UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1995
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-3522
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 July 31, 1995, was as follows:
Common stock, par value $20 per share: 5,290,596 shares outstanding.
<PAGE>
Pennsylvania Electric Company
Quarterly Report on Form 10-Q
June 30, 1995
Table of Contents
Page
PART I - Financial Information
Financial Statements:
Balance Sheets 3
Statements of Income 5
Statements of Cash Flows 6
Notes to Financial Statements 7
Management's Discussion and Analysis of
Financial Condition and Results of
Operations 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
<TABLE>
<CAPTION>
In Thousands
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $2 600 467 $2 549 316
Less, accumulated depreciation 949 566 927 498
Net utility plant in service 1 650 901 1 621 818
Construction work in progress 88 783 98 329
Other, net 30 977 27 717
Net utility plant 1 770 661 1 747 864
Other Property and Investments:
Nuclear decommissioning trusts 36 311 29 871
Other, net 4 590 4 596
Total other property and investments 40 901 34 467
Current Assets:
Cash and temporary cash investments 1 248 1 191
Special deposits 2 610 3 242
Accounts receivable:
Customers, net 67 484 68 547
Other 31 354 21 897
Unbilled revenues 23 792 29 181
Materials and supplies, at average cost or less:
Construction and maintenance 55 243 49 342
Fuel 15 469 20 092
Deferred income taxes 3 255 (1 454)
Prepayments 24 526 4 726
Total current assets 224 981 196 764
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 13 040 13 214
Income taxes recoverable through future rates 221 210 227 177
Other 20 632 23 752
Total regulatory assets 254 882 264 143
Deferred income taxes 113 499 114 231
Other 15 387 8 148
Total deferred debits and other assets 383 768 386 522
Total Assets $2 420 311 $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
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 105 812 $ 105 812
Capital surplus 270 487 261 671
Retained earnings 312 398 290 786
Total common stockholder's equity 688 697 658 269
Cumulative preferred stock 36 777 36 777
Company-obligated mandatorily redeemable
preferred securities 105 000 105 000
Long-term debt 676 507 616 490
Total capitalization 1 506 981 1 416 536
Current Liabilities:
Securities due within one year 9 9
Notes payable 56 395 111 052
Obligations under capital leases 22 005 17 957
Accounts payable:
Affiliates 9 776 10 668
Others 58 524 62 642
Taxes accrued 16 707 13 347
Deferred energy credits 3 295 (10 826)
Interest accrued 18 303 16 356
Vacations accrued 11 407 12 004
Other 10 885 8 700
Total current liabilities 207 306 241 909
Deferred Credits and Other Liabilities:
Deferred income taxes 453 361 454 026
Unamortized investment tax credits 46 440 47 864
Three Mile Island Unit 2 future costs 86 836 85 273
Nuclear fuel disposal fee 13 305 12 918
Regulatory liabilities 38 766 42 878
Other 67 316 64 213
Total deferred credits and other liabilities 706 024 707 172
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $2 420 311 $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 Six Months
Ended June 30, Ended June 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $238 451 $227 122 $491 863 $474 302
Operating Expenses:
Fuel 40 818 39 745 87 287 85 763
Power purchased and interchanged:
Affiliates 2 643 2 289 4 270 3 098
Others 41 904 36 796 81 042 81 107
Deferral of energy costs, net 3 074 2 959 13 898 (4 633)
Other operation and maintenance 64 779 107 953 118 925 169 772
Depreciation and amortization 20 303 17 870 39 493 38 390
Taxes, other than income taxes 15 462 15 529 31 870 32 371
Total operating expenses 188 983 223 141 376 785 405 868
Operating Income Before Income Taxes 49 468 3 981 115 078 68 434
Income taxes 12 250 (4 768) 31 750 13 668
Operating Income 37 218 8 749 83 328 54 766
Other Income and Deductions:
