UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1995
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-6047
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 October 31, 1995, was as follows:
Common stock, par value $2.50 per share: 116,373,614 shares
outstanding.
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General Public Utilities Corporation
Quarterly Report on Form 10-Q
September 30, 1995
Table of Contents
Page
PART I - Financial Information
Financial Statements:
Balance Sheets 3
Statements of Income 5
Statements of Cash Flows 6
Notes to Financial Statements 7
Management's Discussion and Analysis of
Financial Condition and Results of
Operations 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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GENERAL PUBLIC UTILITIES CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
<CAPTION>
In Thousands
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant:
In service, at original cost $9 165 011 $8 879 630
Less, accumulated depreciation 3 373 530 3 148 668
Net utility plant in service 5 791 481 5 730 962
Construction work in progress 345 862 340 248
Other, net 199 366 195 388
Net utility plant 6 336 709 6 266 598
Other Property and Investments:
Nuclear decommissioning trusts 331 801 260 482
Nonregulated investments, net 231 641 115 538
Nuclear fuel disposal fund 92 799 82 920
Other, net 34 856 33 553
Total other property and investments 691 097 492 493
Current Assets:
Cash and temporary cash investments 30 325 26 731
Special deposits 14 689 10 226
Accounts receivable:
Customers, net 285 361 248 728
Other 56 191 56 903
Unbilled revenues 101 527 113 581
Materials and supplies, at average cost or less:
Construction and maintenance 197 779 184 644
Fuel 37 846 55 498
Deferred income taxes 20 449 14 213
Prepayments 94 155 62 164
Total current assets 838 322 772 688
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 309 422 157 042
Unamortized property losses 105 587 108 699
Income taxes recoverable through future rates 579 200 561 498
Other 424 147 370 402
Total regulatory assets 1 418 356 1 197 641
Deferred income taxes 348 700 428 897
Other 56 872 38 546
Total deferred debits and other assets 1 823 928 1 665 084
Total Assets $9 690 056 $9 196 863
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
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 314 458 $ 314 458
Capital surplus 686 350 663 418
Retained earnings 2 047 570 1 775 759
Total 3 048 378 2 753 635
Less, reacquired common stock, at cost 159 732 181 051
Total common stockholders' equity 2 888 646 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 2 536 626 2 345 417
Total capitalization 5 987 388 5 371 117
Current Liabilities:
Securities due within one year 102 462 91 165
Notes payable 224 780 347 408
Obligations under capital leases 163 172 157 168
Accounts payable 297 793 317 259
Deferred energy credits 912 (8 728)
Taxes accrued 39 793 80 027
Interest accrued 56 289 66 628
Other 214 032 208 855
Total current liabilities 1 099 233 1 259 782
Deferred Credits and Other Liabilities:
Deferred income taxes 1 493 658 1 438 743
Unamortized investment tax credits 148 411 156 262
Three Mile Island Unit 2 future costs 346 818 341 139
Regulatory liabilities 101 724 122 144
Other 512 824 507 676
Total deferred credits and other liabilities 2 603 435 2 565 964
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $9 690 056 $9 196 863
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 Nine Months
Ended September 30, Ended September 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Operating Revenues $1 095 082 $ 994 672 $2 873 702 $2 805 414
Operating Expenses:
Fuel 102 086 96 216 272 975 286 914
Power purchased and interchanged 280 800 230 087 754 597 674 912
Deferral of energy costs, net 4 406 4 826 9 645 (20 288)
Other operation and maintenance 251 288 244 941 697 421 846 361
Depreciation and amortization 101 928 85 519 281 813 261 633
Taxes, other than income taxes 98 355 94 193 262 832 267 761
Total operating expenses 838 863 755 782 2 279 283 2 317 293
Operating Income Before Income Taxes 256 219 238 890 594 419 488 121
Income taxes 71 638 69 876 149 860 116 811
Operating Income 184 581 169 014 444 559 371 310
Other Income and Deductions:
Allowance for other funds used during
construction 1 203 766 3 560 2 092
Other income/(expense), net 194 342 3 026 190 172 (140 973)
Income taxes (82 264) (2 014) (80 841) 61 612
Total other income and deductions 113 281 1 778 112 891 (77 269)
Income Before Interest Charges
and Preferred Dividends 297 862 170 792 557 450 294 041
Interest Charges and Preferred Dividends:
Interest on long-term debt 47 680 46 423 140 159 138 627
Other interest 7 017 6 382 22 820 31 901
Allowance for borrowed funds used
during construction (2 543) (1 797) (6 615) (4 862)
Dividends on subsidiary-obligated mandatorily
redeemable preferred securities 7 222 3 145 17 594 3 145
Preferred stock dividends of
subsidiaries 4 208 5 340 12 737 16 371
Total interest charges and
preferred dividends 63 584 59 493 186 695 185 182
