Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS.
Jersey Central Power & Light Company (the Company), which was incorporated under the laws of New Jersey in 1925, is a wholly owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935 (the 1935 Act). The Company's business consists predominantly of the generation, transmission, distribution and sale of electricity.
The Company is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to herein as the "Company and its affiliates." The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc. (EI), which develops, owns and operates nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates own all of the common stock of the Saxton Nuclear Experimental Corporation, which owns a small demonstration nuclear reactor that has been partially decommissioned. The Company and its affiliates, GPUSC, GPUN and GPC are referred to as the "GPU System."
As a subsidiary of a registered holding company, the Company is subject to regulation by the Securities and Exchange Commission (SEC) under the 1935 Act. The Company's retail rates, conditions of service, issuance of securities and other matters are subject to regulation by the New Jersey Board of Regulatory Commissioners (NJBRC). The Nuclear Regulatory Commission (NRC) regulates the construction, ownership and operation of nuclear generating stations. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Federal Power Act. (See "Regulation.")
Industry Developments
The Energy Policy Act of 1992 (Energy Act) has made significant changes to the 1935 Act and the Federal Power Act. As a result of this legislation, the FERC is now authorized to order utilities to provide transmission or wheeling service to third parties for wholesale power transactions provided specified reliability and pricing criteria are met. In addition, the legislation amends the 1935 Act to permit the development and ownership of a broad category of independent power production facilities by utilities and nonutilities alike without subjecting them to regulation under the 1935 Act. These and other aspects of the Energy Act are expected to accelerate the changing character of the electric utility industry.
The electric utility industry appears to be undergoing a major transition as it proceeds from a traditional rate regulated environment based on cost recovery to some combination of a competitive marketplace and modified regulation of certain market segments. The industry challenges resulting from various instances of competition, deregulation and restructuring thus far have been minor compared with the impact that is expected in the future. The
Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry of competitors into the electric generation business. Since then, more competition has been introduced through various state actions to encourage cogeneration and, most recently, the Energy Act. The Energy Act is intended to promote competition among utility and nonutility generators in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. This legislation, coupled with increasing customer demands for lower-priced electricity, is generally expected to stimulate even greater competition in both the wholesale and retail electricity markets. These competitive pressures may create opportunities to compete for new customers and revenues, as well as increase risk which could lead to the loss of customers.
Operating in a competitive environment will place added pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than supportable in the marketplace may experience reduced earnings as they attempt to meet their customers' demands for lower- priced electricity. This prospect of increasing competition in the electric utility industry has already led the major credit rating agencies to address and apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the FERC, subject to certain criteria, to order owners of electric transmission systems, such as the Company and its affiliates, to provide third parties with transmission access for wholesale power transactions. The Energy Act did not give the FERC the authority, however, to order retail transmission access. Movement toward opening the transmission network to retail customers is currently under consideration in several states.
The competitive forces have also begun to influence some retail pricing in the industry. In a few instances, industrial customers, threatening to pursue cogeneration, self-generation or relocation to other service territories, have leveraged price concessions from utilities. Recent state regulatory actions, such as in New Jersey, suggest that utilities may have limited success with attempting to shift costs associated with such discounts to other customers. Utilities may have to absorb, in whole or part, the effects of price reductions designed to retain large retail customers. State regulators may put a limit or cap on prices, especially for those customers unable to pursue alternative supply options.
Insofar as the Company is concerned, unrecovered costs will most likely be related to generation investment, purchased power contracts, and "regulatory assets", which are deferred accounting transactions whose value rests on the strength of a state regulatory decision to allow future recovery from ratepayers. In markets where there is excess capacity (as there currently is in the region including New Jersey) and many available sources of power supply, the market price of electricity may be too low to support full recovery of capital costs of certain existing power plants, primarily the capital intensive plants such as nuclear units. Another significant exposure in the transition to a competitive market results if the prices of a utility's existing purchase power contracts, consisting primarily of contractual obligations with nonutility generators, are higher than future market prices. Utilities locked into expensive purchase power arrangements may be forced to value the contracts at market prices and recognize certain losses. A third
source of exposure is regulatory assets which if not supported by regulators would have no value in a competitive market. Financial Accounting Standard No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. If a portion of the Company's operations continues to be regulated, 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. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result. At this time, it is difficult for management to project the future level of stranded assets or other unrecoverable costs, if any, without knowing what the market price of electricity will be, or if regulators will allow recovery of industry transition costs from customers.
Corporate Realignment
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning studies. GPU Generation Corporation (GPU Generation) will be formed to operate and maintain the fossil-fueled and hydroelectric generating units of the Company and its affiliates; ownership of the generating assets will remain with the Company and its affiliates. GPU Generation will also build new generation facilities as needed by the Company and its affiliates in the future. Involvement in the independent power generation market will continue through EI. Additionally, the management and staff of Penelec and Met-Ed will be combined but the two companies will not be merged and will retain their separate corporate existence. This action is intended to increase effectiveness and lower cost. Included in this effort will be a search for parallel opportunities at GPUN and the Company. Completion of these realignment initiatives will be subject to various regulatory reviews and approvals from the SEC, FERC, NJBRC and the Pennsylvania Public Utility Commission (PaPUC). The GPU System is also developing a performance improvement and cost reduction program to help assure ongoing competitiveness, and, among other matters, will also address workforce issues in terms of compensation, size and skill mix. The GPU System is seeking annual cost savings of approximately $80 million by the end of 1996 as a result of these organizational changes.
Duquesne Transaction
In September 1990, the Company and its affiliates entered into a series of interdependent agreements with Duquesne Light Company (Duquesne) for the purchase of a 50% ownership interest in Duquesne's 300 megawatt (MW) Phillips generating station and the joint construction and ownership of associated high voltage bulk transmission facilities. The Company and its affiliates' share of the total cost of these agreements was estimated to be $500 million, of which the Company's share was $215 million, the major part of which was expected to be incurred after 1994. In addition, the Company and Met-Ed simultaneously entered into a related agreement with Duquesne to purchase 350 MW of capacity and energy from Duquesne for 20 years beginning in 1997. The Company and its affiliates and Duquesne filed several petitions with the
PaPUC and the NJBRC seeking certain of the regulatory authorizations required for the transactions.
In December 1993, the NJBRC denied the Company's request to participate in the proposed transactions. As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Company wrote off the approximately $9 million it had invested in the project.
General
The Company is an electric public utility furnishing service entirely within the State of New Jersey. It provides retail service in northern, western and east central New Jersey having an estimated population of approximately 2.4 million.
The electric generating and transmission facilities of the Company, Met-Ed and Penelec are physically interconnected and are operated as a single integrated and coordinated system. The transmission facilities are physically interconnected with neighboring nonaffiliated utilities in Pennsylvania, New Jersey, Maryland, New York and Ohio. The Company and its affiliates are members of the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and the Mid-Atlantic Area Council, an organization providing coordinated review of the planning by utilities in the PJM area. The interconnection facilities are used for substantial capacity and energy interchange and purchased power transactions as well as emergency assistance.
During 1993, residential sales accounted for approximately 44% of the Company's operating revenues from customers and 40% of kilowatt-hour (kWh) sales to customers; commercial sales accounted for approximately 37% of operating revenues from customers and 37% of kWh sales to customers; industrial sales accounted for approximately 17% of operating revenues from customers and 21% of kWh sales to customers; and sales to a rural electric cooperative, municipalities (primarily for street and highway lighting), and others accounted for approximately 2% of operating revenues from customers and 2% of kWh sales to customers. The Company also makes interchange and spot market sales of electricity to other utilities. The revenues derived from the largest single customer accounted for less than 3% of the electric operating revenues for the year and the 25 largest customers, in the aggregate, accounted for approximately 10% of such revenues. Reference is made to "Company Statistics" on page for additional information concerning the Company's sales and revenues.