Allowance for other funds used during
construction 519 436 1 041 851
Other income/(expense), net (2 406) (75 464) (3 629) (63 134)
Income taxes 989 32 650 1 359 27 444
Total other income and deductions (898) (42,378) (1 229) (34 839)
Income/(Loss) Before Interest Charges and
Dividends on Preferred Securities 36 320 (33 629) 82 099 19 927
Interest Charges and Dividends on
Preferred Securities:
Interest on long-term debt 12 383 11 681 23 985 23 391
Other interest 2 004 1 844 3 961 5 186
Allowance for borrowed funds used
during construction (640) (483) (1 283) (944)
Dividends on company-obligated mandatorily
redeemable preferred securities 2 297 - 4 594 -
Total interest charges and dividends
on preferred securities 16 044 13 042 31 257 27 633
Net Income/(Loss) 20 276 (46 671) 50 842 (7 706)
Preferred stock dividends 386 909 772 1 817
Earnings/(Loss) Available for Common Stock $ 19 890 $(47 580) $ 50 070 $ (9 523)
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
Six Months
Ended June 30,
1995 1994
<S> <C> <C>
Operating Activities:
Net income/(loss) $ 50 842 $ (7 706)
Adjustments to reconcile income/(loss) to
cash provided:
Depreciation and amortization 37 529 34 172
Amortization of property under capital leases 4 296 4 095
Three Mile Island Unit 2 costs - 56 304
Voluntary enhanced retirement programs - 44 856
Nuclear outage maintenance costs, net 1 309 1 539
Deferred income taxes and investment tax
credits, net (4 412) (42 831)
Deferred energy costs, net 14,121 (4 539)
Accretion income - (200)
Allowance for other funds used during construction (1 041) (852)
Changes in working capital:
Receivables (3 005) (11 649)
Materials and supplies (1 278) (1 311)
Special deposits and prepayments (19 168) (14 441)
Payables and accrued liabilities 13 039 3 359
Other, net 2 285 20 302
Net cash provided by operating activities 94 517 81 098
Investing Activities:
Cash construction expenditures (66 956) (90 202)
Contributions to decommissioning trusts (2 632) (2 954)
Net cash used for investing activities (69 588) (93 156)
Financing Activities:
Issuance of long-term debt 59 670 129 100
Decrease in notes payable, net (54 657) (13 739)
Capital lease principal payments (4 113) (3 873)
Contributions from parent corporation 5 000 -
Retirement of long-term debt - (78 000)
Dividends paid on common stock (30 000) (20 000)
Dividends paid on preferred stock (772) (1 817)
Net cash provided/(required) by
financing activities (24 872) 11 671
Net increase/(decrease) in cash and temporary
cash investments from above activities 57 (387)
Cash and temporary cash investments, beginning of year 1 191 1 622
Cash and temporary cash investments, end of period $ 1 248 $ 1 235
Supplemental Disclosure:
Interest paid $ 28 765 $ 27 080
Income taxes paid $ 27 489 $ 20 293
New capital lease obligations incurred $ 7 631 $ 2 245
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
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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 Subsidiaries; and Energy
Initiatives, Inc. (EI) and EI Power, Inc., which develop, own and operate
nonutility generating facilities. All of the Company's affiliates are wholly
owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, EI
and EI Power, Inc. are referred to as the "GPU System".
These notes should be read in conjunction with the notes to consolidated
financial statements included in the 1994 Annual Report on Form 10-K. The
year-end condensed balance sheet data contained in the attached financial
statements were derived from audited financial statements. For disclosures
required by generally accepted accounting principles, see the 1994 Annual
Report on Form 10-K.
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in two major nuclear projects--Three
Mile Island Unit 1 (TMI-1) which is an operational generating facility, and
Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident.