Net Income $ 234 278 $ 111 299 $ 370 755 $ 108 859
Earnings Per Average Common Share $ 2.02 $ .97 $ 3.20 $ .95
Average Common Shares Outstanding 116 512 115 187 115 841 115 124
Cash Dividends Paid Per Share $ .47 $ .45 $ 1.39 $ 1.325
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
Nine Months
Ended September 30,
1995 1994
<S> <C> <C>
Operating Activities:
Net income $ 370 755 $ 108 859
Adjustments to reconcile income to cash provided:
Depreciation and amortization 281 577 270 401
Amortization of property under capital leases 43 039 45 523
Three Mile Island Unit 2 costs (170 005) 183 944
Voluntary enhanced retirement programs - 126 964
Nuclear outage maintenance costs, net 8 178 5 467
Deferred income taxes and investment tax credits, net 95 500 (103 757)
Deferred energy costs, net 9 888 (19 955)
Accretion income (9 390) (11 359)
Allowance for other funds used during construction (3 560) (2 092)
Changes in working capital:
Receivables (19 881) 24 530
Materials and supplies 10 781 2 175
Special deposits and prepayments (37 060) (143 358)
Payables and accrued liabilities (88 678) 10 565
Other, net (43 668) 7 102
Net cash provided by operating activities 447 476 505 009
Investing Activities:
Cash construction expenditures (340 168) (375 076)
Contributions to decommissioning trusts (24 974) (25 027)
Nonregulated investments (47 184) (61 959)
Other, net (3 502) (7 550)
Net cash used for investing activities (415 828) (469 612)
Financing Activities:
Issuance of long-term debt 197 206 178 787
Increase (Decrease) in notes payable, net (123 003) 20 032
Retirement of long-term debt (43 737) (147 232)
Capital lease principal payments (42 486) (47 974)
Issuance of common stock 29 645 -
Issuance of subsidiary-obligated mandatorily
redeemable preferred securities 121 063 198 036
Redemption of preferred stock of subsidiaries (6 049) (26 168)
Dividends paid on common stock (160 693) (152 411)
Net cash provided (required) by financing activities (28 054) 23 070
Net increase in cash and temporary
cash investments from above activities 3 594 58 467
Cash and temporary cash investments, beginning of year 26 731 25 843
Cash and temporary cash investments, end of period $ 30 325 $ 84 310
Supplemental Disclosure:
Interest and preferred dividends paid $ 200 156 $ 203 687
Income taxes paid $ 168 810 $ 84 926
New capital lease obligations incurred $ 45 469 $ 40 206
Common stock dividends declared but not paid $ - $ -
The accompanying notes are an integral part of the consolidated financial statements.
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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 Power, Inc. and EI Energy,
Inc. (collectively, EI), which develop, own and operate generation,
transmission and distribution facilities in the United States and in foreign
countries. All of 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 was derived from audited financial statements. For disclosures
required by generally accepted accounting principles, see the 1994 Annual
Report on Form 10-K.
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The 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 September 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
September 30, 1995 $647 $778
December 31, 1994 $627 $817
The Subsidiaries' net investment in TMI-2 at September 30, 1995 and
December 31, 1994 was $96 million and $103 million, respectively, of which
JCP&L's remaining investment was $86 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
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incur costs and experience reduced output at its nuclear plants because of the
prevailing design criteria at the time of construction and the age of the
plants' systems and equipment. In addition, for economic or other reasons,
operation of these plants for the full term of their now-assumed lives cannot
be assured. Also, not all risks associated with the ownership or operation of
nuclear facilities may be adequately insured or insurable. Consequently, the
ability of electric utilities to obtain adequate and timely recovery of costs
associated with nuclear projects, including replacement power, any unamortized
investment at the end of each plant's useful life (whether scheduled or
premature), the carrying costs of that investment and retirement costs, is not
assured (see NUCLEAR PLANT RETIREMENT COSTS). Management intends, in general,
to seek recovery of such costs through the ratemaking process, but recognizes
that recovery is not assured (see COMPETITION AND THE CHANGING REGULATORY
ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and
contamination of, the plant and a release of radioactivity to the environment.
The cleanup program was completed in 1990, and after receiving Nuclear
Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored
storage in December 1993.
As a result of the accident and its aftermath, individual claims for
alleged personal injury (including claims for punitive damages), which are
material in amount, have been asserted against 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.
