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 1-6047
General Public Utilities Corporation
(Exact name of registrant as specified in its charter)
Pennsylvania 13-5516989
(State or other jurisdiction of (I.R.S. Employer)
incorporation or organization) Identification No.)
100 Interpace Parkway
Parsippany, New Jersey 07054-1149
(Address of principal executive offices) (Zip Code)
(201) 263-6500
(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 $2.50 per share: 116,321,864 shares
outstanding.
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General Public Utilities Corporation
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 21
PART II - Other Information 29
Signatures 30
_________________________________
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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<TABLE>
GENERAL PUBLIC UTILITIES CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
<CAPTION>
In Thousands
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $9 082 843 $8 879 630
Less, accumulated depreciation 3 301 382 3 148 668
Net utility plant in service 5 781 461 5 730 962
Construction work in progress 324 818 340 248
Other, net 198 113 195 388
Net utility plant 6 304 392 6 266 598
Other Property and Investments:
Nuclear decommissioning trusts 311 721 260 482
Nonregulated investments, net 116 816 115 538
Nuclear fuel disposal fund 90 595 82 920
Other, net 33 563 33 553
Total other property and investments 552 695 492 493
Current Assets:
Cash and temporary cash investments 19 031 26 731
Special deposits 13 030 10 226
Accounts receivable:
Customers, net 237 361 248 728
Other 56 475 56 903
Unbilled revenues 107 768 113 581
Materials and supplies, at average cost or less:
Construction and maintenance 196 685 184 644
Fuel 47 981 55 498
Deferred energy costs 4 637 8 728
Deferred income taxes 17 562 18 399
Prepayments 232 270 62 164
Total current assets 932 800 785 602
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 149 008 157 042
Unamortized property losses 106 558 108 699
Income taxes recoverable through future rates 574 519 561 498
Other 357 191 370 402
Total regulatory assets 1 187 276 1 197 641
Deferred income taxes 436 110 428 897
Other 60 410 38 546
Total deferred debits and other assets 1 683 796 1 665 084
Total Assets $9 473 683 $9 209 777
The accompanying notes are an integral part of the consolidated financial statements.
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GENERAL PUBLIC UTILITIES CORPORATION 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 $ 314 458 $ 314 458
Capital surplus 686 272 663 418
Retained earnings 1 810 025 1 775 759
Total 2 810 755 2 753 635
Less, reacquired common stock, at cost 162 020 181 051
Total common stockholders' equity 2 648 735 2 572 584
Cumulative preferred stock:
With mandatory redemption 134 000 150 000
Without mandatory redemption 98 116 98 116
Subsidiary-obligated mandatorily redeemable
preferred securities 330 000 205 000
Long-term debt 2 525 840 2 345 417
Total capitalization 5 736 691 5 371 117
Current Liabilities:
Securities due within one year 87 666 91 165
Notes payable 270 261 347 408
Obligations under capital leases 162 513 157 168
Accounts payable 249 454 317 259
Taxes accrued 19 563 80 027
Interest accrued 69 556 66 628
Other 267 243 213 041
Total current liabilities 1 126 256 1 272 696
Deferred Credits and Other Liabilities:
Deferred income taxes 1 462 739 1 438 743
Unamortized investment tax credits 151 088 156 262
Three Mile Island Unit 2 future costs 347 390 341 139
Regulatory liabilities 110 519 122 144
Other 539 000 507 676
Total deferred credits and other liabilities 2 610 736 2 565 964
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $9 473 683 $9 209 777
The accompanying notes are an integral part of the consolidated financial statements.
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GENERAL PUBLIC UTILITIES CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
(Unaudited)
<CAPTION>
In Thousands
(Except Per Share Data)
Three Months Six Months
Ended June 30, Ended June 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $ 864 648 $ 873 533 $1 778 620 $1 810 742
Operating Expenses:
Fuel 81 662 87 391 170 889 190 698
Power purchased and interchanged 222 874 210 323 473 797 444 825
Deferral of energy costs, net 4 091 (344) 5 239 (25 114)
Other operation and maintenance 226 420 368 309 446 133 601 420
Depreciation and amortization 90 344 86 301 179 885 176 114
Taxes, other than income taxes 78 416 82 615 164 477 173 568
Total operating expenses 703 807 834 595 1 440 420 1 561 511
Operating Income Before Income Taxes 160 841 38 938 338 200 249 231
Income taxes 34 523 (6 762) 78 222 46 935
Operating Income 126 318 45 700 259 978 202 296
Other Income and Deductions:
Allowance for other funds used during
construction 1 152 680 2 357 1 326
Other income/(expense), net (3 370) (201 608) (4 170) (143 999)
Income taxes 1 268 86 925 1 423 63 626
Total other income and deductions (950) (114 003) (390) (79 047)
Income/(Loss) Before Interest Charges
and Preferred Dividends 125 368 (68 303) 259 588 123 249
Interest Charges and Preferred Dividends:
Interest on long-term debt 47 366 46 061 92 479 92 204
Other interest 8 954 7 010 15 803 25 519
Allowance for borrowed funds used
during construction (1 965) (1 548) (4 072) (3 065)
Dividends on subsidiary-obligated mandatorily
redeemable preferred securities 5 825 - 10 372 -
Preferred stock dividends of
subsidiaries 4 208 5 516 8 529 11 031
Total interest charges and
preferred dividends 64 388 57 039 123 111 125 689
Net Income/(Loss) $ 60 980 $(125 342) $ 136 477 $ (2 440)
Earnings/(Loss) Per Average Share $ .53 $ (1.09) $ 1.18 $ (.02)
Average Common Shares Outstanding 115 660 115 119 115 502 115 092
Cash Dividends Paid Per Share $ .47 $ .45 $ .92 $ .875
The accompanying notes are an integral part of the consolidated financial statements.