TMI-1 and TMI-2 are jointly owned by the Company, JCP&L, and Met-Ed in the
percentages of 25%, 25% and 50%, respectively. At June 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
June 30, 1995 $156 $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
affiliates may also incur costs and experience reduced output at their nuclear
plants because of the prevailing design criteria at the time of construction
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and the age of the plants' systems and equipment. In addition, for economic
or other reasons, operation of these plants for the full term of their now-
assumed lives cannot be assured. Also, not all risks associated with the
ownership or operation of nuclear facilities may be adequately insured or
insurable. Consequently, the ability of electric utilities to obtain adequate
and timely recovery of costs associated with nuclear projects, including
replacement power, any unamortized investment at the end of each plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT
COSTS). Management intends, in general, to seek recovery of such costs
through the ratemaking process, but recognizes that recovery is not assured
(see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and, after receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against GPU and the Company and its
affiliates. Approximately 2,100 of such claims are pending in the United
States District Court for the Middle District of Pennsylvania. Some of the
claims also seek recovery for injuries from alleged emissions of radioactivity
before and after the accident. If, notwithstanding the developments noted
below, punitive damages are not covered by insurance and are not subject to
the liability limitations of the federal Price-Anderson Act ($560 million at
the time of the accident), punitive damage awards could have a material
adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson
Act, the Company and its affiliates had (a) primary financial protection in
the form of insurance policies with groups of insurance companies providing an
aggregate of $140 million of primary coverage, (b) secondary financial
protection in the form of private liability insurance under an industry
retrospective rating plan providing for premium charges deferred in whole or
in major part under such plan, and (c) an indemnity agreement with the NRC,
bringing their total primary and secondary insurance financial protection and
indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2
accident-related claims against GPU and the Company and its affiliates and
their suppliers under a reservation of rights with respect to any award of
punitive damages. However, in March 1994, the defendants in the TMI-2
litigation and the insurers agreed that the insurers would withdraw their
reservation of rights with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is scheduled to begin in June 1996. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
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seeking a dismissal of all cases on the grounds that the defendants complied
with applicable federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment. In July 1994, the Court
granted defendants' motions for interlocutory appeal of these orders, stating
that they raise questions of law that contain substantial grounds for
differences of opinion. The issues are now before the United States Court of
Appeals for the Third Circuit.
In an order issued in April 1994, the Court: (1) noted that the
plaintiffs have agreed to seek punitive damages only against GPU and the
Company and its affiliates; and (2) stated in part that the Court is of the
opinion that any punitive damages owed must be paid out of and limited to the
amount of primary and secondary insurance under the Price-Anderson Act and,
accordingly, evidence of the defendants' net worth is not relevant in the
pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in
compliance with NRC regulations, setting forth a funding plan (employing the
external sinking fund method) for the decommissioning of their nuclear
reactors. Under this plan, the Company and its affiliates intend to complete
the funding for TMI-1 by 2014, the end of the plant's license term. The TMI-2
funding completion date is 2014, consistent with TMI-2's remaining in long-
term storage and being decommissioned at the same time as TMI-1. Under the
NRC regulations, the funding target (in 1994 dollars) for TMI-1 is
$157 million, of which the Company's share is $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
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 to $309 million, of which the Company's share would range
from $56 to $77 million (in 1994 dollars). In addition, the study estimated
the cost of removal of nonradiological structures and materials for TMI-1 at
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$74 million, of which the Company's share is $19 million (in 1994 dollars).
To date, no site-specific study has been performed for TMI-2.
The ultimate cost of retiring the Company and its affiliates' nuclear
facilities may be materially different from the funding targets and the cost
estimates contained in the site-specific studies. Such costs are subject to
(a) the type of decommissioning plan selected, (b) the escalation of various
cost elements (including, but not limited to, general inflation), (c) the
further development of regulatory requirements governing decommissioning,
(d) the absence to date of significant experience in decommissioning such
facilities and (e) the technology available at the time of decommissioning.
The Company and its affiliates charge to expense and contribute to external
trusts amounts collected from customers for nuclear plant decommissioning and
nonradiological costs. In addition, the Company has contributed amounts
written off for TMI-2 nuclear plant decommissioning in 1991 to TMI-2's
external trust and will await resolution of the case pending before the
Pennsylvania Supreme Court before making any further contributions for amounts
written off by the company in 1994 (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.
The Financial Accounting Standards Board (FASB) is currently reviewing
the utility industry's accounting practices for nuclear decommissioning costs.
If the FASB's tentative conclusions are adopted, TMI-1 retirement costs may
have to be recorded as a liability, rather than as accumulated depreciation,
with an offsetting asset recorded for amounts collectible through rates. Any
amounts that cannot be collected through rates may have to be charged to
expense. The FASB is expected to release an Exposure Draft on decommissioning
accounting practices by the fourth quarter of 1995.
TMI-1:
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.
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 $11 million at June 30, 1995.
TMI-1 retirement costs are charged to depreciation expense over the expected
service life of the nuclear plant.