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 up to an aggregate of $335 million in premium charges under
such plan, and (c) an indemnity agreement with the NRC for up to $85 million,
bringing their total primary, secondary and tertiary financial protection up
to an aggregate of $560 million. Under the secondary level, the Subsidiaries
are subject to a retrospective premium charge of up to $5 million per reactor,
or a total of $15 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 (the defendants) under a reservation of rights with respect to any
award of punitive damages. However, in March 1994, the defendants in the TMI-
2 litigation and the insurers agreed that the insurers would withdraw their
reservation of rights with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the
punitive damage claims to proceed. A trial of ten allegedly representative
cases is scheduled to begin in June 1996. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury.
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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.
In October 1995, the U.S. Court of Appeals for the Third Circuit ruled
that the Price-Anderson Act provides coverage under its primary and secondary
levels for punitive as well as compensatory damages, but that punitive damages
could not be recovered against the Federal Government. In so doing, the Court
of Appeals referred to the "finite fund" (the $560 million of financial
protection under the Price-Anderson Act) to which plaintiffs must resort to
get compensatory as well as punitive damages.
The Court of Appeals also found that the standard of care owed by the
defendants to a plaintiff was determined by the specific level of radiation
which was released into the environment, as measured at the site boundary,
rather than as measured at the specific site where the plaintiff was located
at the time of the accident (as the Corporation and its Subsidiaries
proposed). The Court of Appeals also held, however, that each plaintiff still
must demonstrate exposure to radiation released during the TMI-2 accident and
that such exposure had resulted in injuries.
The Corporation and its Subsidiaries believe that any liability to which
they might be subject by reason of the TMI-2 accident and these Court of
Appeals decisions will not exceed the financial protection under the Price-
Anderson Act. The Corporation and its Subsidiaries have filed a petition with
the Third Circuit Court seeking a rehearing and en banc reconsideration of its
decision that punitive damages are recoverable under the Price-Anderson Act.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the 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 1995 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
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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 million to $309 million and $239 to $350 million,
respectively (in 1995 dollars). In addition, the studies estimated the cost
of removal of nonradiological structures and materials for TMI-1 and Oyster
Creek at $74 million and $48 million, respectively (in 1995 dollars).
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
(see TMI-2 Future Costs). Amounts deposited in external trusts, including the
interest earned on these funds, are classified as Nuclear Decommissioning
Trusts on the Balance Sheet.
In August 1995, a consultant to GPUN commenced site specific studies of
the TMI site, including both Units 1 and 2, and Oyster Creek. GPUN expects
these studies to be completed in the fourth quarter of 1995.
The Financial Accounting Standards Board (FASB) is reviewing the utility
industry's accounting practices for nuclear plant retirement costs. If the
FASB's tentative conclusions are adopted, Oyster Creek and TMI-1 future
retirement costs will have to be recognized as a liability currently, rather
than recorded over the life of the plants (as is currently the practice), with
an offsetting asset recorded for amounts collectible through rates. Any
amounts not collectible through rates will have to be charged to expense. The
FASB is expected to release an Exposure Draft on decommissioning accounting
practices in the fourth quarter of 1995.
TMI-1 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
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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 expenditure of these funds has been made in accumulated depreciation,
amounting to $60 million for TMI-1 and $110 million for Oyster Creek at
September 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.
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 September 30, 1995. Estimated TMI-2 Future
Costs as of September 30, 1995 and December 31, 1994 are as follows:
September 30, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $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 September 30, 1995, $114 million was in trust funds
for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet,
and $213 million was recoverable from customers and included in Three Mile
Island Unit 2 Deferred Costs on the Balance Sheet. Earnings on trust fund
deposits collected from customers are included in amounts shown on the Balance
Sheet under Three Mile Island Unit 2 Deferred Costs.
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. In 1993, a PaPUC rate order
permitted Met-Ed future recovery of certain TMI-2 retirement costs. The
Pennsylvania Office of Consumer Advocate appealed that order to the
Commonwealth Court, which reversed the PaPUC order in 1994. Consequently,
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. In
September 1995, the Pennsylvania Supreme Court reversed the Commonwealth Court
decision. Met-Ed and Penelec have therefore reversed the previous write-offs,
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resulting in pre-tax income of $127.6 million and $56.3 million, respectively,
being credited to the Other Income and Deductions section of the 1995
Consolidated Statement of Income. However, notwithstanding the Supreme
Court's decision, Met-Ed and Penelec have determined that the recovery of the
incremental monitored storage costs is no longer probable, and have recorded
pre-tax charges to operating income of $10 million and $4.7 million,
respectively, in the third quarter of 1995.
In 1991, 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. In 1990, JCP&L made a
contribution of $15 million to an external decommissioning trust. These
contributions were not recovered from customers and have been expensed.