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GENERAL PUBLIC UTILITIES CORPORATION 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) $ 136 477 $ (2 440)
Adjustments to reconcile income (loss) to cash provided:
Depreciation and amortization 183 300 180 103
Amortization of property under capital leases 30 754 30 698
Three Mile Island Unit 2 costs - 183 944
Voluntary enhanced retirement programs - 126 964
Nuclear outage maintenance costs, net 14 562 15 297
Deferred income taxes and investment tax credits, net 21 488 (98 835)
Deferred energy costs, net 5 413 (24 908)
Accretion income (6 260) (7 641)
Allowance for other funds used during construction (2 357) (1 327)
Changes in working capital:
Receivables 13 123 (12 565)
Materials and supplies (4 524) (507)
Special deposits and prepayments (179 280) (158 780)
Payables and accrued liabilities (76 803) (21 997)
Other, net 5 195 ( 4 061)
Net cash provided by operating activities 141 088 203 945
Investing Activities:
Cash construction expenditures (229 680) (245 213)
Contributions to decommissioning trusts (16 609) (16 647)
Nonregulated investments (1 710) (52 877)
Other, net (346) (7 657)
Net cash used for investing activities (248 345) (322 394)
Financing Activities:
Issuance of long-term debt 168 920 178 787
Increase (Decrease) in notes payable, net (77 184) 180 661
Retirement of long-term debt (3 200) (107 200)
Capital lease principal payments (27 459) (28 684)
Issuance of common stock 29 645 -
Issuance of subsidiary-obligated mandatorily
redeemable preferred securities 120 906 -
Redemption of preferred stock of subsidiaries (6 049) -
Dividends paid on common stock (106 022) (100 625)
Net cash provided by financing activities 99 557 122 939
Net increase (decrease) in cash and temporary
cash investments from above activities (7 700) 4 490
Cash and temporary cash investments, beginning of year 26 731 25 843
Cash and temporary cash investments, end of period $ 19 031 $ 30 333
Supplemental Disclosure:
Interest and preferred dividends paid $ 122 208 $ 119 703
Income taxes paid $ 127 531 $ 34 730
New capital lease obligations incurred $ 34 376 $ 32 855
Common stock dividends declared but not paid $ 54 670 $ 51 786
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
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GENERAL PUBLIC UTILITIES CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Public Utilities Corporation (the Corporation) is a holding
company registered under the Public Utility Holding Company Act of 1935. The
Corporation does not directly operate any utility properties, but owns all the
outstanding common stock of three electric utilities -- Jersey Central Power &
Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania
Electric Company (Penelec) (the Subsidiaries). The Corporation also owns all
the common stock of 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 these
companies considered together with their subsidiaries 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 Subsidiaries have made investments in three major nuclear projects--
Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are
operational generating facilities, and Three Mile Island Unit 2 (TMI-2), which
was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by
JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%,
respectively. Oyster Creek is owned by JCP&L. At June 30, 1995 and December
31, 1994, the Subsidiaries' net investment in TMI-1 and Oyster Creek,
including nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 Oyster Creek
June 30, 1995 $640 $791
December 31, 1994 $627 $817
The Subsidiaries' net investment in TMI-2 at June 30, 1995 and December
31, 1994 was $101 million and $103 million, respectively, of which JCP&L's
remaining investment was $87 million and $89 million, respectively. JCP&L is
collecting retail revenues for TMI-2 on a basis which provides for the
recovery of its remaining investment in the plant by 2008. Met-Ed and Penelec
have recovered substantially all of their investments 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 GPU System may also
incur costs and experience reduced output at its nuclear plants because of the
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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 the Corporation and the
Subsidiaries. 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 Subsidiaries 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 the Corporation and the Subsidiaries 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
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out of the U.S. Treasury. The Court also denied the defendants' motion
seeking a dismissal of all cases on the grounds that the defendants complied
with applicable federal safety standards regarding permissible radiation
releases from TMI-2 and that, as a matter of law, the defendants therefore did
not breach any duty that they may have owed to the individual plaintiffs. The
Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgment. In July 1994, the Court
granted defendants' 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 the Corporation
and the Subsidiaries; 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 Subsidiaries 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 Subsidiaries intend to complete the funding for Oyster Creek and TMI-1 by
the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2
funding completion date is 2014, consistent with TMI-2's remaining in long-
term storage and being decommissioned at the same time as TMI-1. Under the
NRC regulations, the funding targets (in 1994 dollars) for TMI-1 and Oyster
Creek are $157 million and $189 million, respectively. Based on NRC studies,
a comparable funding target for TMI-2 has been developed which takes the
accident into account (see TMI-2 Future Costs). The NRC continues to study
the levels of these funding targets. Management cannot predict the effect
that the results of this review will have on the funding targets. NRC
regulations and a regulatory guide provide mechanisms, including exemptions,
to adjust the funding targets over their collection periods to reflect
increases or decreases due to inflation and changes in technology and
regulatory requirements. The funding targets, while not considered cost
estimates, are reference levels designed to assure that licensees demonstrate
adequate financial responsibility for decommissioning. While the regulations
address activities related to the removal of the radiological portions of the
plants, they do not establish residual radioactivity limits nor do they
address costs related to the removal of nonradiological structures and
materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1
and Oyster Creek that considered various decommissioning plans and estimated
the cost of decommissioning the radiological portions of each plant to range
from approximately $225 to $309 million and $239 to $350 million, respectively
(in 1994 dollars). In addition, the studies estimated the cost of removal of
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nonradiological structures and materials for TMI-1 and Oyster Creek at
$74 million and $48 million, respectively (in 1994 dollars). To date, no
site-specific study has been performed for TMI-2.