Management believes that any TMI-1 retirement costs, in excess of those
currently recognized for ratemaking purposes, should be recoverable under the
current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the
radiological decommissioning of TMI-2, reflecting the NRC funding target (in
1995 dollars). The Company and its affiliates record escalations, when
applicable, in the liability based upon changes in the NRC funding target.
The Company and its affiliates have also recorded a liability for incremental
costs specifically attributable to monitored storage. In addition, the
Company and its affiliates have recorded a liability for the nonradiological
cost of removal consistent with the TMI-1 site-specific study and have spent
$3 million as of June 30, 1995, of which the Company's share is $.7 million.
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Estimated TMI-2 Future Costs as of June 30, 1995 and December 31, 1994 for the
Company are as follows:
June 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 June 30, 1995, $22 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and
$5 million was recoverable from customers and included in Three Mile Unit 2
Deferred Costs on the balance sheet.
In 1993, a PaPUC rate order for Met-Ed allowed for the future recovery
of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer
Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate
order and in 1994, the Commonwealth Court reversed the PaPUC order. In
December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to
review that decision. Oral argument was held on April 27, 1995, and the
matter is pending. 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 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. The Company will await resolution of the
appeal pending before the Pennsylvania Supreme Court before making any
nonrecoverable funding contributions to external trusts for its share of these
costs. The Company is similarly required to charge to expense its share of
future increases in the estimate of the costs of retiring TMI-2 if the
Pennsylvania Supreme Court does not reverse the Commonwealth Court's decision.
Earnings on trust fund deposits are recorded as income. Prior to the
Commonwealth Court's decision, the Company contributed $20 million to external
trusts relating to its share of the accident-related portion of the
decommissioning liability. This contribution was not recovered from customers
and has been expensed.
As a result of TMI-2's entering long-term monitored storage in late
1993, the Company and its affiliates are incurring incremental annual storage
costs of approximately $1 million, of which the Company's share is
$.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
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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 (TMI-2 being excluded
under an exemption received from the NRC in 1994), subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, the GPU System is also
subject to retrospective premium assessments of up to $69 million, of which
the Company's share is $9 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
continues for three years beginning at $2.6 million per week for the first
year, decreasing by 20 percent for years two and three.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
Nonutility Generation Agreements:
Pursuant to the requirements of the federal Public Utility Regulatory
Policies Act (PURPA) and state regulatory directives, the Company has entered
into power purchase agreements with nonutility generators for the purchase of
energy and capacity for periods up to 25 years. The majority of these
agreements contain certain contract limitations and subject the nonutility
generators to penalties for nonperformance. While a few of these facilities
are dispatchable, most are must-run and generally obligate the Company to
purchase, at the contract price, the net output up to the contract limits. As
of June 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 all facilities which have existing agreements, or
which have obtained orders granting them agreements enter service, are
$185 million, $192 million, $213 million, $305 million and $314 million,
respectively. These agreements, in the aggregate, will provide approximately
575 MW of capacity and energy to the Company, at varying prices.
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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. In
addition, the Company and its affiliates intend to avoid, to the maximum
extent practicable, entering into any new nonutility generation agreements
that are not needed or not consistent with current market pricing and are
supporting legislative efforts to repeal PURPA. These efforts may result in
claims against the GPU System for substantial damages. There can, however, be
no assurance as to what extent the Company's and its affiliates' efforts will
be successful in whole or in part.
While the Company and its affiliates thus far have been granted recovery
of their nonutility generation costs from customers by the PaPUC and New
Jersey Board of Public Utilities (NJBPU), there can be no assurance that the
Company and its affiliates will continue to be able to recover these costs
throughout the term of the related agreements. The GPU System currently
estimates that in 1998, when substantially all of these nonutility generation
projects are scheduled to be in service, above market payments (benchmarked
against the expected cost of electricity produced by a new gas-fired combined
cycle facility) will range from $300 million to $450 million annually, of
which the Company's share will range from $90 million to $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;
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<PAGE>
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.