JCP&L intends to seek recovery for any increases in TMI-2 retirement
costs, and Met-Ed and Penelec intend to seek recovery for any increases in the
non-accident related portion of such costs, but recognize 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
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for each of the GPU System's two operating reactors, subject to an annual
maximum payment of $10 million per incident per reactor. In addition to the
retrospective premiums payable under Price-Anderson, the GPU System is also
subject to retrospective premium assessments of up to $69 million 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 to 80 percent of such amounts
for years two and three.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
Nonutility Generation Agreements:
Pursuant to the requirements of the federal Public Utility Regulatory
Policies Act (PURPA) and state regulatory directives, the 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 September 30, 1995, facilities covered by these
agreements having 1,624 MW (JCP&L 892 MW, Met-Ed 335 MW and Penelec 397 MW) of
capacity were in service. Estimated payments to nonutility generators from
1995 through 1999, assuming that all facilities which have existing
agreements, or which have obtained orders granting them agreements, enter
service, are as follows:
Payments Under Nonutility Agreements
(Millions)
Total JCP&L Met-Ed Penelec
1995 $ 650 $ 380 $ 118 $ 152
1996 685 358 151 176
1997 728 389 155 184
1998 859 419 243 197
1999 1,020 431 311 278
These agreements, in the aggregate, will provide approximately 2,062 MW
(JCP&L 1,002 MW, Met-Ed 485 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
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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 (see Managing Nonutility Generation, in
Management's Discussion and Analysis of Financial Condition and Results of
Operations) and (4) initiating proceedings before federal and state
administrative agencies, and in the courts, where appropriate. In addition,
the 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 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 $240 million to $350 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.
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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.
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 September 30, 1995
Consolidated Balance Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 579,200 $ 97,396
TMI-2 deferred costs 309,422 -
Unamortized property losses 105,587 -
NUG contract termination costs 67,899 -
Other postretirement benefits 55,224 -
N.J. unit tax 52,864 -
Unamortized loss on reacquired debt 51,432 -
Load and demand side management programs 47,643 -
DOE enrichment facility decommissioning 40,628 -
Manufactured gas plant remediation 30,720 -
Storm damage 23,876 -
Nuclear fuel disposal fee 23,087 -
N.J. low-level radwaste disposal 15,572 -
Oyster Creek deferred costs 8,084 -
Other 7,118 4,328
Total $1,418,356 $101,724
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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TMI-2 deferred costs: Represents costs that are recoverable through rates for
the Subsidiaries' remaining investment in the plant and fuel core,
radiological decommissioning in accordance with the NRC's funding target and
allowances for the cost of removal of nonradiological structures and
materials, and JCP&L's share of long-term monitored storage costs. For
additional information, see TMI-2 Future Costs.
Unamortized property losses: Consists mainly of costs associated with JCP&L's
Forked River Project, which are included in rates.
NUG contract termination costs: Represents one-time costs incurred for
terminating power purchase contracts with nonutility generators (NUGs), for
which rate recovery is probable (See Managing Nonutility Generation, in
Management's Discussion and Analysis of Financial Condition and Results of
Operations).
Other postretirement benefits: Includes costs associated with the adoption of
FAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions", which are deferred in accordance with Emerging Issues Task Force
Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises".
N.J. unit tax: JCP&L received NJBPU approval in 1993 to recover, with
interest, over a ten-year period on an annuity basis, $71.8 million of Gross
Receipts and Franchise Tax not previously recovered from customers.
Unamortized loss on reacquired debt: Represents premiums and expenses incurred
in the early redemption of long-term debt. In accordance with FERC
regulations, reacquired debt costs are amortized over the remaining original
life of the retired debt.
Load and demand side management (DSM) programs: Consists of load management
costs that are currently being recovered, with interest, 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.
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.
Manufactured gas plant remediation: Consists of costs being recovered
associated with the investigation and remediation of several gas manufacturing
plants. For additional information, see ENVIRONMENTAL MATTERS.
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.
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.
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N.J. low-level radwaste disposal: Represents the accrual of the estimated
assessment for a disposal facility for 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.
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 Subsidiaries expect that the U.S.
Environmental Protection Agency (EPA) will approve state implementation plans
consistent with the proposal, and that as a result, they will spend an
estimated $60 million, beginning in 1997, to meet the reductions set by the
OTC. The OTC has stated that it anticipates that additional NOx reductions
will be necessary to meet the Clean Air Act's 2005 National Ambient Air
Quality Standards for ozone. However, the specific requirements that will
have to be met at that time have not been finalized. The 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 11 hazardous and/or toxic
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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 most of the sites. As of
September 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 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 because: 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. The NJBPU
decision also provided for interest on any overrecovery 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 $471 million during 1995. As a consequence of
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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.
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 (of which $32 million
has already been spent) 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
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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 refund liability from the 1992 LEAC period through February 1996,
the end of the current LEAC period, is $56 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.
