
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 397 MW of capacity are currently
in service and an additional 178 MW are currently scheduled or anticipated to
be in service by 1999.
-23-
<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
(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
-24-
<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.
PENNSYLVANIA ELECTRIC 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)
-25-<PAGE>
<TABLE>
Exhibit 12
Page 1 of 2
PENNSYLVANIA ELECTRIC 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
<CAPTION>
Nine Months Ended
September, 30 September, 30
1995 1994
<S> <C> <C>
OPERATING REVENUES $741 097 $714 569
OPERATING EXPENSES 587 412 591 631
Interest portion of rentals (A) 1 785 2 747
Net expense 585 627 588 884
OTHER INCOME AND DEDUCTIONS:
Allowance for funds used
during construction 3 456 2 778
Other income/(deductions), net 55 259 (63 626)
Total other income and deductions 58 715 (60 848)
EARNINGS AVAILABLE FOR FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS (excluding
taxes based on income) $214 185 $ 64 837
FIXED CHARGES:
Interest on funded indebtedness $ 36 363 $ 35 187
Other interest (B) 12 499 8 088
Interest portion of rentals (A) 1 785 2 747
Total fixed charges $ 50 647 $ 46 022
RATIO OF EARNINGS TO FIXED CHARGES 4.23 1.41
Preferred stock dividend requirement 1 158 2 551
Ratio of income (loss) before provision for
income taxes to net income (loss) (C) 162.1% 113.0%
Preferred stock dividend requirement
on a pre-tax basis 1 877 2 884
Fixed charges, as above 50 647 46 022
Total fixed charges and
preferred stock dividends $ 52 524 $ 48 906
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS 4.08 1.33
</TABLE>
<PAGE>
Exhibit 12
Page 2 of 2
PENNSYLVANIA ELECTRIC 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
NOTES:
(A) The Company has included the equivalent of the interest portion
of all rentals charged to income as fixed charges for this statement
and has excluded such components from Operating Expenses.
(B) Includes dividends on company-obligated mandatorily redeemable preferred
securities of $6,891.
(C) Represents income before provision for income taxes of $163,538 and
$18,815, for the nine months ended September 30, 1995 and
September 30, 1994, respectively, divided by net income of $100,857
and $16,645, respectively.
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000077227
<NAME> PENNSYLVANIA ELECTRIC COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> SEP-30-1995
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,784,333
<OTHER-PROPERTY-AND-INVEST> 43,616
<TOTAL-CURRENT-ASSETS> 193,040
<TOTAL-DEFERRED-CHARGES> 404,276
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,425,265
<COMMON> 105,812
<CAPITAL-SURPLUS-PAID-IN> 270,486
<RETAINED-EARNINGS> 347,457
<TOTAL-COMMON-STOCKHOLDERS-EQ> 723,755
105,000 <F1>
36,777
<LONG-TERM-DEBT-NET> 676,506
<SHORT-TERM-NOTES> 42,200
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 7,399
<LONG-TERM-DEBT-CURRENT-PORT> 9
0
<CAPITAL-LEASE-OBLIGATIONS> 5,619
<LEASES-CURRENT> 23,783
<OTHER-ITEMS-CAPITAL-AND-LIAB> 804,217
<TOT-CAPITALIZATION-AND-LIAB> 2,425,265
<GROSS-OPERATING-REVENUE> 741,097
<INCOME-TAX-EXPENSE> 39,446
<OTHER-OPERATING-EXPENSES> 587,412
<TOTAL-OPERATING-EXPENSES> 626,858
<OPERATING-INCOME-LOSS> 114,239
<OTHER-INCOME-NET> 33,572
<INCOME-BEFORE-INTEREST-EXPEN> 147,811
<TOTAL-INTEREST-EXPENSE> 46,954 <F2>
<NET-INCOME> 100,857
1,158
<EARNINGS-AVAILABLE-FOR-COMM> 99,699
<COMMON-STOCK-DIVIDENDS> 45,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 47,615
<CASH-FLOW-OPERATIONS> 154,618
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1> REPRESENTS COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
<F1> SECURITIES.
<F2> INCLUDES DIVIDENDS ON COMPANY-OBLIGATED MANDATORILY REDEEMABLE
<F2> PREFERRED SECURITIES OF $6,891.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<PAGE>
</TABLE>
