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 March 31, 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 April 30, 1995, was as follows:
Common stock, par value $2.50 per share: 115,267,032 shares
outstanding.
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General Public Utilities Corporation
Quarterly Report on Form 10-Q
March 31, 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
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
ASSETS
Utility Plant:
In service, at original cost $8 968 580 $8 879 630
Less, accumulated depreciation 3 229 034 3 148 668
Net utility plant in service 5 739 546 5 730 962
Construction work in progress 344 364 340 248
Other, net 186 784 195 388
Net utility plant 6 270 694 6 266 598
Other Property and Investments:
Nuclear decommissioning trusts 284 774 260 482
Nonregulated investments, net 115 255 115 538
Nuclear fuel disposal fund 87 204 82 920
Other, net 33 538 33 553
Total other property and investments 520 771 492 493
Current Assets:
Cash and temporary cash investments 38 095 26 731
Special deposits 8 260 10 226
Accounts receivable:
Customers, net 243 297 248 728
Other 55 779 56 903
Unbilled revenues 98 705 113 581
Materials and supplies, at average cost or less:
Construction and maintenance 194 215 184 644
Fuel 45 661 55 498
Deferred energy costs 7 129 8 728
Deferred income taxes 20 617 18 399
Prepayments 75 765 62 164
Total current assets 787 523 785 602
Deferred Debits and Other Assets:
Regulatory assets:
Three Mile Island Unit 2 deferred costs 153 222 157 042
Unamortized property losses 107 556 108 699
Income taxes recoverable through future rates 567 266 561 498
Other 363 390 370 402
Total regulatory assets 1 191 434 1 197 641
Deferred income taxes 428 979 428 897
Other 53 890 38 546
Total deferred debits and other assets 1 674 303 1 665 084
Total Assets $9 253 291 $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
In Thousands
March 31, December 31,
1995 1994
(Unaudited)
LIABILITIES AND CAPITAL
Capitalization:
Common stock $ 314 458 $ 314 458
Capital surplus 671 515 663 418
Retained earnings 1 853 939 1 775 759
Total 2 839 912 2 753 635
Less, reacquired common stock, at cost 180 087 181 051
Total common stockholders' equity 2 659 825 2 572 584
Cumulative preferred stock:
With mandatory redemption 150 000 150 000
Without mandatory redemption 98 116 98 116
Preferred securities of subsidiaries 205 000 205 000
Long-term debt 2 485 479 2 345 417
Total capitalization 5 598 420 5 371 117
Current Liabilities:
Debt due within one year 91 165 91 165
Notes payable 245 787 347 408
Obligations under capital leases 149 847 157 168
Accounts payable 242 931 317 259
Taxes accrued 144 712 80 027
Interest accrued 52 670 66 628
Other 141 069 213 041
Total current liabilities 1 068 181 1 272 696
Deferred Credits and Other Liabilities:
Deferred income taxes 1 449 963 1 438 743
Unamortized investment tax credits 153 410 156 262
Three Mile Island Unit 2 future costs 344 517 341 139
Regulatory liabilities 114 726 122 144
Other 524 074 507 676
Total deferred credits and other liabilities 2 586 690 2 565 964
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $9 253 291 $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)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Revenues $913 972 $937 209
Operating Expenses:
Fuel 89 227 103 307
Power purchased and interchanged 250 923 234 502
Deferral of energy costs, net 1 148 (24 770)
Other operation and maintenance 219 713 233 111
Depreciation and amortization 89 541 89 813
Taxes, other than income taxes 86 061 90 953
Total operating expenses 736 613 726 916
Operating Income Before Income Taxes 177 359 210 293
Income taxes 43 699 53 697
Operating Income 133 660 156 596
Other Income and Deductions:
Allowance for other funds used during
construction 1 205 646
Other income/(expense), net (800) 57 609
Income taxes 155 (23 299)
Total other income and deductions 560 34 956
Income Before Interest Charges
and Preferred Dividends 134 220 191 552
Interest Charges and Preferred Dividends:
Interest on long-term debt 45 113 46 143
Other interest 6 849 18 509
Allowance for borrowed funds used
during construction (2 107) (1 517)
Dividends on preferred securities of
subsidiaries 4 547 -
Preferred stock dividends of subsidiaries 4 321 5 515
Total interest charges and
preferred dividends 58 723 68 650
Net Income $ 75 497 $122 902
Earnings Per Average Common Share $ .65 $ 1.07
Average Common Shares Outstanding 115 340 115 065
Cash Dividends Paid Per Share $ .45 $ .425
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)
In Thousands
Three Months
Ended March 31,
1995 1994
Operating Activities:
Income before preferred stock dividends
of subsidiaries $ 79 818 $ 128 417
Adjustments to reconcile income to cash provided:
Depreciation and amortization 91 815 90 900
Amortization of property under capital leases 14 154 15 815
Nuclear outage maintenance costs, net 8 187 7 965
Deferred income taxes and investment tax
credits, net (27 975) 25 371
Deferred energy costs, net 1 141 (24 781)
Accretion income (3 130) (3 922)
Allowance for other funds used during construction (1 205) (647)
Changes in working capital:
Receivables 22 117 (92 684)