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 the
public, customers, contractors, vendors and other suppliers of equipment and
services and by employees alleging unlawful employment practices. EI, which
has operations in foreign countries, may face additional risks inherent to
operating in such locations, including foreign currency fluctuations and
political instability (see NONREGULATED SUBSIDIARIES, in Management's
Discussion and Analysis of Financial Condition and Results of Operations).
While management does not expect that the outcome of these matters will have a
material effect on the GPU System's financial position or results of
operations, there can be no assurance that this will continue to be the case.
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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 third quarter of 1995 was $234.3 million, or $2.02 per
share, compared to net income of $111.3 million, or $0.97 per share, for the
same period ended 1994. The increase in third quarter earnings was due
primarily to the reversal of $104.9 million (after-tax), or $0.91 per share,
of certain future Three Mile Island Unit 2 (TMI-2) retirement costs written-
off by Metropolitan Edison Company (Met-Ed) ($72.8 million) and Pennsylvania
Electric Company (Penelec) ($32.1 million) in the second quarter of 1994. The
reversal of the TMI-2 write-off resulted from a Pennsylvania Supreme Court
decision that overturned a 1994 Pennsylvania Commonwealth Court order, and
restored a March 1993 Pennsylvania Public Utility Commission (PaPUC) order
that allowed Met-Ed to recover certain future TMI-2 retirement costs from
customers. Partially offsetting this was a charge to income of $8.4 million
(after-tax), or $0.07 per share, of TMI-2 monitored storage costs which Met-Ed
and Penelec believe will not be recoverable through Pennsylvania ratemaking.
Also contributing to the third quarter earnings increase were higher sales
resulting from hotter summer temperatures compared to last year and new
customer growth.
For the nine months ended September 30, 1995 net income was $370.8
million, or $3.20 per share, compared to net income of $108.9 million, or
$0.95 per share, for the same period last year. The same factors affecting
the quarterly results also affected the results for the nine month period. In
addition, net income for the nine months ended last year included several one-
time items that resulted in a net after-tax earnings reduction of $164.7
million, or $1.43 per share.
The 1994 one-time items included a write-off of $104.9 million ($0.91 per
share) of certain future TMI-2 retirement costs, $76.1 million ($0.66 per
share) for early retirement program costs, the write-off of $10.6 million
($0.09 per share) of postretirement benefit costs; and net interest income of
$26.9 million ($0.23 per share) resulting from refunds of previously paid
federal income taxes related to the tax retirement of TMI-2. Lower operation
and maintenance (O&M) expense, which included payroll and benefits savings
from the early retirement programs in 1994, also contributed to the nine month
earnings increase.
OPERATING REVENUES:
Total revenues for the third quarter of 1995 increased 10.1% to $1.1
billion, as compared to the third quarter of 1994. For the nine months ended
September 30, 1995, revenues increased 2.4% to $2.9 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 Nine Months
Ended Ended
September 30, 1995 September 30, 1995
Kilowatt-hour (KWH) revenues
(excluding energy portion) $ 34.7 $(13.8)
Energy revenues 62.0 89.2
Other revenues 3.7 (7.1)
Increase in revenues $100.4 $ 68.3
Kilowatt-hour revenues
The increase in KWH revenues for the three month period was due primarily
to higher sales from hotter summer temperatures in 1995 and new customer
additions in the residential and commercial sectors. The decrease in KWH
revenues for the nine month period was due to lower residential sales from
milder winter and cooler spring weather in 1995.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect
corresponding changes in the energy cost rates billed to customers and
expensed. Energy revenues increased in both the three and nine month periods
primarily from higher energy cost rates and increased sales to other
utilities.
Other revenues
Generally, changes in other revenues do not affect earnings as they are
offset by corresponding changes in expense, such as taxes other than income
taxes.
OPERATING EXPENSES:
Power purchased and interchanged
Generally, changes in the energy component of power purchased and
interchanged expense do not significantly affect earnings since these cost
increases are substantially recovered through the Subsidiaries' energy
clauses. However, earnings for the three month period benefitted from lower
reserve capacity expense.
Fuel and Deferral of energy costs, net
Generally, changes in fuel expense and deferral of energy costs do not
affect earnings as they are offset by corresponding changes in energy
revenues.
Other operation and maintenance
The increase in other O&M for the three month period was due to a one-
time $14.7 million (pre-tax) charge by Met-Ed and Penelec in 1995 for TMI-2
monitored storage costs deemed not recoverable through Pennsylvania
ratemaking. The decrease in other O&M expense for the nine month period was
primarily attributable to a one-time $127 million (pre-tax) charge in 1994
related to early retirement programs. Also contributing to the nine month O&M
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reduction were payroll and benefits savings from the retirement programs and
lower 1995 winter storm repair costs.
Depreciation and amortization
The increases in depreciation and amortization expense for the three and
nine month periods were due primarily to additions to plant in service and
adjustments for TMI-2 decommissioning.