The ultimate cost of retiring the GPU System's 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
Subsidiaries charge to expense and contribute to external trusts amounts
collected from customers for nuclear plant decommissioning and nonradiological
costs. In addition, the Subsidiaries have contributed amounts written off for
TMI-2 nuclear plant decommissioning in 1990 and 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 Met-
Ed and Penelec 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, Oyster Creek and 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 and Oyster Creek:
JCP&L is collecting revenues for decommissioning, which are expected to
result in the accumulation of its share of the NRC funding target for each
plant. JCP&L is also collecting revenues, based on estimates of $15.3 million
for TMI-1 and $31.6 million for Oyster Creek adopted in previous rate orders
issued by the New Jersey Board of Public Utilities (NJBPU), for its share of
the cost of removal of nonradiological structures and materials. The
Pennsylvania Public Utility Commission (PaPUC) previously granted Met-Ed
revenues for decommissioning costs of TMI-1 based on its share of the NRC
funding target and nonradiological cost of removal as estimated in the site-
specific study. The PaPUC also approved a rate change for Penelec which
increased the collection of revenues for decommissioning costs for TMI-1 to a
basis equivalent to that granted Met-Ed. Collections from customers for
retirement expenditures are deposited in external trusts. Provision for the
future expenditures of these funds has been made in accumulated depreciation,
amounting to $57 million for TMI-1 and $120 million for Oyster Creek at
June 30, 1995. Oyster Creek and TMI-1 retirement costs are charged to
depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 and Oyster Creek retirement costs, in
excess of those currently recognized for ratemaking purposes, should be
recoverable under the current ratemaking process.
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TMI-2 Future Costs:
The Subsidiaries have recorded a liability for the radiological
decommissioning of TMI-2, reflecting the NRC funding target (in 1995 dollars).
The Subsidiaries record escalations, when applicable, in the liability based
upon changes in the NRC funding target. The Subsidiaries have also recorded a
liability for incremental costs specifically attributable to monitored
storage. In addition, the Subsidiaries 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. Estimated TMI-2 Future Costs
as of June 30, 1995 and December 31, 1994 are as follows:
June 30, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $256 $250
Nonradiological Cost of Removal 72 72
Incremental Monitored Storage 19 19
Total $347 $341
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At June 30, 1995, $112 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and
$48 million was recoverable from customers and included in Three Mile Island
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. As a consequence of the Commonwealth Court decision,
Met-Ed recorded pre-tax charges totaling $127.6 million during 1994. Penelec,
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
$121 million for radiological decommissioning costs, $48.2 million for the
nonradiological cost of removal and $14.7 million for incremental monitored
storage costs. Met-Ed and Penelec will await resolution of the appeal pending
before the Pennsylvania Supreme Court before making any nonrecoverable funding
contributions to external trusts for their share of these costs. The
Pennsylvania Subsidiaries are similarly required to charge to expense their
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 for Met-Ed and Penelec are recorded
as income. Prior to the Commonwealth Court's decision, Met-Ed and Penelec
contributed $40 million and $20 million respectively, to external trusts
relating to their shares of the accident-related portion of the
decommissioning liability. JCP&L also made a contribution of $15 million to
an external decommissioning trust. These contributions were not recovered
from customers and have been expensed. JCP&L's share of earnings on trust fund
deposits are offset against amounts shown on the balance sheet under Three
Mile Island Unit 2 Deferred Costs as collectible from customers.
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The NJBPU has granted JCP&L decommissioning revenues for the remainder
of the NRC funding target and allowances for the cost of removal of
nonradiological structures and materials. JCP&L, which is not affected by the
Commonwealth Court's ruling, intends to seek recovery for any increases in
TMI-2 retirement costs, but recognizes that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage in late
1993, the Subsidiaries are incurring incremental annual storage costs of
approximately $1 million. The Subsidiaries estimate that the remaining annual
storage costs will total $19 million through 2014, the expected retirement
date of TMI-1. JCP&L's rates reflect its $5 million share of these costs.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for
its operations and facilities including coverage for property damage,
liability to employees and third parties, and loss of use and occupancy
(primarily incremental replacement power costs). There is no assurance that
the GPU System will maintain all existing insurance coverages. Losses or
liabilities that are not completely insured, unless allowed to be recovered
through ratemaking, could have a material adverse effect on the financial
position of the GPU System.
The decontamination liability, premature decommissioning and property
damage insurance coverage for the TMI station and for Oyster Creek totals
$2.7 billion per site. In accordance with NRC regulations, these insurance
policies generally require that proceeds first be used for stabilization of
the reactors and then to pay for decontamination and debris removal expenses.
Any remaining amounts available under the policies may then be used for repair
and restoration costs and decommissioning costs. Consequently, there can be
no assurance that in the event of a nuclear incident, property damage
insurance proceeds would be available for the repair and restoration of that
station.