Materials and supplies 266 2 475
Special deposits and prepayments (17 874) 46 322
Payables and accrued liabilities 1 958 27 400
Other, net 420 (20 103)
Net cash provided by operating activities 169 692 202 528
Investing Activities:
Cash construction expenditures (122 138) (125 764)
Contributions to decommissioning trusts (8 382) (9 030)
Nonregulated investments 756 (105)
Other, net 1 589 (2 162)
Net cash used for investing activities (128 175) (137 061)
Financing Activities:
Issuance of long-term debt 139 115 139 087
Decrease in notes payable, net (101 886) (26 101)
Retirement of long-term debt - (64 000)
Capital lease principal payments (11 218) (14 980)
Dividends paid on common stock (51 843) (48 861)
Dividends paid on preferred stock of subsidiaries (4 321) (5 515)
Net cash required by financing activities (30 153) (20 370)
Net increase in cash and temporary
cash investments from above activities 11 364 45 097
Cash and temporary cash investments,
beginning of year 26 731 25 843
Cash and temporary cash investments, end of period $ 38 095 $ 70 940
Supplemental Disclosure:
Interest paid (net of amount capitalized) $ 71 086 $ 68 113
Income taxes paid $ 28 569 $ 9 067
New capital lease obligations incurred $ 8 207 $ 6 949
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) 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 March 31, 1995 and December
31, 1994, the Subsidiaries' net investment in TMI-1, TMI-2 and Oyster Creek,
including nuclear fuel, was as follows:
Net Investment (Millions)
TMI-1 TMI-2 Oyster Creek
March 31, 1995 $621 $102 $803
December 31, 1994 $627 $103 $817
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
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
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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 not likely to begin before 1996. In February 1994, the Court held
that the plaintiffs' claims for punitive damages are not barred by the Price-
Anderson Act to the extent that the funds to pay punitive damages do not come
out of the U.S. Treasury. The Court also denied the defendants' motion
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
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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
nonradiological structures and materials for TMI-1 and Oyster Creek at
$74 million and $48 million, respectively (in 1994 dollars).
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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. Amounts deposited in external trusts, including the
interest earned on these funds, are classified as Nuclear Decommissioning
Trusts on the balance sheet.
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 $53 million for TMI-1 and $109 million for Oyster Creek at March
31, 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
nonradiological cost of removal consistent with the TMI-1 site-specific study
and have spent $2 million as of March 31, 1995. Estimated TMI-2 Future Costs
as of March 31, 1995 and December 31, 1994 are as follows:
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March 31, 1995 December 31, 1994
(Millions) (Millions)
Radiological Decommissioning $253 $250
Nonradiological Cost of Removal 72 72
Incremental Monitored Storage 19 19
Total $344 $341
The above amounts are reflected as Three Mile Island Unit 2 Future Costs
on the balance sheet. At March 31, 1995, $111 million was in trust funds for
TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and
$51 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. 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 will be 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. Future earnings on trust fund deposits for Met-Ed and Penelec will
be 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.
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.
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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 $68 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.
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 25 years. The majority of
these agreements contain certain contract limitations and subject the
nonutility generators to penalties for nonperformance. While a few of these
facilities are dispatchable, most are must-run and generally obligate the
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Subsidiaries to purchase, at the contract price, the net output up to the
contract limits. As of March 31, 1995, facilities covered by these agreements
having 1,416 MW (JCP&L 882 MW, Met-Ed 239 MW and Penelec 295 MW) of capacity
were in service and 219 MW were scheduled to commence operation 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 1,088 571 280 237
1998 1,304 587 415 302
1999 1,337 607 418 312
These agreements, in the aggregate, will provide approximately 2,583 MW
(JCP&L 1,176 MW, Met-Ed 833 MW and Penelec 574 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, 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
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
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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.