The Company and its affiliates along with the other members of the PJM power pool, experienced an electric emergency due to extremely cold temperature from January 18 through January 20, 1994. In order to maintain the electric system and to avoid a total black-out, intermittent black-outs for periods typically of one to two hours were instituted on January 19, 1994 to control peak loads. In February 1994, the NJBRC, the PaPUC and the FERC initiated investigations of the energy emergency, and forwarded data requests to all affected utilities. In addition, the United States House of Representatives' Energy and Power Subcommittee, among others, held hearings on this matter. At this time, management is unable to estimate the impact, if any, from any conclusions that may be reached by the regulators.
Competition in the electric utility industry has already played a significant role in wholesale transactions, affecting the pricing of energy sales to electric cooperatives and municipal customers. During 1993, Penelec successfully negotiated power supply agreements with several Company wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of the Company. Wholesale customers represent a relatively small portion of GPU System sales.
Nuclear Facilities
The Company has 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. At December 31, 1993, the Company's net investment in TMI-1 and Oyster Creek, including nuclear fuel, was $173 million and $784 million, respectively. TMI-1 and TMI-2 are jointly owned by the Company, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by the Company.
Costs associated with the operation, maintenance and retirement of nuclear plants have continued to increase and become less predictable, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at their nuclear plants because of the design criteria prevailing 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 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 the plants' useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs described above through the ratemaking process, but recognizes that recovery is not assured.
TMI-1
TMI-1, a 786 MW pressurized water reactor, was licensed by the NRC in 1974 for operation through 2008. The NRC has extended the TMI-1 operating license through April 2014, in recognition of the plant's approximate six-year construction period. During 1993, TMI-1 operated at a capacity factor of approximately 87%. A scheduled refueling outage that year lasted 36 days; the next refueling outage is scheduled for late 1995.
Oyster Creek
The Oyster Creek station, a 610 MW boiling water reactor, received a provisional operating license from the NRC in 1969 and a full-term operating license in 1991. In April 1993, the NRC extended the station's operating license from 2004 to 2009 in recognition of the plant's approximate four-year construction period. The plant operated at a capacity factor of approximately 87% during 1993. A scheduled refueling outage lasted 81 days and the plant returned to service on February 16, 1993. The next refueling outage is scheduled for September 1994.
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 NRC approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates. Approximately 2,100 of such claims are pending in the U. S. 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. Questions have not yet been resolved as to whether the punitive damage claims are (a) subject to the overall limitation of liability set by the Price-Anderson Act ($560 million at the time of the accident) and (b) outside the primary insurance coverage provided pursuant to that Act (remaining primary coverage of approximately $80 million as of December 1993). If punitive damages are not covered by insurance or are not subject to the Price-Anderson liability limitation, punitive damage awards could have a material adverse effect on the financial position of the Company.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of twelve allegedly representative cases is scheduled to begin in October 1994. 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 Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment.
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). See Note 2 to Financial Statements for further information regarding nuclear fuel disposal costs.
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for 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 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1993 dollars) for TMI-1 is $143 million, of which the Company's share is $36 million, and for Oyster Creek is $175 million. Based on NRC studies, a comparable funding
target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 million, of which the Company's share is $57 million. The NRC is currently studying 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 actual 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 $205 to $285 million, of which the Company's share is $51 to $71 million, and $220 to $320 million, respectively (adjusted to 1993 dollars). In addition, the studies estimated the cost of removal of nonradiological structures and materials for TMI-1 and Oyster Creek at $72 million, of which the Company's share is $18 million, and $47 million, respectively.
The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company charges to expense and contributes to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, in 1990 the Company contributed to an external trust an amount not recoverable from customers for nuclear plant decommissioning.
TMI-1 and Oyster Creek
The Company is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. The Company is also collecting revenues for the cost of removal of nonradiological structures and materials at each plant based on its share ($3.83 million) of an estimated $15.3 million for TMI-1 and $31.6 million for Oyster Creek. Collections from customers for decommissioning expenditures are deposited in external trusts. These external trust funds, including the interest earned, are classified as Decommissioning Funds on the balance sheet. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $13 million for TMI-1 and $80 million for Oyster Creek at December 31, 1993.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the ratemaking process.
TMI-2
The Company has recorded a liability, amounting to $57 million as of December 31, 1993, for its share of the radiological decommissioning of TMI- 2, reflecting the NRC funding target (unadjusted for an immaterial decrease in 1993). The Company records escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company has also recorded a liability in the amount of $5 million for its share of incremental costs specifically attributable to monitored storage. Such costs are expected to be incurred between 1994 and 2014, when decommissioning is forecast to begin. In addition, the Company has recorded a liability in the amount of $18 million for its share of the nonradiological cost of removal. The above amounts for retirement costs and monitored storage are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. The Company has made a nonrecoverable contribution of $15 million to an external decommissioning trust.
The NJBRC has granted the Company decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. Management 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, the Company is incurring incremental storage costs currently estimated at $.25 million annually. The Company has deferred the $5 million for its share of the total estimated incremental costs attributable to monitored storage through 2014, the expected retirement date of TMI-1. The Company's share of these costs has been recognized in rates by the NJBRC.
Insurance
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered one site for insurance purposes) 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 to stabilize 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 the stations.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $9.4 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary 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 three reactors, subject to an annual maximum payment of $10 million per incident per reactor. In 1993, GPUN requested an exemption from the NRC to eliminate the secondary protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at their nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years at decreasing levels beginning at weekly amounts of $1.8 million and $2.6 million for Oyster Creek and TMI-1, respectively.
Under its insurance policies applicable to nuclear operations and facilities, the Company is subject to retrospective premium assessments of up to $31 million in any one year, in addition to those payable under the Price-Anderson Act.
Nonutility and Other Power Purchases
The Company has entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must- run and generally obligate the Company to purchase all of the power produced up to the contract limits. The agreements have been approved by the NJBRC and permit the Company to recover energy and demand costs from customers through its energy clause. These agreements provide for the sale of approximately 1,194 MW of capacity and energy to the Company by the mid-to-late 1990s. As of December 31, 1993, facilities covered by these agreements having 661 MW of capacity were in service, and 215 MW were scheduled to commence operation in 1994. Payments made pursuant to these agreements were $292 million for 1993 and are estimated to aggregate $325 million for 1994. The price of the energy and capacity to be purchased under these agreements is determined by the terms of the contracts. The rates payable under a number of these agreements are substantially in excess of current market prices. While the Company has been granted full recovery of these costs from customers by the NJBRC, there can be no assurance that the Company will continue to be able to recover these costs throughout the term of the related contracts. The emerging competitive market has created additional uncertainty regarding the forecasting of the GPU System's energy supply needs which, in turn, has caused the Company and its affiliates to change their supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Company is attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation contracts where opportunities arise. The extent to which the Company may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before the
NJBRC, as well as to litigation, and may result in claims against the Company for substantial damages. There can be no assurance as to the outcome of these matters.
In July 1993, an NJBRC Advisory Council recommended in a report that all New Jersey electric utilities be required to submit integrated resource plans for review and approval by the NJBRC.
The NJBRC has asked all electric utilities in the state to assess the economics of their purchase power contracts with nonutility generators to determine whether there are any candidates for potential buy out or other remedial measures. In response, the Company initially identified a 100 MW project now under development, which it believes is economically undesirable based on current cost projections. In November 1993, the NJBRC directed the Company and the developer to negotiate contract repricing to a level more consistent with the Company's current avoided cost projections or a contract buy out. The parties have been unable to reach agreement and on February 10, 1994 the NJBRC decided to conduct a hearing on the matter. The developer has filed a declaratory judgement action in federal court contesting the NJBRC's jurisdiction in this matter and is seeking to enjoin the NJBRC proceeding. The matter is pending before the District Court and the NJBRC.