Taxes, other than income taxes
Generally, changes in taxes other than income taxes do not significantly
affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income/(expense), net
The increase in other income/(expense) for the three month period was
attributable to the reversal by Met-Ed and Penelec of $183.9 million (pre-tax)
of expense resulting from the Pennsylvania Supreme Court decision overturning
a 1994 Pennsylvania Commonwealth Court order, and restoring a March 1993 PaPUC
order that allowed Met-Ed to recover certain future TMI-2 retirement costs
from customers. In addition, $8.2 million (pre-tax) of expense was reversed
for escalations recorded since June 1994 for radiological decommissioning and
nonradiological cost of removal.
The same factors affecting the three month period also affected the nine
month period. In addition, the nine month period increase included write-offs
in 1994 of $183.9 million (pre-tax) for certain future TMI-2 retirement costs
resulting from the Pennsylvania Commonwealth Court order mentioned above, and
$18.6 million (pre-tax) for postretirement benefit costs not believed to be
recoverable in rates. These increases were partially offset by lower interest
income of $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 nine month period decreased primarily from
the recognition in the first quarter of 1994 of interest expense related to
the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $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, Jersey Central Power & Light Company (JCP&L)
issued $125 million, of monthly income preferred securities through special-
purpose finance subsidiaries. Dividends on these securities are payable
monthly.
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LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The GPU System's capital needs for the nine months ended September 30,
1995 consisted of cash construction expenditures of $340 million.
Construction expenditures for the year are forecasted to be $471 million.
Expenditures for securities maturing in 1995 will total $91 million.
Management estimates that approximately two-thirds of the capital needs in
1995 will be satisfied through internally generated funds.
FINANCING:
GPU has regulatory authority to issue up to four million shares of
additional common stock through 1996. GPU expects to use the proceeds from
any sale of additional common stock to reduce GPU short-term debt and make
capital contributions to the GPU System companies, including EI.
The Subsidiaries have regulatory authority to issue and sell first
mortgage bonds (FMBs), which may be issued as secured medium-term notes, and
preferred stock through June 1997 for JCP&L and Penelec, and December 1997 in
the case of Met-Ed. Under existing authorizations, JCP&L, Met-Ed and Penelec
may issue such senior securities in the amount of $225 million, $190 million
and $160 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 through June 1996. The Subsidiaries also have regulatory
authority to incur short-term debt, a portion of which may be through the
issuance of commercial paper.
In the third quarter of 1995, Met-Ed redeemed at maturity $12 million
principal amount of FMBs. Met-Ed also issued $28.5 million principal amount
of FMBs as collateral for a like amount of pollution control revenue refunding
bonds issued by the Northampton County Industrial Development Authority. The
proceeds from the sale of the Authority bonds were used to redeem at maturity
a like amount of the Authority's pollution control bonds issued in 1985.
In October 1995, Penelec issued $70 million principal amount of FMBs, the
proceeds of which will be used to redeem, prior to maturity, $30 million
principal amount of FMBs and reduce outstanding short-term debt.
On November 1, 1995, JCP&L redeemed at maturity $17.4 million principal
amount of FMBs.
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.
COMPETITIVE ENVIRONMENT:
In September 1995, the Federal Energy Regulatory Commission (FERC)
accepted for filing, subject to possible refund, the Subsidiaries' proposed
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open access transmission tariffs. The tariffs were submitted to the FERC in
March 1995, prior to the FERC's issuance of the Notice of Proposed Rulemaking
on open access non-discriminatory transmission services. The FERC has ordered
that hearings be held on a number of aspects of these tariffs, including
whether they are consistent in certain respects with FERC policy on open
access and comparability of service. The tariffs provide for both firm and
interruptible service on a point-to-point basis. Network service, where
requested, will be negotiated on a case by case basis.
In April 1994, the PaPUC initiated an investigation into the role of
competition in Pennsylvania's electric utility industry and solicited comments
on various issues. Met-Ed and Penelec jointly filed responses in November
1994 suggesting, among other things, that the PaPUC provide for the equitable
recovery of stranded investments, enable utilities to offer flexible pricing
to customers with competitive alternatives, and address regulatory
requirements that impose costs unequally on Pennsylvania utilities as compared
with unregulated or out-of-state suppliers. In August 1995, the PaPUC
released a Staff report in which the Staff decided not to recommend retail
wheeling at this time. Evidentiary hearings on this matter are scheduled to
begin in December 1995.
In August 1995, the New Jersey Board of Public Utilities (NJBPU)
initiated Phase II of the Energy Master Plan on industry restructuring. The
NJBPU Phase II Report, which is expected to address such items as retail and
wholesale competition and divestiture of utility assets, is scheduled for
release in March 1996.