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 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
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Consolidated Balance Sheet. Regulatory assets and liabilities, as reflected
in the March 31, 1995 Consolidated Balance Sheet, were as follows:
(In thousands)
Assets Liabilities
Income taxes recoverable/refundable
through future rates $ 567,266 $104,855
TMI-2 deferred costs 153,222 -
TMI-2 tax refund - 6,463
Unamortized property losses 107,556 -
N.J. unit tax 55,481 -
Unamortized loss on reacquired debt 53,898 -
DOE enrichment facility decommissioning 43,894 -
Load and demand side management programs 43,385 -
Other postretirement benefits 47,711 -
Manufactured gas plant remediation 28,584 -
Nuclear fuel disposal fee 25,398 -
Storm damage 22,953 -
N.J. low level radwaste disposal 18,299 -
Oyster Creek deferred costs 16,108 -
Other 7,679 3,408
Total $1,191,434 $114,726
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.
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.
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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 an NJBPU order dated February 1993, and other DSM program
expenditures that are recovered annually.
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: In 1993, the NJBPU approved a mechanism
for the recovery by JCP&L of future costs when expenditures exceed prior
collections. The NJBPU order provides for interest to be credited to
customers until the overrecovery is eliminated and for future costs to be
amortized over seven years with interest. 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.
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
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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 September
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, if any, additional costs 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. A portion of one of these sites has been
repurchased by JCP&L. JCP&L has also entered into various cost-sharing
agreements with other utilities for some of the sites. As of March 31, 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 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.
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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 provides for interest to be credited to customers until the
overrecovery is eliminated and for future costs to be amortized over seven
years with interest. A final NJBPU order dated December 16, 1994 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
November 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 $98 million for 1995.
Met-Ed entered into an agreement that expires in 1995, and JCP&L
completed contract negotiations with three other utilities to purchase
capacity and energy for various periods through 2004. These agreements,
including contracts under negotiation, 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:
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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's contract negotiations are the result of its all-source
solicitation for short- to intermediate-term energy and capacity.
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. On February 28, 1995, the NJDEP issued an air permit for
the facility based, in part, on the NJBPU's December 21, 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 to the Appellate Division of the New
Jersey Superior Court, and has stated that it also intends to appeal the April
19, 1995 order of the NJBPU denying such group's motion for reconsideration of
the NJBPU's December 21, 1994 order. 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 1993, JCP&L and the other New Jersey electric utilities filed motions for
summary judgment with the NJBPU. Ratepayer Advocate has filed a brief in
opposition to the utilities' summary judgment motions including a statement
from its consultant that in his view, the "double recovery" for JCP&L for the
1988-92 LEAC periods would be approximately $102 million. In 1994, the NJBPU
ruled that the 1991 LEAC period was considered closed but subsequent LEACs
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
approximately $55 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
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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. At the request of the PaPUC, the affected Pennsylvania
electric utilities have supplied to the PaPUC proposals for the establishment
of a nuclear performance standard. The PaPUC has not yet acted on these
proposals.
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 first quarter ended March 31, 1995, was $75.5 million,
or $0.65 per share, compared to $122.9 million, or $1.07 per share, for the
first quarter of 1994. The decrease in first quarter earnings was due
primarily to lower interest income as compared to last year, when the electric
operating subsidiaries recognized nonrecurring net interest income of $26.9
million after-tax ($0.23 per share) which resulted from refunds of previously
paid federal income taxes related to the tax retirement of Three Mile Island
Unit 2 (TMI-2), and lower sales due to warmer winter weather this year as
compared to last year. Also contributing to the earnings decline was higher
reserve capacity expense.
These reductions were partially offset by lower operation and maintenance
expense (O&M) and increased sales from new customer growth.
OPERATING REVENUES:
Total revenues for the first quarter of 1995 decreased 2.5% to $914
million as compared to the first quarter of 1994. The components of the
changes are as follows:
(In Millions)
Kilowatt-hour (KWH) revenues
(excluding energy portion) $(26.1)
Energy revenues 7.8
Other revenues (4.9)
Decrease in revenues $(23.2)
Kilowatt-hour revenues
KWH revenues decreased due primarily to lower residential sales resulting
from warmer winter temperatures this year as compared to last year. New
customer additions in the residential and commercial sectors partially offset
the decrease due to weather.