In November 1993, the NJBRC granted two nonutility generators, having a total of 200 MW under contract with the Company, a one-year extension in the in-service dates for projects which were originally scheduled to be operational in 1997. The Company is awaiting a final written NJBRC order and may appeal this decision.
Also in November 1993, the Company received approval from the NJBRC to withdraw its request for proposals for the purchase of 150 MW from nonutility generators. In its petition requesting withdrawal, the Company cited, among other reasons, that solicitations for long-term contracts would have limited its ability to compete in a deregulated environment. As a result of the NJBRC's decision, in January 1994, the Company issued an all source solicitation for the short-term supply of energy and/or capacity to determine and evaluate the availability of competitively priced power supply options. The Company is seeking proposals from utility and nonutility generation suppliers for periods of one to eight years in length and capable of delivering electric power beginning in 1996. Although the intention of the solicitation is to procure short-term and medium-term supplies of electric power, the Company is willing to give some consideration to proposals in excess of eight-year terms.
The Company has entered into an arrangement for a peaking generation project. The Company plans to install a gas-fired combustion turbine at its Gilbert Generating station and retire two steam units for an 88 MW net increase in peaking capacity at an expected cost of $50 million. The Company expects to complete the project by 1996.
The Company and its affiliates have entered into agreements with other utilities for the purchase of capacity and energy for various periods through 1999. These agreements provide for up to 2,130 MW in 1994, declining to 1,307 MW in 1995 and 183 MW by 1999. Payments pursuant to these agreements are estimated to aggregate $244 million in 1994. The price of the energy
purchased under these agreements is determined by contracts providing generally for the recovery by the sellers of their costs.
Rate Proceedings
In December 1993, the Company filed a proposal with the NJBRC seeking approval to implement a new rate initiative designed to retain and expand the economic base in New Jersey. Under the proposed contract rate service, large retail customers could enter into contracts for existing electric service at prevailing rates, with limitations on their exposure to future rate increases. With this rate initiative, the Company would have to absorb any differential in price resulting from changes in costs not provided for in the contracts. This matter is pending before the NJBRC.
Proposed legislation has been introduced in New Jersey which is intended to allow the NJBRC, at the request of an electric or gas utility, to adopt a plan of regulation other than traditional ratemaking methods to encourage economic development and job creation. This legislation would allow electric utilities to be more competitive with nonutility generators who are not subject to NJBRC regulation. Combined with other economic development initiatives, this legislation, if enacted, would provide more flexibility in responding to competitive pressures, but may also serve to accelerate the growth of competitive pressures.
The Company's two operating nuclear units are subject to the NJBRC's annual nuclear performance standard. Operation of these units at an aggregate 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 $10 million. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBRC for review. The annual measurement period, which begins in March of each year, coincides with that used for the Levelized Energy Adjustment Clause (LEAC).
The NJBRC 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 New Jersey Public Advocate, Division of Rate Counsel (Rate Counsel), 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 September 1993, the Company and the other New Jersey electric utilities filed motions for summary judgment with the NJBRC requesting that the NJBRC dismiss contentions being made by Rate Counsel that adjustments for alleged "double recovery" in prior periods are warranted. Rate Counsel 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 the Company for the 1988-92 period would be approximately $102 million. Management believes that the position of Rate Counsel is without merit. This matter is pending before the NJBRC.
Construction Program
General
During 1993, the Company had gross plant additions of approximately $203 million attributable principally to improvements and modifications to existing generating stations and additions to the transmission and distribution system. During 1994, the Company contemplates gross plant additions of approximately $275 million. The Company's gross plant additions are expected to total approximately $253 million in 1995. The principal categories of the 1994 anticipated expenditures, which include an allowance for other funds used during construction, are as follows:
(In Millions)
Generation - Nuclear $ 74 Nonnuclear 54 Total Generation 128 Transmission & Distribution 135 Other 12 Total $275
In addition, expenditures for maturing debt are expected to be $60 million and $47 million for 1994 and 1995, respectively. Subject to market conditions, the Company intends to redeem during these periods outstanding senior securities pursuant to optional redemption provisions thereof should it prove economical to do so.
Management estimates that approximately one-half of the Company's total capital needs for 1994 and approximately three-fourths for 1995 will be satisfied through internally generated funds. The Company expects to obtain the remainder of these funds principally through the sale of first mortgage bonds and preferred stock, subject to market conditions. The Company's bond indenture and charter include provisions that limit the amount of long-term debt, preferred stock and short-term debt the Company may issue. The interest and preferred stock dividend coverage ratios of the Company are currently in excess of indenture or charter restrictions. (See "Limitations on Issuing Additional Securities.") Present plans call for the Company to issue long- term debt and preferred stock during the next three years to finance construction activities and, depending on the level of interest rates, refinance outstanding senior securities.
The Company's 1994 construction program includes $19 million in connection with the federal Clean Air Act Amendments of 1990 (Clean Air Act) requirements (see "Environmental Matters - Air"). The 1995 construction program currently includes approximately $16 million for Clean Air Act compliance.
The Company's gross plant additions exclude nuclear fuel requirements provided under capital leases that amounted to $13 million in 1993. When consumed, the currently leased material, which amounted to $86 million at December 31, 1993, is expected to be replaced by additional leased material at
an average rate of approximately $36 million annually. In the event the replacement nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
In response to the increasingly competitive business climate and excess capacity of nearby utilities, the GPU System's supply plan places an emphasis on maintaining flexibility. Supply planning focuses increasingly on short- to intermediate-term commitments, reliance on "spot" markets, and avoidance of long-term firm commitments. The Company is expected to experience an average growth rate in sales to customers (exclusive of the loss of its wholesale customers) through 1998 of about 1.6% annually. The Company also expects to experience peak load growth although at a somewhat lesser rate. Through 1998, the Company's plan consists of the continued utilization of most existing generating facilities, retirement of certain older units, present commitments for power purchases and new power purchases (of short or intermediate term duration), construction of a new facility, and the utilization of capacity of its affiliates. The plan also includes the continued promotion of economical energy conservation and load management programs. Given the future direction of the industry, the Company's present strategy includes minimizing the financial exposure associated with new long-term purchase commitments and the construction of new facilities by including projected market prices in the evaluation of these options. The Company will resist efforts to compel it to add or contract for new capacity at costs that may exceed future market prices. In addition, the Company will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected market prices.
Demand-Side Management
The regulatory environment in New Jersey encourages the development of new conservation and load management programs. This is evidenced by demand- side management (DSM) incentive regulations adopted in New Jersey in 1992. DSM includes utility sponsored activities designed to improve energy efficiency in customer end-use, and includes load management programs (i.e., peak reduction) and conservation programs (i.e., energy and peak reduction).
The NJBRC approved the Company's DSM plan in 1992 reflecting DSM initiatives of 67 MW of summer peak reduction by the end of 1994. Under the approved regulation, qualified Performance Program DSM investments are recovered over a six-year period with a return earned on the unrecovered amounts. Lost revenues will be recovered on an annual basis and the Company can also earn a performance-based incentive for successfully implementing cost effective programs. In addition, the Company will continue to make certain NJBRC mandated Core Program DSM investments which are recovered annually.
Financing Arrangements
The Company expects to have short-term debt outstanding from time to time throughout the year. The peak in short-term debt is expected to occur in the spring, coinciding with normal cash requirements for New Jersey Unit Tax payments.
GPU and the Company and its affiliates have $398 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks that permits total borrowing of $150 million
outstanding at any one time. The credit facilities generally provide for the payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually. Borrowings under these credit facilities generally bear interest based on the prime rate or money market rates. Notes issued under the Credit Agreement, which expires April 1, 1995, are subject to various covenants and acceleration under certain conditions.
In 1993, the Company refinanced higher cost long-term debt in the principal amount of $394 million resulting in an estimated annualized after- tax savings of $4 million. Total long-term debt issued during 1993 amounted to $555 million. In addition, the Company redeemed $50 million of high- dividend rate preferred stock issues.