NONREGULATED SUBSIDIARIES:
EI is engaged in the development, ownership and operation of generation,
transmission and distribution facilities in the United States and foreign
countries. As of September 30, 1995, GPU's investment in EI totaled
$160 million. Currently, GPU has outstanding guarantee obligations on EI
commitments of $277 million.
In July 1995, EI Power acquired from the Bolivian government, for
approximately $47 million, a 50% ownership interest in Empresa Guaracachi
S.A., a Bolivian electric generating company having an aggregate capacity of
approximately 216 megawatts (MW) of gas-fired and oil-fired generation.
Because EI Power has a financial controlling interest in this investment,
Empresa Guaracachi S.A. is accounted for as a consolidated entity in the
consolidated financial statements.
In October 1995, EI Power, along with its development partners, completed
the financing for the acquisition of a 240 MW gas-fired generating plant in
Barranquilla, Colombia and to begin construction of a new 750 MW gas-fired
plant adjacent to the existing plant. Electricity generated by these plants
will be sold to The Corporacion Electrica de la Costa Atlantica under a 20
year contract. Total project costs, including the acquisition of the existing
plant, are approximately $750 million, of which EI Power's equity contribution
is expected to be approximately $65 million. EI Power has agreed to make
additional equity contributions to the project of up to $58 million under
certain circumstances.
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<PAGE>
In October 1995, Victoria Electric, Inc., a subsidiary of EI Energy,
entered into a Consortium Agreement with The Australian Gas Light Company
(AGL) to acquire Solaris Power Ltd., an electric distribution company in and
around Melbourne, Australia for a total purchase price of approximately $712
million, of which Victoria Electric's 50% share is $356 million. Victoria
Electric and AGL will each have an equity investment in Solaris Power of
approximately $109 million, with the balance of the purchase price to be
provided by borrowings from an Australian bank syndicate (led by the
Commonwealth Bank of Australia). Solaris Power, which provides electric
service to more than 230,000 customers in and around northwestern Melbourne,
was sold by the Government of Victoria through a competitive bid as part of
the government's privatization of the electric industry.
Niagara Mohawk Power Corporation (NIMO) has filed with the New York
Public Service Commission a proposed restructuring plan that it claims may be
needed to avoid seeking reorganization under Chapter XI of the Bankruptcy
Code. Energy Initiatives has ownership interests, with an aggregate book
value of approximately $35 million, in three nonutility generating (NUG)
projects which have long-term purchase power agreements with NIMO. In the
restructuring plan, NIMO has insisted on renegotiating all of its contracts
with NUGs, and has claimed that it has the right to use eminent domain to
condemn NUG facilities, if such negotiations are not successful. There can be
no assurance as to the outcome of this matter.
NIMO has also initiated actions in federal and state court seeking to
invalidate numerous NUG contracts or limit the amount of annual generation
produced by the NUG (and is withholding allegedly "excess" payments made in
respect of "over generation" under these contracts), including the contracts
for two of Energy Initiatives' projects. Energy Initiatives has filed motions
to dismiss these complaints and is vigorously defending these actions. There
can be no assurance as to the outcome of these proceedings.
THE GPU SUPPLY PLAN:
Managing Nonutility Generation
The Subsidiaries are seeking to reduce the above market costs of
nonutility generation agreements, including (1) attempting to convert must-run
agreements to dispatchable agreements; (2) attempting to renegotiate prices of
the agreements; (3) offering contract buy-outs while seeking to recover the
costs through their energy clauses and (4) initiating proceedings before
federal and state administrative agencies, and in the courts, where
appropriate. In addition, the 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
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<PAGE>
NJBPU from reexamining its order approving the rates payable to Freehold
Cogeneration Associates under a long-term power purchase agreement entered
into pursuant to PURPA. On October 5, 1995, the U. S. Supreme Court denied
petitions for review, filed by JCP&L and the Ratepayer Advocate. JCP&L has
also 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
that it requires JCP&L to purchase power at costs that were above JCP&L's
then avoided costs. On October 11, 1995, the FERC denied JCP&L's petition.
JCP&L intends to seek rehearing by the FERC, and may pursue the case in
federal court.
In May 1995, Met-Ed and Penelec filed a petition for enforcement and
declaratory order with the FERC requesting that the FERC effectively
invalidate four contracts with nonutility generators, aggregating 487 MW of
capacity, on the grounds that the PaPUC's implementation of PURPA directing
Met-Ed and Penelec to enter into these agreements was unlawful. Specifically,
Met-Ed and Penelec contended that the PaPUC's procedures imposing contract
prices based on the costs of a "coal proxy" plant violated PURPA and the
FERC's implementing regulations. In June 1995, the FERC denied the petition,
and in September 1995, the FERC denied Met-Ed's and Penelec's petition for
rehearing. Met-Ed and Penelec have not determined whether they will seek
judicial review of the FERC's order. Subsequent to the FERC's decision, Met-
Ed entered into cancellation agreements, as described below, with the
developers of two of these projects aggregating 327 MW.