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 in any one
year under insurance policies applicable to nuclear operations and facilities.
The GPU System has insurance coverage for incremental replacement power
costs resulting from an accident-related outage at its nuclear plants.
Coverage commences after the first 21 weeks of the outage and continues for
three years beginning at $1.8 million for Oyster Creek and $2.6 million for
TMI-1 per week for the first year, decreasing by 20 percent for years two and
three.
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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 Subsidiaries have
entered into power purchase agreements with nonutility generators for the
purchase of energy and capacity for periods up to 26 years. The majority of
these agreements contain certain contract limitations and subject the
nonutility generators to penalties for nonperformance. While a few of these
facilities are dispatchable, most are must-run and generally obligate the
Subsidiaries 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 1,535 MW (JCP&L 892 MW, Met-Ed 246 MW and Penelec 397 MW) of capacity
were in service and 89 MW were scheduled to commence operation later in 1995.
Estimated payments to nonutility generators from 1995 through 1999, assuming
all facilities which have existing agreements, or which have obtained orders
granting them agreements enter service, are as follows:
Payments Under Nonutility Agreements
(Millions)
Total JCP&L Met-Ed Penelec
1995 $ 694 $ 395 $ 114 $ 185
1996 918 556 170 192
1997 1,062 571 278 213
1998 1,306 587 414 305
1999 1,340 607 419 314
These agreements, in the aggregate, will provide approximately 2,589 MW
(JCP&L 1,202 MW, Met-Ed 812 MW and Penelec 575 MW) of capacity and energy to
the GPU System, at varying prices.
The emerging competitive generation market has created uncertainty
regarding the forecasting of the System's energy supply needs which has caused
the Subsidiaries 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 Subsidiaries' nonutility
generation agreements are substantially in excess of current and projected
prices from alternative sources.
The Subsidiaries 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
Subsidiaries intend to avoid, to the maximum extent practicable, entering into
any new nonutility generation agreements that are not needed or not consistent
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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 Subsidiaries' efforts will be successful in whole or in part.
While the Subsidiaries thus far have been granted recovery of their
nonutility generation costs from customers by the PaPUC and NJBPU, there can
be no assurance that the Subsidiaries 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.
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 GPU System'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 GPU System'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.
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Management believes that to the extent that the GPU System 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 Subsidiaries have
deferred certain costs pursuant to actions of the NJBPU, PaPUC and Federal
Energy Regulatory Commission (FERC) and are recovering or expect 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 $ 574,519 $102,332
TMI-2 deferred costs 149,008 -
TMI-2 tax refund - 3,786
Unamortized property losses 106,558 -
N.J. unit tax 54,185 -
Unamortized loss on reacquired debt 52,664 -
DOE enrichment facility decommissioning 42,182 -
Load and demand side management programs 44,220 -
Other postretirement benefits 50,552 -
Manufactured gas plant remediation 29,548 -
Nuclear fuel disposal fee 23,608 -
Storm damage 23,048 -
N.J. low level radwaste disposal 16,935 -
Oyster Creek deferred costs 11,430 -
Other 8,819 4,401
Total $1,187,276 $110,519
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: Primarily represents costs that are being recovered
through retail rates for the remaining JCP&L investment in the plant and fuel
core, radiological decommissioning for JCP&L's share of the NRC's funding
target and allowances for the cost of removal of nonradiological structures
and materials, and long-term monitored storage costs. For additional
information, see TMI-2 Future Costs.
TMI-2 tax refund: Represents the tax refund related to the tax abandonment of
TMI-2. This balance is being amortized by the Pennsylvania subsidiaries
concurrent with its return to customers through a base rate credit.
Unamortized property losses: Consists mainly of costs associated with JCP&L's
Forked River Project, which is included in rates.
N.J. unit tax: JCP&L received NJBPU approval in 1993 to recover, over a ten-
year period on an annuity basis, $71.8 million of Gross Receipts and Franchise
Tax not previously recovered from customers.
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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 Subsidiaries' energy adjustment clauses.
Load and demand side management (DSM) programs: Consists of load management
costs that are currently being recovered through JCP&L's retail base rates
pursuant to a 1993 NJBPU order, and other DSM program expenditures that are
recovered annually. Also includes provisions for lost revenues between base
rate cases and performance incentives.
Other postretirement benefits: Includes costs associated with the adoption of
FAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions." Recovery of these costs is subject to regulatory approval.
Manufactured gas plant remediation: Consists of costs associated with the
investigation and remediation of several gas manufacturing plants. For
additional information, see ENVIRONMENTAL MATTERS.
Nuclear fuel disposal fee: Represents amounts recoverable through rates for
estimated future disposal costs for spent nuclear fuel at Oyster Creek and
TMI-1 in accordance with the Nuclear Waste Policy Act of 1982.
Storm damage: Relates to noncapital costs associated with various storms in
the JCP&L service territory that are not recoverable through insurance. These
amounts were deferred based upon past rate recovery precedent. An annual
amount for recovery of storm damage expense is included in JCP&L's retail base
rates.
N.J. low level radwaste disposal: Represents the accrual of the estimated
assessment for disposal of low-level waste from Oyster Creek, less
amortization as allowed in JCP&L's rates.
Oyster Creek deferred costs: Consists of replacement power and O&M costs
deferred in accordance with orders from the NJBPU. JCP&L has been granted
recovery of these costs through rates at an annual amount until fully
amortized.