In accordance with the provisions of FAS 71, the Company has deferred
certain costs pursuant to actions of the PaPUC and the Federal Energy
Regulatory Commission (FERC) and is recovering or expects to recover such
costs in electric rates charged to customers. Regulatory assets are reflected
in the Deferred Debits and Other Assets section of the Consolidated Balance
Sheet, and regulatory liabilities are reflected in the Deferred Credits and
Other Liabilities section of the Consolidated Balance Sheet. Regulatory
assets and liabilities, as reflected in the June 30, 1995 Consolidated Balance
Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 221,210 $ 36,590
TMI-2 deferred costs 13,040 -
TMI-2 tax refund - 1,363
Unamortized property losses 1,853 -
Unamortized loss on reacquired debt 9,651 -
DOE enrichment facility decommissioning 5,386 -
Other 3,742 813
Total $ 254,882 $ 38,766
Income taxes recoverable/refundable through future rates: Represents amounts
deferred due to the implementation of FAS 109, "Accounting for Income Taxes,"
in 1993.
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<PAGE>
TMI-2 deferred costs: Represents costs that are being recovered through
wholesale rates for the remaining investment in the plant and fuel core, in
addition to amounts for the Company's share of the NRC's radiological
decommissioning funding target, allowances for the cost of removal of
nonradiological structures and materials, and long term monitored storage
costs. For additional information, see TMI-2 Future Costs.
TMI-2 tax refund: Represents the tax refund related to the tax abandonment of
TMI-2. This balance is being amortized by the Company concurrent with its
return to customers through a base rate credit.
Unamortized property losses: The NRC has mandated that the design of nuclear
reactors be documented. As a result, the Company's share of the costs
incurred in documenting TMI-1 plant design, in addition to costs incurred in a
study used to assess the vulnerability of nuclear reactors to severe
accidents, are recorded in this account. The study costs are amortized over
the life of the plant.
Unamortized loss on reacquired debt: Represents premiums and expenses incurred
in the redemption of long-term debt. In accordance with FERC regulations,
reacquired debt costs are amortized over the remaining original life of the
retired debt.
DOE enrichment facility decommissioning: These costs, representing payments
to the DOE over a 15-year period beginning in 1994, are currently being
collected through the Company's energy adjustment clause.
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
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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 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 requires additional NOx
reductions to meet the Clean Air Act's 2005 National Ambient Air Quality
Standards for ozone. However, the specific requirements that will have to be
met at that time have not been finalized. The Company and its affiliates are
unable to determine what 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
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 $144 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 benefits. The
Company's share of the cost of coal purchased under these agreements is
expected to aggregate $45 million for 1995.
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During the normal course of the operation of its businesses, in addition
to the matters described above, the Company is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by customers, contractors,
vendors and other suppliers of equipment and services and by employees
alleging unlawful employment practices. It is not expected that the outcome
of these types of matters would have a material effect on the Company's
financial position or results of operations.
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<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 available for common stock for the second quarter ended June 30,
1995 were $19.9 million compared to a net loss of $47.6 million for the second
quarter of 1994. Earnings for the three months ended June 30, 1995, as
compared to 1994, were higher primarily as a result of a write-off of
$32.1 million after-tax from an unfavorable Pennsylvania Commonwealth Court
order disallowing the collection of revenues for certain Three Mile Island
Unit 2 (TMI-2) retirement costs, a $25.6 million after-tax charge to earnings
for costs related to voluntary enhanced retirement programs, and a
$10.6 million after-tax write-off of postretirement benefit costs not
considered likely to be recovered through ratemaking, all in the second
quarter of 1994.
For the six months ended June 30, 1995, the Company experienced net
income of $50.1 million compared with a net loss of $9.5 million for the
comparable period in 1994. The same factors affecting the quarterly results
also affected results for the six month period. In addition, the six month
earnings comparison was negatively affected by lower sales because of the
milder winter weather compared to 1994 and higher reserve capacity expense.
Also affecting the six months earnings comparison was nonrecurring interest
income (net of nonrecurring interest expense) in 1994 of $6.5 million after-
tax resulting from refunds of previously paid federal income taxes related to
the tax retirement of TMI-2.
OPERATING REVENUES:
Total revenues for the second quarter of 1995 increased 5.0% to
$238.5 million as compared to the second quarter of 1994. Total revenues for
the six months ended June 30, 1995 increased 3.7% to $491.9 million compared
with the same period in 1994. The components of these changes are as follows:
(In Millions)
Three Months Six Months
Ended Ended
June 30, 1995 June 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ (0.8) $ (6.1)
Energy revenues 6.0 17.9
Other revenues 6.2 5.8
Increase in revenues $ 11.4 $ 17.6
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<PAGE>
Kilowatt-hour Revenues
KWH revenues decreased in the six month period ending June 30, 1995 due
primarily to lower residential sales resulting from warmer winter temperatures
this year compared to last year.