The Company has regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock through June, 1995. Under existing authorization, the Company may issue senior securities in the amount of $275 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
Under the Company's nuclear fuel lease agreements with nonaffiliated fuel trusts, an aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-I) of nuclear fuel costs may be outstanding at any one time. It is contemplated that when consumed, portions of the currently leased material will be replaced by additional leased material. The Company and its affiliates are responsible for the disposal costs of nuclear fuel leased under these agreements.
Limitations on Issuing Additional Securities
The Company's first mortgage bond indenture and/or charter include provisions that limit the total amount of securities evidencing secured indebtedness and/or unsecured indebtedness that the Company can issue, the more restrictive of which are described below.
The Company's first mortgage bond indenture requires that, for any period of 12 consecutive months out of the 15 calendar months preceeding the issuance of additional bonds, net earnings available for interest shall have been at least twice the interest requirements on bonds to be outstanding immediately after such issuance. Net earnings available for interest generally consist of the excess of gross operating revenues over operating expenses (other than income taxes), plus or minus net nonoperating income or loss with nonoperating income limited to 5% of operating income. Moreover, the Company's first mortgage bond indenture restricts the ratio of the principal amount of first mortgage bonds that can be issued to not more than 60% of bondable value of property additions. In addition, the indenture, in general, permits the Company to issue additional first mortgage bonds against a like principal amount of previously retired bonds.
At December 31, 1993, the net earnings requirement under the Company's mortgage indenture, as described above, would have permitted it to issue
approximately $821 million of first mortgage bonds at an assumed interest rate of 8%. However, the Company had bondable value of property additions and previously retired bonds that would have permitted it to issue an aggregate of only approximately $334 million of additional first mortgage bonds.
Among other restrictions, the Company's charter provides that, without the consent of the holders of two-thirds of the total voting power of the outstanding preferred stock, no additional shares of preferred stock may be issued unless, for any period of 12 consecutive months of the 15 calendar months preceding such issuance, the Company's net after tax earnings available for the payment of interest on indebtedness shall have been at least one and one-half times the aggregate of (a) the annual interest charges on indebtedness and (b) the annual dividend requirements on all shares of preferred stock to be outstanding immediately after such issuance. At December 31, 1993, these earnings restrictions would have permitted the Company to issue approximately $659 million stated value of cumulative preferred stock at an assumed dividend rate of 8%.
The Company's ability to effect bank loans and issue commercial paper is limited by the provisions of its charter concerning the ratio of loans to total capitalization. The Company's charter provides that, without the consent of the holders of a majority of the total voting power of the Company's outstanding preferred stock, unsecured indebtedness having an initial maturity of less than 10 years (or within three years of maturity) cannot exceed 10% of the sum of secured indebtedness, capital stock, including premium thereon, and surplus. At December 31, 1993, these restrictions would have permitted the Company to have approximately $277 million of unsecured indebtedness outstanding.
The Company has obtained authorization from the SEC to incur short-term debt (including indebtedness under the Credit Agreement, bank credit facilities and commercial paper) up to the Company's charter limitation.
Regulation
As a registered holding company, GPU is subject to regulation by the SEC under the 1935 Act. The Company, as a subsidiary of GPU, is also subject to regulation under the 1935 Act with respect to accounting, the issuance of securities, the acquisition and sale of utility assets, securities or any other interest in any business, the entering into, and performance of, service, sales and construction contracts, and certain other matters. The SEC has determined that the electric facilities of the Company and its affiliates constitute a single integrated public utility system under the standards of the 1935 Act. The 1935 Act also limits the extent to which the Company may engage in nonutility businesses. The Company's retail rates, conditions of service, issuance of securities and other matters are subject to regulation by the NJBRC. Moreover, with respect to the transmission of electric energy, accounting, the construction and maintenance of hydroelectric projects and certain other matters, the Company is subject to regulation by the FERC under the Federal Power Act. The NRC regulates the construction, ownership and operation of nuclear generating stations and other related matters. The Company is also subject, in certain respects, to regulation by the PaPUC in connection with its participation in the ownership and operation of certain
facilities located in Pennsylvania. (See "Electric Generation and the Environment - Environmental Matters" for additional regulation to which the Company is or may be subject.)
The rates charged by the Company for electric service are set by regulators under statutory requirements that they be "just and reasonable." As such, they are subject to adjustment, up or down, in the event they vary from that statutory standard. In 1989, the NJBRC issued proposed regulations designed to establish a mechanism to evaluate the earnings of New Jersey utilities to determine whether their rates continue to be just and reasonable. As proposed, the regulations would permit the NJBRC to establish interim rates subject to refund without prior hearing. There has been no activity concerning this matter since the Company filed comments with the NJBRC.
Electric Generation and the Environment
Fuel
Of the portion of its energy requirements supplied by its own generation, the Company utilized fuels in the generation of electric energy during 1993 in approximately the following percentages: Nuclear--72%; Coal--23%; Gas--4%; and Other (primarily Oil)--1%. Approximately 58% of the Company's energy requirements in 1993 was supplied by purchases (including net interchange) from other utilities and nonutility generators. For 1994, the Company estimates that its generation of electric energy will be in the following proportions: Nuclear--64%; Coal--26%; Gas--9%; and Other (primarily Oil)--1%. The anticipated changes in 1994 fuel utilization percentages are principally attributable to the refueling outage scheduled during 1994 for the Oyster Creek nuclear generating station. Approximately 65% of the Company's 1994 energy requirements is expected to be supplied by purchases (including net interchange) from other utilities and nonutility generators.
Fossil: The Company has entered into a long-term contract with a nonaffiliated mining company for the purchase of coal for the Keystone generating station of which the Company owns a one-sixth undivided interest. This contract, which expires in 2004, requires the purchase of minimum amounts of the station's coal requirements. The price of the coal is determined by a formula generally providing for the recovery by the mining company of its costs of production. The Company's share of the cost of coal purchased under this agreement is expected to aggregate $21 million for 1994.
The Company's portion of the station's estimated coal requirements aggregates approximately 15 million tons over the next 20 years, of which five million tons are expected to be supplied by the nonaffiliated mine-mouth coal company under the long-term contract, with the balance supplied by spot purchases or short-term contracts.
At the current time, adequate supplies of fossil fuels are readily available to the Company, but this situation could change rapidly as a result of actions over which it has no control.
Nuclear: Preparation of nuclear fuel for generating station use involves various manufacturing stages for which the Company and its affiliates contract
separately. Stage I involves the mining and milling of uranium ores to produce natural uranium concentrates. Stage II provides for the chemical conversion of the natural uranium concentrates into uranium hexafluoride. Stage III involves the process of enrichment to produce enriched uranium hexafluoride from the natural uranium hexafluoride. Stage IV provides for the fabrication of the enriched uranium hexafluoride into nuclear fuel assemblies for use in the reactor core at the nuclear generating station.
For TMI-1, under normal operating conditions, there is, with minor planned modifications, sufficient on-site storage capacity to accommodate spent nuclear fuel through the end of its licensed life while maintaining the ability to remove the entire reactor core. While Oyster Creek currently has sufficient on-site storage capacity to accommodate, under normal operating conditions, its spent nuclear fuel while maintaining the ability to remove the entire reactor core, additional on-site storage capacity will be required at the Oyster Creek station beginning in 1996 in order to continue operation of the plant. Contract commitments, with an outside vendor, have been made for on-site incremental spent fuel dry storage capacity at Oyster Creek for 1996 and 1998. Currently, public hearings on plans to build an interim spent fuel facility at the plant are underway.
Environmental Matters
The Company is subject to federal and state water quality, air quality, solid waste disposal and employee health and safety legislation and to environmental regulations issued by the U.S. Environmental Protection Agency (EPA), state environmental agencies and other federal agencies. In addition, the Company is subject to licensing of hydroelectric projects by the FERC and of nuclear power projects by the NRC. Such licensing and other actions by federal agencies with respect to projects of the Company are also subject to the National Environmental Policy Act.