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 primarily as a result of increased sales
to other utilities and higher energy cost rates, partially offset by lower
sales to customers.
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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 first quarter were negatively impacted by
higher reserve capacity expense resulting primarily from higher payments to
the Pennsylvania-New Jersey-Maryland Interconnection and a one-time
$5.9 million pre-tax charge from another utility.
Other operation and maintenance
The decrease in other O&M expense included payroll and benefits savings
resulting from a workforce reduction in 1994 and lower winter storm repair
costs.
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 decrease in other income was primarily attributable to lower interest
income as compared to last year, when the electric operating subsidiaries
recognized $59.4 million pre-tax of interest income from 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 decreased primarily due to the recognition in the
first quarter of 1994 of interest expense related to the tax retirement of
TMI-2. The tax retirement of TMI-2 resulted in a $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 preferred securities of subsidiaries
During the third quarter of 1994, Met-Ed and Penelec issued $100 million
and $105 million, respectively, 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 first quarter of 1995 consisted of
cash construction expenditures of $122 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 first quarter of 1995, JCP&L, Met-Ed and Penelec issued $50
million, $30 million and $60 million, respectively, of long-term debt. The
proceeds from the Met-Ed and Penelec issuances were used to reduce short-term
debt and the proceeds from the JCP&L issuance will be used to moderate future
short-term debt levels. In the second quarter of 1995, JCP&L repurchased in
the market, 60,000 shares of its 7.52% Series K cumulative preferred stock.
This repurchase, along with the expected issuance of monthly income preferred
securities, is one component of the GPU System's effort to reduce preferred
equity capital costs, while striving to obtain a preferred equity target ratio
of 8%-10% of capitalization. The repurchased shares may be used to satisfy
future sinking fund requirements.
JCP&L is awaiting Securities and Exchange Commission (SEC) authorization
to issue, through a special-purpose finance subsidiary, up to $125 million of
monthly income preferred securities. The securities are expected to be issued
in 1995 and the proceeds used primarily to repay outstanding short-term debt.
GPU has obtained regulatory authorization from the SEC to issue up to
five million shares of additional common stock through 1996. The proceeds
from any sale of such additional common stock are expected to be used to
increase the Subsidiaries' common equity ratios and reduce GPU short-term
debt. GPU will monitor the capital markets as well as its capitalization
ratios relative to its targets to determine whether, and when, to issue such
shares.
The Subsidiaries have regulatory authority to issue and sell first
mortgage bonds, which may be issued as secured medium-term notes, and
preferred stock for various periods through 1995. JCP&L and Penelec are
seeking to extend such authorizations through June 1997. Under existing
authorizations, JCP&L, Met-Ed and Penelec may issue senior securities in the
amount of $225 million, $220 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 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. As a result of the second quarter 1994
write-off of TMI-2 retirement costs, together with certain other costs
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recognized in the same period, Met-Ed and Penelec will be unable to meet the
interest and preferred dividend coverage requirements of their indenture and
charter, respectively, until the third quarter of 1995. Therefore, Met-Ed's
and Penelec's ability to issue senior securities through June 1995 will be
limited to the issuance of first mortgage bonds on the basis of $35 million,
and $8 million respectively, of previously issued and retired bonds. The
ability of Met-Ed and Penelec to issue, through their special-purpose
subsidiaries, their remaining monthly income preferred securities, is not
affected by such coverage restrictions.
GPU is seeking shareholder approval at the annual meeting in May 1995 to
amend its Articles of Incorporation to increase the number of authorized
shares of GPU common stock from 150 million to 350 million, and to eliminate
the remaining preemptive rights of stockholders. GPU believes that these
amendments are necessary to provide flexibility to meet future equity
requirements and to take advantage of future business opportunities.
CAPITALIZATION:
On April 6, 1995, the Board of Directors of the Corporation declared a
quarterly dividend on the common stock of 47 cents per share, an increase of
4.4%. The increased dividend is payable May 31, 1995 to the shareholders of
record April 28, 1995. Management will continue to review its dividend policy
to determine how to best serve the long-term interests of shareholders.