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 six month periods
ended June 30, 1995 primarily as a result of increased sales to other
utilities and higher energy cost rates, partially offset by lower sales to
customers.
Other Revenues
Generally, changes in other revenues do not affect earnings as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Company's energy clause.
However, earnings for the six months ended June 30, 1995 were negatively
impacted 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
The decrease in other O&M expense for the three and six months ended June
30, 1995 was primarily a result of a $44.9 million pre-tax charge for costs
related to the voluntary enhanced retirement programs in the second quarter of
1994. Other O&M expense for the six month period also decreased as a result
of lower winter storm repair costs and payroll and benefit savings resulting
from the 1994 workforce reduction. These decreases in other O&M were
partially offset by higher other post employment benefit expenses.
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.
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<PAGE>
OTHER INCOME AND DEDUCTIONS:
Other income/(expense), net
The increase in other income for both the three and six months ended June
30, 1995 were primarily attributable to write-offs in 1994 consisting of
$56.3 million pre-tax for certain TMI-2 retirement costs resulting from a
Pennsylvania court order, and $18.6 million pre-tax for other post employment
benefit costs not considered likely to be recovered in rates. The six month
increase was partially offset by lower first quarter 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 six months ended June 30, 1995 decreased
due primarily to the recognition in the first quarter of 1994 of interest
expense related to the tax retirement of TMI-2. The tax retirement of TMI-2
resulted in a $3.5 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.
Dividends on company-obligated mandatorily redeemable preferred securities
In 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 six months ended June 30, 1995
consisted of cash construction expenditures of $67 million. Construction
expenditures for the year are forecasted to be $144 million. The Company has
no long-term debt maturing in 1995. Management estimates that approximately
three-fourths of the capital needs in 1995 will be satisfied through
internally generated funds.
FINANCING:
During the second quarter of 1995, GPU sold one million shares of common
stock through an underwritten public offering. The net proceeds of
$29.6 million were used to make cash capital contributions to the Company and
its affiliates, of which the Company's share was $5.0 million.
The Company has regulatory authority to issue and sell first mortgage
bonds, which may be issued as secured medium-term notes, and preferred stock
through June 1997. Under existing authorizations, the Company may issue
senior securities in the amount of $230 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. The Company also has
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<PAGE>
regulatory authority to incur short-term debt, a portion of which may be
through the issuance of commercial paper.
The Company's bond indentures and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Company may issue. The Company's interest and preferred
dividend coverage ratios are currently in excess of indenture and charter
restrictions. The ability to issue securities in the future will depend on
coverages at that time. The ability of the Company to issue, through its
special-purpose subsidiary, monthly income preferred securities, is not
affected by such coverage restrictions.
COMPETITIVE ENVIRONMENT:
In March 1995, prior to the Federal Energy Regulatory Commission's (FERC)
issuance of the Notice of Proposed Rulemaking on open access non-
discriminatory transmission services, the Company and its affiliates filed
with the FERC proposed open access transmission tariffs. Such proposed
tariffs provided for both firm and interruptible service on a point-to-point
basis. Network service, where requested, would be negotiated on a case by
case basis. In July 1995, the Company and its affiliates submitted to the
FERC further support and justification for their tariffs in response to a FERC
Staff request. The Company and its affiliates do not know whether, or to what
extent, the FERC will require modifications to any of the proposed terms and
conditions of these transmission tariffs.
In June 1995, the Securities and Exchange Commission (SEC) approved an
SEC Staff report containing a series of legislative and administrative
recommendations to reform the Public Utility Holding Company Act of 1935
(Holding Company Act). The SEC Staff recommended that the SEC support repeal
of the Holding Company Act with a minimum one year transition period, and a
transfer of audit, reporting and certain other responsibilities to the FERC
while giving state commissions access to holding company books and records.