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including, but not limited to, acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants, 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. The consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant are unknown. Management believes the costs described above should be recoverable through the ratemaking process, but recognizes that recovery cannot be assured.
Water: The federal Water Pollution Control Act (Clean Water Act) generally requires, with respect to existing steam electric power plants, the application of the best conventional or practicable pollutant control technology available and compliance with state-established water quality standards. With respect to future plants, the Clean Water Act requires the
application of the "best available demonstrated control technology, processes, operating methods or other alternatives" to achieve, where practicable, no discharge of pollutants. Congress may amend the Clean Water Act during 1994.
The EPA has adopted regulations that establish thermal and other limitations for effluents discharged from both existing and new steam electric generating stations. Standards of performance are developed and enforcement of effluent limitations is accomplished through the issuance by the EPA, or states authorized by the EPA, of discharge permits that specify limitations to be applied. Discharge permits, which have been issued for all of the Company's generating stations, where required, have expired. Timely reapplications for such permits have been filed as required by regulations. Until new permits are issued, the currently expired permits remain in effect.
The discharge permit received by the Company for the Oyster Creek station may, among other things, require the installation of a closed-cycle cooling system, such as a cooling tower, to meet New Jersey state water quality-based thermal effluent limitations. Although construction of such a system is not required in order to meet the EPA's regulations setting effluent limitations for the Oyster Creek station (such regulations would accept the use of the once-through cooling system now in operation at this station), a closed-cycle cooling system may be required in order to comply with the water quality standards imposed by the New Jersey Department of Environmental Protection and Energy (NJDEPE) for water quality certification and incorporated in the station's discharge permit. If a cooling tower is required, the capital costs could exceed $150 million. In 1988, the NJDEPE prepared a draft evaluation that assessed the impact of cooling water intake and discharge from Oyster Creek. This evaluation concluded that the thermal impact of water discharge from Oyster Creek operation was small and localized, but that the impact of cooling water intake was inconclusive, requiring further study. In 1993, the NJDEPE advised GPUN that rather than conduct hearings, it will determine water quality standards in the context of renewing the discharge permit. The NJDEPE has indicated that water quality standards (on an interim basis) will be set as requested by GPUN and that physical or operational changes to the intake structure will not be necessary at this time. Final standards will be established based upon results of a study to determine the optimum operational schedule for the dilution pumps.
The NJDEPE has proposed thermal and other conditions for inclusion in the discharge permits for the Company's Gilbert and Sayreville generating stations that, among other things, could require the Company to install cooling towers and/or modify the water intake/discharge systems at these facilities. The Company has objected to these conditions and has requested an adjudicatory hearing with respect thereto. Implementation of these permit conditions has been stayed pending action on the Company's hearing request. The Company has made filings with the NJDEPE that the Company believes demonstrate compliance with state water quality standards at the Gilbert generating station and justify the issuance of a thermal variance at the Sayreville generating station to permit the continued use of the current once-through cooling system. Based on the NJDEPE's review of these demonstrations, substantial
modifications may be required at these stations, which may result in material capital expenditures.
The Company is also subject to environmental and water diversion requirements adopted by the Delaware River Basin Commission and the Susquehanna River Basin Commission as administered by those commissions or the Pennsylvania Department of Environmental Resources (PaDER) and the NJDEPE.
Nuclear: Reference is made to "Nuclear Facilities" for information regarding the TMI-2 accident, its aftermath and the Company's other nuclear facilities.
New Jersey and Pennsylvania have each established, in conjunction with other states, a low level radioactive waste (radwaste) compact for the construction, licensing and operation of low level radwaste disposal facilities to service their respective areas by the year 2000.
New Jersey and Connecticut have established the Northeast Compact. The estimated cost to license and build a low level radwaste disposal facility in New Jersey is approximately $74 million. The Company's expected $29.5 million share of the cost for this facility is to be paid annually over an eight year period ending 1999. In its February 1993 rate order, the NJBRC granted the Company's request to recover these amounts currently from customers. The facility would be available for disposal of low level waste from Oyster Creek.
Similarly, Pennsylvania, Delaware, Maryland and West Virginia have established the Appalachian Compact, which will build a single facility to dispose of low level radwaste in their areas, including low level radwaste from TMI-1. The estimated cost to license and build this facility is approximately $60 million, of which the Company and its affiliates' share is $12 million. These payments are considered advance waste disposal fees and will be recovered during the facility's operation.
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The Company's share of the total liability at December 31, 1993 amounted to $29 million. The Company made its initial payment in 1993. The remaining amount recoverable from ratepayers is $28 million at December 31, 1993.
Air: The Company is subject to certain state environmental regulations of the NJDEPE, the New Jersey Department of Health and the PaDER. The Company is also subject to certain federal environmental regulations of the EPA.
The PaDER, NJDEPE and the EPA have adopted air quality regulations designed to implement Pennsylvania, New Jersey and federal statutes relating to air quality.
Current Pennsylvania environmental regulations prescribe criteria that generally limit the sulfur dioxide content of stack gas emissions from generating stations constructed before 1972 and stations constructed after 1971 but before 1978, to 3.7 pounds and 1.2 pounds per million BTUs of heat input, respectively. On a weighted average basis, the Company and its
affiliates have been able to obtain coal having a sulfur content meeting these criteria. If, and to the extent that, the Company and its affiliates cannot continue to meet such limitations with processed coal, it may be necessary to retrofit operating stations with sulfur removal equipment that may require substantial capital expenditures as well as substantial additional operating costs. Such retrofitting, if it could be accomplished to permit continued reliable operation of the facilities concerned, would take approximately five years.
As a result of the Clean Air Act, which requires substantial reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year 2000, it may be necessary for the Company to install and operate emission control equipment at the Keystone station, in which it has a 16.67% ownership interest. To comply with Title IV of the Clean Air Act, the Company expects to expend up to $145 million by the year 2000 for the installation of scrubbers, low NOx burner technology and various precipitator upgrades, of which approximately $2 million had been spent as of December 31, 1993. The capital costs of this equipment and the increased operating costs are expected to be recoverable through the ratemaking process.
The current strategy for Phase II compliance under the Clean Air Act is to install scrubbers at the Keystone station.
The Company continues to review available options to comply with the Clean Air Act, including those that may result from the development of an emission allowance trading market. The Company's compliance strategy, especially with respect to Phase II, could change as a result of further review, discussions with co-owners of jointly owned stations and changes in federal and state regulatory requirements.
The ultimate impact of Title I of the Clean Air Act, which deals with the attainment of ambient air quality standards, is highly uncertain. In particular, this Title has established an ozone transport or emission control region that includes 11 northeast states. Pennsylvania and New Jersey are part of this transport region, and will be required to control NOx emissions to a level that will provide for the attainment of the ozone standard in the northeast. As an initial step, major sources of NOx will be required to implement Reasonably Available Control Technology (RACT) by May 31, 1995. This will affect the Company and its affiliates' steam generating stations. PaDER's RACT regulations have been approved by the Environmental Quality Board and became effective in January 1994. Large coal-fired combustion units are required to comply with a presumptive RACT emission limitation (technology) or may elect to use a case-by-case analysis to establish RACT requirements. NJDEPE's RACT regulations became effective in December 1993. These regulations establish maximum allowable emission rates for utility boilers based on fuel used and boiler type, and on combustion turbines based on fuel used. Existing units are eligible for emissions averaging upon approval of an averaging plan by the NJDEPE.
The ultimate impact of Title III of the Clean Air Act, which deals with emissions of hazardous air pollutants, is also highly uncertain. Specifically, the EPA has not completed a Clean Air Act study to determine
whether it is appropriate to regulate emissions of hazardous air pollutants from electric utility steam generating units.