Amounts related to the decommissioning of TMI-1 and Oyster Creek, which
are not included in Regulatory Assets on the balance sheet, are separately
disclosed in NUCLEAR PLANT RETIREMENT COSTS.
The Subsidiaries continue to be subject to cost-based ratemaking
regulation. The Corporation is unable to estimate to what extent FAS 71 may no
longer be applicable to its utility assets in the future.
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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 GPU System 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 Subsidiaries expect to spend up to $380 million for air pollution
control equipment by the year 2000. In developing its least-cost plan to
comply with the Clean Air Act, the GPU System will continue to evaluate major
capital investments compared to participation in the emission allowance market
and the use of low-sulfur fuel or retirement of facilities. In 1994, the
Ozone Transport Commission (OTC), consisting of representatives of 12
northeast states (including New Jersey and Pennsylvania) 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 Corporation expects that the U.S.
Environmental Protection Agency (EPA) will approve the proposal, and that as a
result, the Subsidiaries will spend an estimated $60 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 Subsidiaries are unable to
determine what additional costs, if any, will be incurred.
The GPU System companies have been notified by the EPA and state
environmental authorities that they are 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 12 hazardous and/or toxic
waste sites. In addition, the Subsidiaries have been requested to voluntarily
participate in the remediation or supply information to the EPA and state
environmental authorities on several other sites for which they have not yet
been named as PRPs. The Subsidiaries have 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 Subsidiaries.
JCP&L has entered into agreements with the New Jersey Department of
Environmental Protection for the investigation and remediation of 17 formerly
owned manufactured gas plant sites. JCP&L has also entered into various cost-
sharing agreements with other utilities for some of the sites. As of June 30,
1995, JCP&L has an estimated environmental liability of $32 million recorded
on its balance sheet relating to these sites. The estimated liability is
based upon ongoing site investigations and remediation efforts, including
capping the sites and pumping and treatment of ground water. If the periods
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over which the remediation is currently expected to be performed are
lengthened, JCP&L believes that it is reasonably possible that the ultimate
costs may range as high as $60 million. Estimates of these costs are subject
to significant uncertainties as JCP&L does not presently own or control most
of these sites; the environmental standards have changed in the past and are
subject to future change; the accepted technologies are subject to further
development; and the related costs for these technologies are uncertain. If
JCP&L is required to utilize different remediation methods, the costs could be
materially in excess of $60 million.
In 1993, the NJBPU approved a mechanism similar to JCP&L's Levelized
Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas
plant remediation costs when expenditures exceed prior collections. Since
collections currently exceed expenditures, the NJBPU decision also provided
for interest on the excess to be credited to customers until the overrecovery
is eliminated and for future costs to be amortized over seven years with
interest. A final 1994 NJBPU order indicated that interest is to be accrued
retroactive to June 1993. JCP&L is pursuing reimbursement of the remediation
costs from its insurance carriers. In 1994, JCP&L filed a complaint with the
Superior Court of New Jersey against several of its insurance carriers,
relative to these manufactured gas plant sites. JCP&L requested the Court to
order the insurance carriers to reimburse JCP&L for all amounts it has paid,
or may be required to pay, in connection with the remediation of the sites.
Pretrial discovery has begun in this case.
The GPU System companies are 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 GPU System's construction programs, for which substantial
commitments have been incurred and which extend over several years,
contemplate expenditures of $482 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 Subsidiaries have entered into long-term contracts with
nonaffiliated mining companies for the purchase of coal for certain generating
stations in which they have 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 Subsidiaries' share of the cost of coal purchased under these agreements
is expected to aggregate $90 million for 1995.
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The Subsidiaries have entered into agreements with other utilities to
purchase capacity and energy for various periods through 2004. These
agreements will provide for up to 1,308 MW in 1995, declining to 1,096 MW in
1997 and 696 MW by 2004. For the years 1995 through 1999, payments pursuant
to these agreements are estimated as follows:
Payments Under Other Utility Agreements
(Millions)
Total JCP&L Met-Ed
1995 $ 208 $ 202 $ 6
1996 175 175 -
1997 162 162 -
1998 145 145 -
1999 128 128 -
JCP&L has commenced construction of a 141 MW gas-fired combustion
turbine at its Gilbert generating station. The new facility, coupled with the
retirement of two older units, will result in a net capacity increase of
approximately 95 MW. This estimated $50 million project is expected to be in-
service by mid-1996. In February 1995, the NJDEP issued an air permit for the
facility based, in part, on the NJBPU's December 1994 order which found that
New Jersey's Electric Facility Need Assessment Act is not applicable to this
combustion turbine and that construction of this facility, without a market
test, is consistent with New Jersey energy policies. An industry trade group
representing nonutility generators has appealed the NJDEP's issuance of the
air permit and the NJBPU's order to the Appellate Division of the New Jersey
Superior Court. JCP&L has moved to dismiss the appeal. There can be no
assurance as to the outcome of this proceeding.
The NJBPU has instituted a generic proceeding to address the appropriate
recovery of capacity costs associated with electric utility power purchases
from nonutility generation projects. The proceeding was initiated, in part,
to respond to contentions of the Division of the Ratepayer Advocate (Ratepayer
Advocate), that by permitting utilities to recover such costs through the
LEAC, an excess or "double recovery" may result when combined with the
recovery of the utilities' embedded capacity costs through their base rates.