COMPETITIVE ENVIRONMENT:
In March 1995, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking (NOPR) on open access non-discriminatory
transmission services by public utilities and transmitting utilities, and a
supplemental NOPR on recovery of stranded costs superseding an earlier June
1994 NOPR, and other related NOPRs. The new rules, if adopted, would in
essence provide open access to the interstate electric transmission network
and thereby encourage a fully competitive wholesale electric power market.
Among other things, the FERC's proposal would (a) require electric
utilities to file non-discriminatory open access transmission tariffs for both
network and point-to-point service which would be available to all wholesale
sellers and buyers of electricity; (b) require utilities to accept service
under these new tariffs for their own wholesale transactions and (c) permit
utilities to recover their legitimate and verifiable "stranded costs" incurred
when a franchise customer elects to purchase power from another supplier using
the utility's transmission system.
While the proposed rule does not provide for "corporate unbundling",
which the FERC defines as the disposing of ancillary services or creating
separate affiliates to manage transmission services, it does provide for
"functional unbundling". In the NOPR, the FERC describes "functional
unbundling" to mean that (a) the utility must make the same charges for
transmission services to its new wholesale customers as are provided by the
tariff under which it offers these services to others; (b) the tariff must
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include separate rates for transmission and ancillary services; and (c) the
utility is restricted to using the same electronic network as is used by its
customers to obtain system transmission information when engaging in wholesale
transactions, and the utility may not have access to any internal system
transmission data which is not otherwise available to non-affiliated third
parties.
With respect to stranded costs, the FERC proposed to provide recovery
mechanisms where stranded costs result from municipalization or other
instances where former retail customers become wholesale customers, as well as
for wholesale stranded costs. The states would be expected to provide for
recovery of stranded costs attributable to retail wheeling or direct access
programs, and the FERC would intervene only when the state regulatory agency
lacked necessary authority.
Also in March 1995, prior to the FERC's issuance of the NOPR, GPU's
electric operating subsidiaries filed with the FERC proposed open access
transmission tariffs. Such proposed tariffs provide 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. While the
Subsidiaries believe that the proposed transmission tariffs are consistent
with the FERC's previously issued Transmission Pricing Policy Statement, they
do not know whether or to what extent the FERC will require modifications to
any of the proposed terms and conditions of transmission tariffs.
In March 1995, energy rate flexibility legislation was introduced in the
New Jersey Senate. If enacted, the legislation would enable electric
utilities to offer rate discounts to certain customers and allow these
customers access to competitive markets for power. The bill would also allow
utilities to recover 80% of lost revenue as a result of a rate discount if
certain conditions are met. It would also provide utilities the opportunity
to propose to the New Jersey Board of Public Utilities (NJBPU) alternative
ways to set rates.
In April 1995, legislation was introduced in the U.S. Senate that would
repeal Section 210 of the Public Utility Regulatory Policies Act of 1978
(PURPA). Under that section of PURPA, among other things, electric utilities
are required to purchase power from certain qualifying nonutility generators.
In March 1994, GPU announced its intention to form a new subsidiary, GPU
Generation Corporation (GPUGC), to operate, maintain and repair the non-
nuclear generation facilities owned by the Subsidiaries as well as undertake
responsibility to construct any new non-nuclear generation facilities which
the Subsidiaries may need in the future. During 1994, the Subsidiaries
received regulatory approvals from the Pennsylvania Public Utility Commission
(PaPUC) and NJBPU to enter into an operating agreement with GPUGC. In June
1994, however, Allegheny Electric Cooperative (AEC), a wholesale customer of
Penelec, filed a request for evidentiary hearing in the application filed with
the SEC to form GPUGC. The intervention does not challenge the formation of
GPUGC, but purports to be concerned with costs that GPUGC will charge the
Subsidiaries, from which AEC ultimately purchases power. The Subsidiaries
have opposed AEC's request and the matter is pending before the SEC.
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THE GPU SUPPLY PLAN:
New Energy Supplies:
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 to the Appellate Division of New Jersey Superior Court, and has
stated that it also intends to appeal the April 1995 order of the NJBPU
denying such group's motion for reconsideration of the NJBPU's December 1994
order. 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 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 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. JCP&L intends to petition the U.S. Supreme Court to review the Court
of Appeals decision. 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 rulings, the FERC has
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 April 1995, Met-Ed reached a buy-out agreement with the developer of a
13 MW 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. Met-Ed has petitioned the PaPUC for approval to recover from
customers the $1.65 million buy-out cost.