In the interim, the Staff recommended that the SEC adopt a series of
administrative reforms that would streamline such things as the issuance of
securities for routine financings and permit a wide range of energy related
diversification activities. The Staff also recommended that the SEC more
flexibly interpret the Holding Company Act's integrated system requirements by
allowing utility acquisitions and specifically, combination electric and gas
systems, where the affected state commissions concur.
In response to the Staff report, the SEC has adopted certain changes
which will streamline routine financings, and has proposed a number of others.
GPU and other registered holding companies, believe, however, that repeal of
the Holding Company Act is necessary to remove a significant impediment to
competition.
THE SUPPLY PLAN:
New Energy Supplies:
The Company is currently reevaluating its participation beyond the first
budget phase of a proposed $146 million research and development project to
repower its 82 MW Warren generating station. The repowering project, if
undertaken, would enable the station to comply with state and federal
standards for reduced emissions, and increase electrical output to
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<PAGE>
approximately 100 MW. The U.S. Department of Energy (DOE) has agreed to fund
50% of the project through its Clean Coal Technology Program. A number of
unresolved issues, including the unavailability of a key component, a lagging
schedule, and changing economics, have necessitated a reevaluation of the
project. In June 1995, the Company and the DOE extended the first budget phase
of the project to January 31, 1996 in order to give the DOE time to address
the Company's technical, economic, and project viability concerns. To date,
the Company has spent $2.0 million on the repowering project.
Managing Nonutility Generation
The Company is seeking to reduce the above market costs of nonutility
generation (NUG) agreements, including (1) attempting to convert must-run
agreements to dispatchable agreements; (2) attempting to renegotiate prices of
the agreements; (3) offering contract buy-outs while seeking to recover the
costs through its energy clause and (4) initiating proceedings before federal
and state administrative agencies, and in the courts. In addition, the
Company intends to avoid, to the maximum extent practicable, entering into any
new nonutility generation agreements that are not needed or not consistent
with current market pricing and are supporting legislative efforts to repeal
the Public Utility Regulatory Policies Act of 1978 (PURPA). These efforts may
result in claims against the Company for substantial damages. There can,
however, be no assurance as to what extent the Company's efforts will be
successful in whole or in part. The following is a discussion of some major
nonutility generation activities involving the Company.
In May 1995, the Company filed a petition for enforcement and declaratory
order with the FERC requesting that the FERC overturn two contracts with
nonutility generators, aggregating 160 MW of capacity, and to act against the
PaPUC's implementation of PURPA. Specifically, the Company contended that the
PaPUC's procedures resulting in orders to enter into contracts with qualifying
facilities at prices based on the costs of a "coal proxy" plant violate PURPA
and the FERC's implementing regulations. In June 1995, the FERC denied the
petition. The Company has filed a petition for rehearing with the FERC.
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 its customers by finding that the Company had a 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 Administrative Law Judge (ALJ) for a recommended
decision.
As part of an effort to reduce above-market payments under nonutility
generation agreements, the Company and its affiliates are seeking to implement
a program under which the natural gas fuel and transportation for the
Company's and its affiliates' gas-fired facilities, as well as up to
approximately 1,100 MW of nonutility generation capacity, would be pooled and
managed by a nonaffiliated fuel manager. The Company and its affiliates
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<PAGE>
believe the plan has the potential to provide substantial savings for their
customers. The Company and its affiliates are conducting negotiations with a
nonaffiliated company to serve as fuel manager.
The Company has contracts and anticipated commitments with nonutility
generation suppliers under which a total of 397 MW of capacity are currently
in service and an additional 178 MW are currently scheduled or anticipated to
be in service by 1999.
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<PAGE>
PART II
ITEM 1 - LEGAL PROCEEDINGS
Information concerning the current status of certain legal
proceedings instituted against the Company and its affiliates and
GPU as a result of the March 28, 1979 nuclear accident at Unit 2
of the Three Mile Island nuclear generating station discussed in
Part I of this report in Notes to Consolidated Financial
Statements is incorporated herein by reference and made a part
hereof.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
By Consent of the Sole Stockholder dated March 16, 1995, the
following were elected directors of the Company for the ensuing
year:
R. C. Arnold
J. F. Furst
J. G. Graham
F. D. Hafer
J. R. Leva
G. R. Repko
R. S. Zechman
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(12) Statements Showing Computation of Ratio of Earnings to
Fixed Charges and Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
(27) Financial Data Schedule.