Both the EPA and PaDER are questioning the attainment of National Ambient Air Quality Standards (NAAQS) for sulfur dioxide in the vicinity of the Chestnut Ridge Energy Complex, which includes the Keystone generating station. The EPA and the PaDER have approved the use of a nonguideline air quality model. This model is more representative and less conservative than the EPA guideline model and will be used in the development of a compliance strategy for all generating stations in the Chestnut Ridge Energy Complex. Significant sulfur dioxide reductions may be required at the Keystone generating station, which could result in material capital and additional operating expenditures.
Certain other environmental regulations limit the amount of particulate matter emitted into the environment. The Company and its affiliates have installed equipment at their coal-fired generating stations and may find it necessary to either upgrade or install additional equipment at certain of their stations to consistently meet particulate emission requirements.
In the fall of 1993, the Clinton Administration announced its climate change action plan that intends to reduce greenhouse gas emissions to 1990 levels by the year 2000. The climate action plan relies heavily on voluntary action by industry. The Company and its affiliates have notified the DOE that they support the voluntary approach proposed by the President and expressed their intent to work with the DOE.
Title IV of the Clean Air Act requires Phase I and Phase II affected units to install a continuous emission monitoring system and quality assure the data for sulfur dioxide, NOx, opacity and volumetric flow. In addition, Title VIII requires all affected sources to monitor carbon dioxide emissions.
The Clean Air Act has also expanded the enforcement options available to the EPA and the states and contains more stringent enforcement provisions and penalties. Moreover, citizen suits can seek civil penalties for violations of this Act.
In 1988, the Environmental Defense Fund (EDF), the New Jersey Conservation Foundation, the Sierra Club and Pennsylvanians for Acid Rain Control requested that the NJDEPE and the NJBRC seek to reduce sulfur deposition in New Jersey, either by reducing emissions from both in-state and out-of-state sources, or by requiring that certain electricity imported into New Jersey be generated from facilities meeting minimum emission standards. The Company purchases a substantial portion of its net system requirements from out-of-state coal-fired facilities, including the 1,700 MW Keystone station in Pennsylvania. Hearings on the EDF petition were held during 1989 and 1990, and the matter is pending before the NJDEPE and the NJBRC.
NJDEPE regulations establish the maximum sulfur content of oil, which may not exceed .3% for most of the Company's generating stations and 1% for the balance.
In 1993, the Company made capital expenditures of approximately $2 million in response to environmental considerations and has included
approximately $11 million for this purpose in its 1994 construction program. The operating and maintenance costs, including the incremental costs of low-sulfur fuel, for such equipment were approximately $42 million in 1993 and are expected to be approximately $44 million in 1994.
Electromagnetic Fields: There have been a number of scientific studies regarding the possibility of adverse health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. While some of the studies have indicated some association between exposure to EMF and cancer, other studies have indicated no such association. The studies have not shown any causal relationship between exposure to EMF and cancer, or any other adverse health effects. In 1990, the EPA issued a draft report that identifies EMF as a possible carcinogen, although it acknowledges that there is still scientific uncertainty surrounding these fields and their possible link to adverse health effects. On the other hand, a 1992 White House Office of Science and Technology policy report states that "there is no convincing evidence in the published literature to support the contention that exposures to extremely low frequency electric and magnetic fields generated by sources such as household appliances, video display terminals, and local power lines are demonstrable health hazards." Additional studies, which may foster a better understanding of the subject, are currently under way.
Certain parties have alleged that exposure to EMF associated with the operation of the Company's transmission and distribution facilities will produce adverse impacts upon public health and safety, and upon property values. Furthermore, regulatory actions under consideration by the NJDEPE and bills introduced in the Pennsylvania legislature could, if enacted, establish a framework under which the intensity of EMF produced by electric transmission and distribution lines would be limited or otherwise regulated.
The Company cannot determine at this time what effect, if any, this matter will have on it.
Hazardous/Toxic Wastes: Under the Toxic Substances Control Act (TSCA), the EPA has adopted certain regulations governing the use, storage, testing, inspection and disposal of electrical equipment that contains polychlorinated biphenyls (PCBs). Such regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs. The Company has met all requirements of the TSCA necessary to allow the continued use of equipment containing PCBs, and has taken substantive voluntary actions to reduce the amount of PCB containing electrical equipment.
Prior to 1953, the Company owned and operated manufactured gas plants in New Jersey. Wastes associated with the operation and dismantlement of these gas manufacturing plants were disposed of both on-site and off-site. Claims may be asserted against the Company for the cost of investigation and remediation of these waste disposal sites. The amount of such remediation costs and penalties may be significant and may not be covered by insurance. The Company has identified 17 such sites to date. The Company has entered into cost-sharing agreements with New Jersey Natural Gas Company and Elizabethtown Gas Company under which the Company is responsible for 60% of all costs incurred in connection with the remediation of 12 of these sites.
The Company has entered into Administrative Consent Orders (ACOs) with the NJDEPE for seven of these sites and has entered into Memorandum of Agreements (MOAs) with the NJDEPE for eight of these sites. The Company anticipates entering into MOAs for the remaining sites. The ACOs specify the agreed upon obligations of both the Company and the NJDEPE for remediation of the sites. The MOAs afford the Company greater flexibility in the schedule for investigation and remediation of sites. The Company is seeking NJDEPE approval of its plans for the remediation of these sites. The NJDEPE has approved the Company's implementation program for five of these sites.
At December 31, 1993, the Company has an estimated environmental liability of $35 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, the Company 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: the Company 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 the Company is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In June 1993, the NJBRC approved a mechanism for the recovery of future manufactured gas plant remediation costs through the Company's LEAC when expenditures exceed prior collections. The NJBRC 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. At December 31, 1993, the Company has collected from customers $5.2 million in excess of expenditures of $12.8 million. The Company is currently awaiting a final NJBRC order. The Company is pursuing reimbursement of the above costs from its insurance carriers, and will seek to recover costs to the extent not covered by insurance through this mechanism.
The federal Resource Conservation and Recovery Act of 1976, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the Superfund Amendment and Reauthorization Act of 1986 authorize the EPA to issue an order compelling responsible parties to take cleanup action at any location that is determined to present an imminent and substantial danger to the public or to the environment because of an actual or threatened release of one or more hazardous substances. New Jersey has enacted legislation giving similar authority to the NJDEPE. Because of the nature of the Company's business, various by-products and substances are produced and/or handled that are classified as hazardous under one or more of these statutes. The Company generally provides for the treatment, disposal or recycling of such substances through licensed independent contractors, but these statutory provisions also impose potential responsibility for certain cleanup costs on the generators of the wastes. The Company has been notified by the EPA and a state environmental authority that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at six
hazardous and/or toxic waste sites (including the one described below). In addition, the Company has been requested to supply information to the EPA and state environmental authorities on several other sites for which it has not as yet been named as a PRP.
The Company received notification in 1986 from the EPA that it is among the more than 800 PRPs under CERCLA who may be liable to pay for the cost associated with the investigation and remediation of the Maxey Flats disposal site, located in Fleming County, Kentucky. The Company is alleged to have contributed approximately 1.55% of the total volume of waste shipped to the Maxey Flats site. On September 30, 1991, the EPA issued a Record of Decision (ROD) advising that a remedial alternative had been selected. The PRPs estimate the cost of the remedial alternative selected and associated activities identified in the ROD at more than $60 million, for which all responsible parties would be jointly and severally liable. The Company has provided for its proportionate share of this cost in its financial statements.
The ultimate cost of remediation of these sites will depend upon changing circumstances as site investigations continue, including (a) the technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Company.
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Management believes the costs described above should be recoverable through the ratemaking process.