In 1994, the NJBPU ruled that the 1991 LEAC period was considered closed but
subsequent LEAC periods remain open for further investigation. This matter is
pending before a NJBPU Administrative Law Judge. JCP&L estimates that the
potential exposure from the 1992 LEAC period through February 1996, the end of
the current LEAC period, is $73 million. There can be no assurance as to the
outcome of this proceeding.
JCP&L's two operating nuclear units are subject to the NJBPU's annual
nuclear performance standard. Operation of these units at an aggregate annual
generating capacity factor below 65% or above 75% would trigger a charge or
credit based on replacement energy costs. At current cost levels, the maximum
annual effect on net income of the performance standard charge at a 40%
capacity factor would be approximately $11 million before tax. While a
capacity factor below 40% would generate no specific monetary charge, it would
require the issue to be brought before the NJBPU for review. The annual
measurement period, which begins in March of each year, coincides with that
used for the LEAC.
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During the normal course of the operation of their businesses, in
addition to the matters described above, the GPU System companies are 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 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 GPU
System's financial position or results of operations.
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General Public Utilities Corporation 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 Corporation'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
Corporation's 1994 Annual Report on Form 10-K.
RESULTS OF OPERATIONS
Net income for the second quarter of 1995 was $61.0 million, or $0.53 per
share, compared to a net loss of $125.3 million, or a $1.09 loss per share,
for the same period ended 1994. The increase in second quarter earnings was
due to GPU's recognition in 1994 of one-time charges totaling $191.6 million
after-tax, or $1.66 per share. These one-time charges consisted of a write-
off of certain Three Mile Island Unit 2 (TMI-2) retirement costs ($104.9
million) resulting from a Pennsylvania court order, costs related to voluntary
enhanced retirement programs ($76.1 million), and a write-off of
postretirement benefit costs ($10.6 million) not considered likely to be
recovered in rates.
Lower operation and maintenance (O&M) expense, which included payroll and
benefits savings from the retirement programs, also contributed to the
earnings increase. However, this increase was more than offset by lower sales
from cooler spring weather this year compared to last year.
For the six months ended June 30, 1995 net income was $136.5 million, or
$1.18 per share, compared to a net loss of $2.4 million, or a $0.02 loss per
share, for the same period last year. The same factors affecting the
quarterly results also affected the results for the six month period. In
addition, earnings for the current six month period versus last year
benefitted from increased sales from new customer growth. Earnings compared
to last year were negatively affected by higher reserve capacity expense and
lower sales due to warmer 1995 winter weather. Also affecting the six months
earnings comparison was nonrecurring interest income (net of nonrecurring
interest expense) in 1994 of $26.9 million after-tax, or $0.23 per share,
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 decreased 1.0% to
$864.6 million, as compared to the second quarter of 1994. For the six months
ended June 30, 1995, revenues decreased 1.8% to $1.78 billion, as compared to
the same period last year. The components of the changes are as follows:
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(In Millions)
Three Months Six Months
Ended Ended
June 30, 1995 June 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $(22.4) $(48.5)
Energy revenues 19.4 27.2
Other revenues (5.9) (10.8)
Decrease in revenues $ (8.9) $(32.1)
Kilowatt-hour revenues
The decrease in KWH revenues in the three and six month periods was due
primarily to lower residential sales from a warmer winter and cooler spring
this year as compared to the previous year. New customer additions in the
residential and commercial sectors partially offset these decreases.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased in both the three and six month periods
primarily from higher energy cost rates and increased sales to other
utilities, 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 Subsidiaries' energy
clauses. However, earnings for the six months ended June 1995 were negatively
impacted by higher reserve capacity expense resulting primarily from higher
payments to the Pennsylvania-New Jersey-Maryland Interconnection and a one-
time $3.3 million pre-tax charge from another utility.
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
1995 was primarily attributable to a one-time $127 million pre-tax charge in
1994 related to the voluntary enhanced retirement programs. Also contributing
to the O&M reduction was payroll and benefits savings from the retirement
programs and lower first quarter winter storm repair costs.
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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 for the three and six months ended June 1995
was primarily attributable to write-offs in 1994 consisting of $183.9 million
pre-tax for certain TMI-2 retirement costs resulting from a Pennsylvania court
order, and $18.6 million pre-tax for postretirement benefit costs not
considered likely to be recovered in rates. The increase was partially offset
by lower first quarter interest income of $59.4 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 PREFERRED DIVIDENDS:
Other interest
Other interest expense for the six months ended June 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 $13.8 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 subsidiary-obligated mandatorily redeemable preferred securities
In 1994, Met-Ed and Penelec issued $100 million and $105 million,
respectively, and in May 1995, JCP&L issued $125 million, of monthly income
preferred securities through special-purpose finance subsidiaries. Dividends
on these securities are payable monthly.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The GPU System's capital needs for the six months ended June 30, 1995
consisted of cash construction expenditures of $230 million. Construction
expenditures for the year are forecasted to be $482 million. Expenditures for
maturing debt are expected to be $91 million for 1995. Management estimates
that approximately two-thirds of the capital needs in 1995 will be satisfied
through internally generated funds.
FINANCING:
During the 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
Subsidiaries.
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In addition, JCP&L Capital L.P., a special-purpose finance subsidiary of
JCP&L, issued $125 million stated value of monthly income preferred
securities. The proceeds from the issuance were used to reduce JCP&L's
outstanding short-term debt. Met-Ed issued $30 million principal amount of
first mortgage bonds (FMBs), the proceeds of which were used to reduce
outstanding short-term debt.