-26-
<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 a proposed 100 MW nonutility
generating facility in the City of Scranton, Pennsylvania. Met-Ed is seeking
relief from that order on the grounds that the project developers no longer
plan to construct the project in the City of Scranton which was a principal
reason for the PaPUC's order. Met-Ed also contends that the rates payable
under the contract, which are not in effect since the PaPUC has not granted
Met-Ed energy cost rate recovery, are $298 million in excess of the projected
costs of alternative power.
In May 1995, Met-Ed and Penelec filed a petition for enforcement and
declaratory order with the FERC requesting that the FERC declare the PaPUC's
PURPA implementation procedures unlawful. Specifically, Met-Ed and Penelec
contend that the PaPUC's procedures that result 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. Met-Ed
and Penelec have requested that the FERC declare void power purchase
agreements and related obligations representing 487 MW of capacity and energy
which the PaPUC has ordered the Companies to enter into under this procedure.
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, where the matter is now pending.
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 filed a motion seeking to dismiss the nonutility generator's
petition.
In May 1994, the NJBPU issued an order granting two nonutility
generators, aggregating 200 MW, a final in-service date extension for projects
originally scheduled to be operational in 1997. In June 1994, JCP&L appealed
the NJBPU's decision to the Appellate Division of the New Jersey Superior
Court. Oral argument on the appeal was held in March 1995 and the matter is
pending before the Appellate Division. The NJBPU order extends the in-service
dates for one year plus the appeal period.
The Subsidiaries have contracts and anticipated commitments with
nonutility generation suppliers under which a total of 1,416 MW of capacity
are currently in service and an additional 1,167 MW are currently scheduled or
anticipated to be in service by 1999.
Conservation and Load Management
In a December 1993 order, the PaPUC adopted guidelines for the recovery
of demand side management (DSM) costs and directed utilities to implement DSM
programs. Met-Ed and Penelec subsequently filed DSM programs that were
-27-
<PAGE>
expected to be approved by the PaPUC in the first quarter of 1995. However,
an industrial intervenor had contested the PaPUC's guidelines and, in January
1995, the Commonwealth Court reversed the PaPUC order. The PaPUC is appealing
that decision to the Pennsylvania Supreme Court. As a result, the nature and
scope of Met-Ed's and Penelec's DSM programs are uncertain at this time.
ACCOUNTING ISSUES:
In March 1995, the Financial Accounting Standards Board (FASB) issued FAS
121, "Accounting for the Impairment of Long-Lived Assets", which is effective
for fiscal years beginning after June 15, 1995. FAS 121 requires that long-
lived assets, identifiable intangibles, capital leases and goodwill be
reviewed for impairment whenever events occur or changes in circumstances
indicate that the carrying amount of the assets may not be recoverable. In
addition, FAS 121 requires that regulatory assets meet the recovery criteria
of FAS 71, "Accounting for the Effects of Certain Types of Regulation", on an
ongoing basis in order to avoid a writedown.
FAS 121 implementation in 1996 is not expected to have an impact on the
GPU System since the carrying amount of all assets, including regulatory
assets, is considered recoverable. However, as the Subsidiaries enter a more
competitive environment, some assets could potentially be subject to
impairment, thereby necessitating writedowns or writeoffs, which could have a
material adverse effect on the GPU System's results of operations and
financial position.
-28-
<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
GPUN 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 March 1994, the Lacey Township Zoning Board of Adjustment
issued a use variance for the on-site storage facility. In May
1994, however, Berkeley Township and another party appealed to the
New Jersey Superior Court to overturn the decision. In April
1995, the Superior Court remanded the variance application to the
Board of Adjustment for the limited purpose of permitting the
plaintiffs to present expert testimony. Construction of the
facility, which is scheduled for completion in September 1995, is
continuing.
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 April 1995, dated April 20, 1995, under Item
5 (Other Events).
-29-
<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
May 4, 1995 By: /s/ J. G. Graham
J. G. Graham, Senior Vice President
(Chief Financial Officer)
May 4, 1995 By: /s/ F. A. Donofrio
F. A. Donofrio, Vice President
and Comptroller
(Chief Accounting Officer)
-30-
<PAGE>
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