Franchises
The Company operates pursuant to franchises in the territory served by it and has the right to occupy and use the public streets and ways of the State with its poles, wires and equipment upon obtaining the consent in writing of the owners of the soil, and also to occupy the public streets and ways underground with its conduits, cables and equipment, where necessary, for its electric operation. The Company has the requisite legal franchise for the operation of its electric business within the State of New Jersey, including in incorporated cities and towns where designations of new streets, public ways, etc., may be obtained upon application to such municipalities. The Company holds a FERC license expiring in 2013 authorizing it to operate and maintain the Yards Creek pumped storage hydroelectric station in which the Company has a 50% ownership interest.
Employee Relations
At February 28, 1994, the Company had 3,439 full-time employees. The nonsupervisory production and maintenance employees of the Company and certain of the Company's nonsupervisory clerical employees are represented for collective bargaining purposes by local unions of the International Brotherhood of Electrical Workers (IBEW). The Company's three-year contract with the IBEW expires on October 31, 1994.
ITEM 2.



ITEM 2. PROPERTIES.
Generating Stations
At December 31, 1993, the generating stations of the Company had an aggregate effective summer capability of 2,849,000 net kilowatts (kW), as follows: Year of Name and Location of Station Installation Net kW
Nuclear: Oyster Creek, Lacey Twp., NJ 1969 610,000 Three Mile Island Unit No. 1 Dauphin County, PA (a) 1974 196,000 Gas or Oil: Gilbert, Holland Twp., NJ 1930-1949 117,000 Sayreville, Sayreville, NJ (b) 1930-1958 313,000 Other (18 combustion turbines and 1 combined cycle), various locations 1970-1989 868,000 Oil: E. H. Werner, South Amboy, NJ 1953 58,000 Other (4 combustion turbines and 4 diesel units), various locations 1968-1972 214,000 Coal: Keystone, Indiana, PA (c) 1967-1968 283,000 Pumped Storage: Yards Creek, Blairstown, NJ (d) 1965 190,000 Total 2,849,000
(a) Represents the Company's undivided 25% interest in the station. (b) Effective February 1, 1994, 84,000 kW of capability were retired. (c) Represents the Company's undivided 16.67% interest in the station. (d) Represents the Company's undivided 50% interest in the station, which is a net user rather than a net producer of electric energy.
Substantially all of the Company's properties are subject to the lien of its first mortgage bond indenture.
The Company's peak load was 4,564,000 kW, reached on July 9, 1993.
Transmission and Distribution System
At December 31, 1993, the Company owned 299 transmission and distribution substations that had an aggregate installed transformer capacity of 21,810,169 kilovoltamperes (kVA), and 2,572 circuit miles of transmission lines, of which 18 miles were operated at 500 kilovolts (kV), 570 miles at 230 kV, 228 miles at 115 kV and the balance of 1,756 miles at 69 kV and 34.5 kV. The Company's distribution system included 9,707,504 kVA of line transformer capacity, 15,459 pole miles of overhead lines and 6,362 trench miles of underground cables.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS.
Reference is made to "Nuclear Facilities - TMI-2," "Rate Proceedings," and "Environmental Matters" under Item 1 and Note 1 to Financial Statements contained in Item 8 for a description of certain pending legal proceedings involving the Company. See Page for reference to Notes to Financial Statements.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the Company's outstanding common stock is owned by GPU. During 1993, the Company paid $60 million in dividends on its common stock.
In accordance with the Company's mortgage indenture, as supplemented, $1.7 million of the balance of retained earnings at December 31, 1993 is restricted as to the payment of dividends on its common stock.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA.
See page for reference to Selected Financial Data required by this item.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
See page for reference to Management's Discussion and Analysis of Financial Condition and Results of Operations required by this item.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See page for reference to Financial Statements and Quarterly Financial Data (unaudited) required by this item.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Identification of Directors
The current directors of the Company, their ages, positions held and business experience during the past five years are as follows:
Year First Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief Executive Officer 1986 D. Baldassari (b) 44 President 1982 R. C. Arnold (c) 56 Director 1989 J. G. Graham (d) 55 Vice President and Chief Financial Officer 1986 M. P. Morrell (e) 45 Vice President 1993 G. E. Persson (f) 62 Director 1983 P. H. Preis (g) 60 Vice President and Comptroller 1982 S. C. Van Ness (h) 60 Director 1983 S. B. Wiley (i) 64 Director 1982
(a) Mr. Leva became Chairman of the Board and Chief Executive Officer of the Company in 1992. He became Chairman, President and Chief Executive Officer of GPU in 1992. He is also Chairman, President, Chief Executive Officer and a director of GPUSC, Chairman of the Board, Chief Executive Officer and a director of Met-Ed, Penelec and GPC, and Chairman of the Board and a director of GPUN. Prior to assuming his current positions, Mr. Leva served as President of the Company since 1986. He is also a director of Utilities Mutual Insurance Company, the New Jersey Utilities Association, Chemical Bank NJ and Princeton Bank & Trust Company.
(b) Mr. Baldassari became President of the Company and a director of GPUSC and GPUN in February 1992. Prior to assuming his current positions, Mr. Baldassari served as Vice President - Rates and a director of the Company since 1982. He also served as Vice President - Materials and Services of the Company since 1990, and as Treasurer of the Company from October 1979 through December 31, 1989. He is also a director of First Morris Bank and the New Jersey Utilities Association.
(c) Mr. Arnold became Executive Vice President - Power Supply of GPUSC in 1990. He was Senior Vice President - Power Supply of GPUSC from 1987 to 1989. He is also a director of GPUSC, Met-Ed and Penelec.
(d) Mr. Graham became Senior Vice President in 1989 and Chief Financial Officer of GPU in 1987. He is also Executive Vice President, Chief Financial Officer and a director of GPUSC; Vice President, Chief Financial Officer and a director of Met-Ed and Penelec; Vice President and Chief Financial Officer of GPUN; President and a director of GPC; and a director of EI.
(e) Mr. Morrell was elected Vice President - Materials, Services and Regulatory Affairs of the Company and a director of the Company in 1993. Prior to assuming these positions, Mr. Morrell served as Vice President of GPU since 1989 and Treasurer of GPU since 1987, and had also served as Vice President and Treasurer of the Company, GPUSC, Met-Ed and Penelec and as Treasurer of GPUN and GPC. He is also a director of Utilities Mutual Insurance Company.
(f) Mrs. Persson is owner and President of Business Dynamics Associates of Farmingdale, NJ. Prior to that, she was owner and operator of a family-owned business in Little Silver and Farmingdale, NJ since 1965. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College.
(g) Mr. Preis became a Vice President and a director of the Company in 1982 and Comptroller in 1979.
(h) Mr. Van Ness has been affiliated with the law firm of Pico, Mack, Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since July 1990. Prior to that time, he was affiliated with the law firm of Jamison, McCardell, Moore, Peskin and Spicer of Princeton, NJ since 1983. He also served as Commissioner of the Department of the Public Advocate, State of New Jersey, from 1974 to September 1982. Mr. Van Ness is a director of The Prudential Insurance Company of America.
(i) Mr. Wiley has been a partner in the law firm of Wiley, Malehorn and Sirota of Morristown, NJ since 1973. He is also Chairman of First Morris Bank.
The Company's directors are elected at the annual meeting of stockholder to serve until the next meeting of stockholder and until their respective successors are duly elected and qualified. There are no family relationships among the directors of the Company.
Identification of Executive Officers
The executive officers of the Company, their ages, positions held and business experience during the past five years are as follows:
Year First Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief Executive Officer 1992 D. Baldassari (b) 44 President 1992 C. D. Cudney (c) 55 Vice President 1982 C. R. Fruehling (d) 58 Vice President 1982 J. G. Graham (e) 55 Vice President and Chief Financial Officer 1987 E. J. McCarthy (f) 55 Vice President 1982 M. P. Morrell (g) 45 Vice President 1990 R. W. Muilenburg (h) 60 Vice President 1982 D. W. Myers (i) 49 Vice President and Treasurer 1993 P. H. Preis (j) 60 Vice President and Comptroller 1979 R. J. Toole (k) 51 Vice President 1990 J. J. Westervelt (l) 53 Vice President 1982 R. S. Cohen (m) 51 Secretary and Corporate Counsel 1986
(a) See Note (a) on page 28.