Also in the second quarter, JCP&L repurchased in the market, 60,000
shares of its 7.52% Series K cumulative preferred stock. The repurchased
shares may be used to satisfy future sinking fund requirements.
In July 1995, Met-Ed redeemed at maturity $12 million principal amount of
4 5/8% FMBs. Met-Ed also issued $28.5 million principal amount of 6.10% FMBs
as collateral for a like amount of pollution control revenue refunding bonds
issued by the Northampton County Industrial Development Authority. The
proceeds from the sale of the authority bonds will be used to redeem the
Authority's 10 1/2% pollution control bonds maturing September 1, 1995, issued
to finance construction of pollution control facilities at Met-Ed's Portland
station.
The Subsidiaries have regulatory authority to issue and sell first
mortgage bonds, which may be issued as secured medium-term notes, and
preferred stock through 1995 in the case of Met-Ed, and June 1997 for JCP&L
and Penelec. Under existing authorizations, JCP&L, Met-Ed and Penelec may
issue senior securities in the amount of $225 million, $190 million and
$230 million, respectively, of which $100 million for each Subsidiary may
consist of preferred stock. Met-Ed and Penelec, through their special-purpose
finance subsidiaries, have remaining regulatory authority to issue an
additional $25 million and $20 million, respectively, of monthly income
preferred securities. The Subsidiaries also have regulatory authority to
incur short-term debt, a portion of which may be through the issuance of
commercial paper.
The Subsidiaries' bond indentures and articles of incorporation include
provisions that limit the amount of long-term debt, preferred stock and short-
term debt the Subsidiaries may issue. The Subsidiaries' 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 Subsidiaries to issue,
through their special-purpose subsidiaries, 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 Subsidiaries 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 Subsidiaries submitted to the FERC further support and
justification for their tariffs in response to a FERC Staff request. The
Subsidiaries 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.
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In July 1995, New Jersey adopted energy rate flexibility legislation that
will enable electric utilities to offer rate discounts to certain customers
and allow these customers access to competitive markets. If certain
conditions are met, utilities are permitted to recover from customers 50% of
revenue lost as a result of a rate discount. The legislation also provides
utilities with the opportunity to propose to the New Jersey Board of Public
Utilities (NJBPU) alternative ways to set rates.
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.
Nonregulated Business:
As of June 30, 1995, GPU's aggregate investment in Energy Initiatives,
Inc. and EI Power, Inc. totaled $118 million. In July 1995, EI Power acquired
from the Bolivian government, for approximately $47 million, a 50% ownership
interest in a Bolivian electric generating company having an aggregate
capacity of approximately 216 megawatts (MW) of gas-fired and oil-fired
generation.
THE GPU SUPPLY PLAN:
New Energy Supplies:
Penelec 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
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, Penelec and the DOE extended the first budget phase of
the project to January 31, 1996 in order to give the DOE time to address
Penelec's technical, economic, and project viability concerns. To date,
Penelec has spent $2.0 million on the repowering project.
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JCP&L has commenced construction of a 141 MW gas-fired combustion turbine
at its Gilbert generating station. The new facility, coupled with the
retirement of two older units, will result in a net capacity increase of
approximately 95 MW. This estimated $50 million project is expected to be in-
service by mid-1996. In February 1995, the New Jersey Department of
Environmental Protection (NJDEP) issued an air permit for the facility based,
in part, on the NJBPU's December 1994 order which found that New Jersey's
Electric Facility Need Assessment Act is not applicable to this combustion
turbine and that construction of this facility, without a market test, is
consistent with New Jersey energy policies. An industry trade group
representing nonutility generators has appealed the issuance of the air permit
by the NJDEP and the NJBPU's order to the Appellate Division of New Jersey
Superior Court. JCP&L has moved to dismiss the appeal. There can be no
assurance as to the outcome of this proceeding.
Managing Nonutility Generation
The Subsidiaries are 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 their energy clauses and (4) initiating proceedings
before federal and state administrative agencies, and in the courts. In
addition, the Subsidiaries 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 GPU System for substantial
damages. There can, however, be no assurance as to what extent the
Subsidiaries' efforts will be successful in whole or in part. The following
is a discussion of some major nonutility generation activities involving the
Subsidiaries.
In March 1995, the U.S. Court of Appeals denied petitions for rehearing
filed by JCP&L, the NJBPU and the New Jersey Division of Ratepayer Advocate
asking that the Court reconsider its January 1995 decision prohibiting the
NJBPU from reexamining its order approving the rates payable to a nonutility
generator under a long-term power purchase agreement entered into pursuant to
PURPA. Also in March 1995, JCP&L petitioned the FERC to declare the agreement
unlawful on the grounds that when it was approved by the NJBPU, the contract
pricing violated PURPA. In two recent decisions involving other utilities,
the FERC ruled that PURPA prohibits the states from requiring utilities to
enter into contracts at rates higher than the utility's avoided costs, and
found that contracts containing these rates are void under certain conditions.
In June 1995, JCP&L and the Ratepayer Advocate filed petitions with the U.S.
Supreme Court seeking to review the U.S. Court of Appeals decision. JCP&L's
petition before the FERC is pending.