(b) Reports on Form 8-K:
None.
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<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
August 8, 1995 By: \s\ F. D. Hafer
F. D. Hafer, President
August 8, 1995 By: \s\ D. L. O'Brien
D. L. O'Brien, Comptroller
(Principal Accounting Officer)
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<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000077227
<NAME> PENNSYLVANIA ELECTRIC COMPANY
<MULTIPLIER> 1,000
<CURRENCY> US DOLLARS
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> JUN-30-1995
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,770,661
<OTHER-PROPERTY-AND-INVEST> 40,901
<TOTAL-CURRENT-ASSETS> 224,981
<TOTAL-DEFERRED-CHARGES> 383,768
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,420,311
<COMMON> 105,812
<CAPITAL-SURPLUS-PAID-IN> 270,487
<RETAINED-EARNINGS> 312,398
<TOTAL-COMMON-STOCKHOLDERS-EQ> 688,697
105,000 <F1>
36,777
<LONG-TERM-DEBT-NET> 676,507
<SHORT-TERM-NOTES> 15,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 40,795
<LONG-TERM-DEBT-CURRENT-PORT> 9
0
<CAPITAL-LEASE-OBLIGATIONS> 5,975
<LEASES-CURRENT> 22,005
<OTHER-ITEMS-CAPITAL-AND-LIAB> 828,946
<TOT-CAPITALIZATION-AND-LIAB> 2,420,311
<GROSS-OPERATING-REVENUE> 491,863
<INCOME-TAX-EXPENSE> 31,750
<OTHER-OPERATING-EXPENSES> 376,785
<TOTAL-OPERATING-EXPENSES> 408,535
<OPERATING-INCOME-LOSS> 83,328
<OTHER-INCOME-NET> (1,229)
<INCOME-BEFORE-INTEREST-EXPEN> 82,099
<TOTAL-INTEREST-EXPENSE> 31,257 <F2>
<NET-INCOME> 50,842
772
<EARNINGS-AVAILABLE-FOR-COMM> 50,070
<COMMON-STOCK-DIVIDENDS> 30,000 <F3>
<TOTAL-INTEREST-ON-BONDS> 47,033
<CASH-FLOW-OPERATIONS> 94,517
<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 $4,594.
<F3> REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
</FN>
<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
Six Months Ended
June 30, June 30,
1995 1994
OPERATING REVENUES $491 863 $474 302
OPERATING EXPENSES 376 785 405 868
Interest portion of rentals (A) 1 067 1 815
Net expense 375 718 404 053
OTHER INCOME AND DEDUCTIONS:
Allowance for funds used
during construction 2 324 1 795
Other deductions, net (3 629) (63 134)
Total other income and deductions (1 305) (61 339)
EARNINGS AVAILABLE FOR FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS (excluding
taxes based on income) $114 840 $ 8 910
FIXED CHARGES:
Interest on funded indebtedness $ 23 985 $ 23 391
Other interest (B) 8 555 5 186
Interest portion of rentals (A) 1 067 1 815
Total fixed charges $ 33 607 $ 30 392
RATIO OF EARNINGS TO FIXED CHARGES 3.42 0.29(D)
Preferred stock dividend requirement 772 1 817
Ratio of income (loss) before provision for
income taxes to net income (loss) (C) 159.8% 278.8%
Preferred stock dividend requirement
on a pre-tax basis 1 234 5 065
Fixed charges, as above 33 607 30 392
Total fixed charges and
preferred stock dividends $ 34 841 $ 35 457
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS 3.30 0.25(D)
<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 $4,594.
(C) Represents income (loss) before provision for income taxes of $81,233 and
$(21,482), for the six months ended June 30, 1995 and June 30, 1994,
respectively, divided by net income (loss) of $50,842 and $(7,706),
respectively.
(D) Pre-tax earnings for the six months ended June 30, 1994 were inadequate to
cover both fixed charges and combined fixed charges and preferred stock
dividends. The deficiency in pre-tax earnings for the ratio of earnings to
fixed charges and the ratio of earnings to combined fixed charges and
preferred stock dividends is $21,482 and $26,547, respectively, which
represents additional pre-tax earnings needed to reach a one-to-one ratio.
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