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. In October 1995, at the
request of the nonutility generator, the NJBPU entered an order dismissing the
petition. 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
had 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 1995, the Appellate Division of the New Jersey Superior Court
reversed NJBPU orders granting the developers of the Crown/Vista project in-
service date extensions for their proposed 200 MW coal-fired facilities. 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 project for three years. In August 1995, the
developers entered into a buy-out agreement under which JCP&L has purchased
and terminated the agreements for $17 million. JCP&L intends to file with the
NJBPU for recovery of the costs through the levelized energy adjustment
clause.
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<PAGE>
In April 1995, Met-Ed filed a petition with the PaPUC requesting that the
PaPUC rescind its 1992 order directing Met-Ed to enter into a long-term power
purchase agreement with the developers of the proposed 100 MW Scranton
facility. In August 1995, the developers agreed to cancel the project and
terminate the power purchase agreement for up to a $30 million payment from
Met-Ed (but not less than $20 million). In September 1995, Met-Ed filed with
the PaPUC for recovery of the costs through energy cost rates (ECR).
In 1992, as required by a PaPUC order, Met-Ed entered into a long-term
power-purchase agreement with the developers of a proposed 227 MW York County
coal-fired cogeneration plant. In September 1995, Met-Ed and the developer
agreed to cancel the proposed project and attempt to restructure the power-
purchase agreement to allow for the development of a natural gas-fired
facility. Under the agreement, Met-Ed will pay the developer up to $30
million to terminate the coal-fired facility, and an additional $5 million if
the agreement cannot be restructured. When the amount to be paid is
finalized, Met-Ed will file a petition with the PaPUC for ECR recovery.
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 ALJ for a recommended decision. In August 1995, however, the
Pennsylvania Supreme Court granted Penelec's petition for review of the
Commonwealth Court's decision. The Commonwealth Court has remanded pricing
issues to the PaPUC, which has now assigned the matter to an ALJ for hearings.
In August 1995, the Subsidiaries entered into a three-year fuel
management agreement with New Jersey Natural Energy Corporation, an affiliate
of New Jersey Natural Gas Company, to manage the Subsidiaries' natural gas
purchases and interstate pipeline capacity. It is intended that the
Subsidiaries' gas-fired facilities, as well as up to approximately 1,100 MW of
nonutility generation capacity, will be pooled and managed under this
agreement, allowing the Subsidiaries to reduce power purchase expenses.
The Subsidiaries have contracts and anticipated commitments with
nonutility generation suppliers under which a total of 1,624 MW of capacity
are currently in service and an additional 438 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 5 - OTHER EVENTS
Management believes that the Oyster Creek nuclear station will
require additional on-site storage capacity, beginning in 1996, in
order to maintain its full core reserve margin, i.e. its ability,
when necessary, to off-load the entire core to conduct certain
maintenance or repairs in order to restore operation of the plant.
In 1994, the Lacey Township Zoning Board of Adjustment issued a
use variance for the on-site storage facility, but Berkeley
Township and another party appealed to the New Jersey Superior
Court to overturn the decision. The Superior Court then remanded
the variance application to the Board of Adjustment for the
limited purpose of permitting the plaintiffs to present expert
testimony. In August 1995, the Board of Adjustment ruled in favor
of JCP&L and reaffirmed its 1994 decision granting JCP&L the use
variance. Construction of the facility is continuing, and is
expected to be completed by early 1996.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(27) Financial Data Schedule
(b) Reports on Form 8-K:
For the month of October 1995, dated October 4, 1995, under
Item 5 (Other Events)
For the month of October 1995, dated October 20, 1995, under
Item 5 (Other Events), as amended by Form 8-K/A No. 1, dated
October 27, 1995
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<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
November 8, 1995 By:
J. G. Graham, Senior Vice President
(Chief Financial Officer)
November 8, 1995 By:
F. A. Donofrio, Vice President
and Comptroller
(Chief Accounting Officer)
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<PAGE>
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<ARTICLE> UT
<CIK> 0000040779
<NAME> GENERAL PUBLIC UTILITIES CORPORATION
<MULTIPLIER> 1,000
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<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
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464,000 <F2>
98,116
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0
<EARNINGS-AVAILABLE-FOR-COMM> 370,755
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<F1> INCLUDES REACQUIRED COMMON STOCK OF $159,732.
<F2> INCLUDES SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
<F2> SECURITIES OF $330,000.
<F3> INCLUDES DIVIDENDS ON SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE
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<PAGE>
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