In April 1995, Met-Ed agreed to buy-out the power purchase agreement for
a 13 MW unconstructed nonutility generating facility. Met-Ed estimates that
the buy-out of the uneconomic power purchase contract will save its customers
$16 million over 25 years. In June 1995, the PaPUC authorized recovery from
customers of the $1.65 million buy-out price over a two year period, starting
with Met-Ed's April 1, 1996 energy cost rate.
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<PAGE>
In May 1995, Met-Ed and Penelec filed a petition for enforcement and
declaratory order with the FERC requesting that the FERC overturn four
contracts with nonutility generators, aggregating 487 MW of capacity, and to
act against the PaPUC's implementation of PURPA. Specifically, Met-Ed and
Penelec 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. Met-Ed and Penelec have filed a
petition for rehearing with the FERC.
In 1994, a nonutility generator requested that the NJBPU and the PaPUC
order JCP&L and Met-Ed to enter into long-term agreements to buy capacity and
energy. JCP&L contested the request and the NJBPU referred the matter to an
Administrative Law Judge (ALJ) for hearings. In February 1995, the ALJ issued
an initial decision stating that the nonutility generator had created a
legally enforceable obligation, but the appropriate avoided cost to be used
was still to be decided by the NJBPU. However, in April 1995, the NJBPU
remanded the proceeding to the ALJ for fact finding. Met-Ed sought to dismiss
the request based on a May 1994 PaPUC order, which granted Met-Ed and Penelec
permission to obtain additional nonutility purchases through competitive
bidding until new PaPUC regulations have been adopted. In September 1994, the
Pennsylvania Commonwealth Court granted the PaPUC's application to revise its
May 1994 order for the purpose of reevaluating the nonutility generator's
right to sell power to Met-Ed. The PaPUC subsequently ordered that hearings
be held in this matter. In March 1995, Met-Ed moved to dismiss the nonutility
generator's petition. The nonutility generator has filed a cross-motion for
summary judgment. The matter is pending before the PaPUC.
In May 1994, the NJBPU issued orders granting two nonutility generators,
aggregating 200 MW, a final in-service (sunset) date extension for projects
originally scheduled to be operational in 1997. The NJBPU orders extend the
in-service dates for one year plus any appeal period. In May 1995, the
Appellate Division of the New Jersey Superior Court reversed the NJBPU
decision. In June 1995, the New Jersey Assembly passed a bill which, if
enacted, would have the effect of nullifying the Court's decision by
retroactively extending the in-service deadlines on the two projects for three
years. The State Senate is expected to consider the legislation in September
1995.
In November 1994, Penelec requested the Pennsylvania Supreme Court to
review a Commonwealth Court decision upholding a PaPUC order requiring Penelec
to purchase a total of 160 MW from two nonutility generators. The PaPUC had
ordered Penelec 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
Penelec's appeal of the PaPUC order. Penelec's petition to the Supreme Court
contends that the Commonwealth Court imposed unnecessary and excessive costs
on Penelec customers by finding that Penelec 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 Subsidiaries are seeking to implement a program
under which the natural gas fuel and transportation for the Subsidiaries'
-27-
<PAGE>
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 Subsidiaries believe the plan has the potential to provide
substantial savings for their customers. The Subsidiaries are conducting
negotiations with a nonaffiliated company to serve as fuel manager.
The Subsidiaries have contracts and anticipated commitments with
nonutility generation suppliers under which a total of 1,535 MW of capacity
are currently in service and an additional 1,054 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 Corporation and its
subsidiaries 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
At the Annual Meeting of Stockholders held on May 4, 1995, the
following individuals were reelected as directors of the
Corporation for three year terms expiring at the 1998 annual
meeting.
Name Votes For Votes Withheld
Henry F. Henderson, Jr. 99,308,789 1,263,876
James R. Leva 99,399,387 1,263,876
John M. Pietruski 99,385,954 1,263,876
Catherine A. Rein 99,308,578 1,263,876
Louis J. Appell, Jr., Donald J. Bainton, and Theodore H. Black,
whose terms expire at the 1996 annual meeting, and Paul R. Roedel,
Carlisle A. H. Trost, and Patricia K. Woolf, whose terms expire at
the 1997 annual meeting, continue to serve as directors following
the meeting.
At the Annual Meeting, stockholders approved by a vote of
71,283,964 shares for, 28,293,694 shares against and 1,036,895
shares abstained, an amendment to Article 5 of the Corporation's
Article of Incorporation to increase the number of authorized
shares of Common Stock to 350,000,000 shares, par value $2.50 per
share, from 150,000,000 shares. Stockholders also approved, by a
vote of 69,505,164 shares for, 19,188,636 shares against,
1,361,319 shares abstained and 10,559,434 shares broker non-votes,
an amendment to Article 9 of the Corporation's Article of
Incorporation eliminating the remaining preemptive rights of
stockholders to purchase additional shares of Common Stock.
Stockholders also ratified at the Annual Meeting the selection of
Coopers & Lybrand L.L.P. as independent auditor for the year 1995
by a vote of 99,495,374 shares for, 566,234 shares against and
552,945 shares abstained.
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 June 1995, dated June 9, 1995, under Item 5
(Other Events).
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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.
GENERAL PUBLIC UTILITIES CORPORATION
August 8, 1995 By: /s/ J. G. Graham
J. G. Graham, Senior Vice President
(Chief Financial Officer)
August 8, 1995 By: /s/ F. A. Donofrio
F. A. Donofrio, Vice President
and Comptroller
(Chief Accounting Officer)
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<PAGE>
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