(b) See Note (b) on page 28.
(c) Mr. Cudney has been Vice President of the Company since 1982. Prior to that time, Mr. Cudney served as Manager - Operations of the Company since May 1975.
(d) Mr. Fruehling has been Vice President of the Company since 1982. Prior to that time, Mr. Fruehling served as Director - Transmission & Distribution Engineering of the Company since October 1979.
(e) See Note (d) on page 28.
(f) Mr. McCarthy has been Vice President of the Company since 1982. Prior to that time, Mr. McCarthy served as Manager - Business Offices of the Company since May 1971.
(g) See note (e) on page 29.
(h) Mr. Muilenburg has been Vice President of the Company since 1982. Prior to that time, Mr. Muilenburg served as Manager - Corporate Communications of the Company since June 1976.
(i) Mr. Myers became Vice President and Treasurer of the Company in 1993. He is also Vice President and Treasurer of GPU, GPUSC, Met-Ed, Penelec, GPUN and GPC. Prior to assuming his current positions, Mr. Myers served as Vice President and Comptroller of GPUN since 1986.
(j) See Note (g) on page 29.
(k) Mr. Toole has been Vice President of the Company since 1990. He has also been a Vice President of Met-Ed since 1989. Prior to that he served as Director - Generation Operations of Met-Ed and GPUSC and as Operations and Maintenance Director of TMI-1.
(l) Mr. Westervelt has been Vice President of the Company since 1982. Prior to that time, Mr. Westervelt served as Director - Human Resources of the Company since April 1979.
(m) Mr. Cohen has been Secretary and Corporate Counsel of the Company since 1986.
The Company's executive officers are elected each year at the first meeting of the Board of Directors held following the annual meeting of stockholder. Executive officers hold office until the next meeting of directors following the annual meeting of stockholder and until their respective successors are duly elected and qualified. There are no family relationships among the Company's executive officers.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
Remuneration of Executive Officers
SUMMARY COMPENSATION TABLE
Long-Term Annual Compensation Compensation Other Awards All Name and Annual Restricted Other Principal Compen- Stock/Unit Compen- Position Year Salary Bonus sation(1) Awards(2) sation
J. R. Leva Chairman and Chief Executive Officer (3) (3) (3) (3) (3) (3)
D. Baldassari 1993 $253,750 $57,000 $ - $41,850 $11,192(4) President 1992 211,480 50,000 - 35,100 8,985 1991 117,600 18,500 - 12,190 9,227
M. P. Morrell 1993(5) 144,200 26,000 1,932 15,500 5,768(6) Vice Presi- 1992 137,500 24,900 1,166 14,560 5,267 dent 1991 128,750 21,000 547 12,650 5,150
C. D. Cudney 1993 137,675 24,000 - 14,260 7,573(7) Vice Presi- 1992 132,400 20,900 - 14,300 5,741 dent 1991 125,800 19,000 - 13,340 4,994
P. H. Preis 1993 135,900 22,500 - 14,260 4,881(8) Vice Presi- 1992 130,725 20,600 - 13,780 4,285 dent and 1991 125,825 19,000 - 12,190 3,794 Comptroller
E. J. McCarthy 1993 125,825 22,500 - 13,020 5,033(6) Vice Presi- 1992 121,125 19,100 - 13,000 4,845 dent 1991 116,625 18,000 - 11,270 2,744
(1) "Other Annual Compensation" is composed entirely of the above-market interest accrued on the preretirement portion of deferred compensation.
(2) Number and value of aggregate restricted shares/units at the end of 1993 (dividends are paid or accrued on these restricted shares/units and reinvested):
Aggregate Aggregate Shares/Units Value
D. Baldassari 3,500 $95,114 M. P. Morrell 1,910 $49,348 C. D. Cudney 1,880 $48,316 P. H. Preis 1,810 $46,646 E. J. McCarthy 1,680 $43,264
(3) As noted above, Mr. Leva is Chairman and Chief Executive Officer of the Company and its affiliates, as well as Chairman and Chief Executive Officer of GPU and GPUSC. Mr. Leva is compensated by GPUSC for his overall services on behalf of the GPU System and, accordingly, is not compensated directly by the Company for his services. Information with respect to Mr. Leva's compensation is included on pages 13 to 15 of GPU's 1994 definitive proxy statement, which are incorporated herein by reference.
(4) Consists of the Company's matching contributions under the Savings Plan ($9,427) and the imputed interest on employer-paid premiums for split- dollar life insurance ($1,765).
(5) Mr. Morrell was elected Vice President-Materials, Services and Regulatory Affairs of the Company effective January 15, 1993. Prior to assuming this position, Mr. Morrell served as Vice President and Treasurer of the Company.
(6) Consists of the Company's matching contributions under the Savings Plan.
(7) Consists of the Company's matching contributions under the Savings Plan ($4,847) and above-market interest accrued on the retirement portion of deferred compensation ($2,726).
(8) Consists of the Company's matching contributions under the Savings Plan ($3,805) and above-market interest accrued on the retirement portion of deferred compensation ($1,076).
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Performance Estimated future payouts Number of or other under nonstock price- shares, period until based plans(1) units or maturation Name other rights or payout Target ($ or #)
D. Baldassari 1,350 5 years $29,177
M. P. Morrell 500 5 years 10,806
C. D. Cudney 460 5 years 9,942
P. H. Preis 460 5 years 9,942
E. J. McCarthy 420 5 years 9,077
(1) The 1990 Stock Plan for Employees of General Public Utilities Corporation and Subsidiaries also provides for a Performance Cash Incentive Award in the event that the annualized GPU Total Shareholder Return exceeds the annualized Industry Total Return (Edison Electric Institute's Investor- Owned Electric Utility Index) for the period between the award and vesting dates. These payments are designed to compensate recipients of restricted stock/unit awards for the amount of federal and state income taxes that will be payable upon the restricted stock/units that are vesting for the recipient. The amount is computed by multiplying the applicable gross-up percentage by the amount of gross income the recipient recognizes for federal income tax purposes when the restrictions lapse. The estimated amounts above are computed based on the number of restricted units awarded for 1993 multiplied by the 1993 year-end market value of $30.875. Actual payments would be based on the market value of GPU common stock at the time the restrictions lapse, and may be different from those indicated above.
Proposed Remuneration of Executive Officers
No executive officer of the Company has an employment contract with the Company. The compensation of the Company's executive officers is determined from time to time by the Board of Directors of the Company.
Retirement Plans
The GPU System pension plans provide for pension benefits, payable for life after retirement, based upon years of creditable service with the GPU System and the employee's career average annual compensation as defined below. Under federal law, an employee's pension benefits that may be paid from a qualified trust under a qualified pension plan such as the GPU System plans are subject to certain maximum amounts. The GPU System companies also have adopted nonqualified plans providing that the portion of a participant's pension benefits that, by reason of such limitations or source, cannot be paid from such a qualified trust shall be paid directly on an unfunded basis by the participant's employer.
The following table illustrates the amount of aggregate annual pension from funded and unfunded sources resulting from employer contributions to the qualified trust and direct payments payable upon retirement in 1994 (computed on a single life annuity basis) to persons in specified salary and years of service classifications:
Estimated Annual Retirement Benefits(2)(3)(4) Based Upon Career Average Compensation (1994 Retirement) 15 Years 20 Years 25 Years 30 Years 35 Years 40 Years of Service of Service of Service of Service of Service of Service Career Average Compensation (1) $100,000 $ 29,114 $ 38,819 $ 48,524 $ 58,229 $ 67,934 $ 76,956 150,000 44,114 58,819 73,524 88,229 102,934 116,556 200,000 59,114 78,819 98,524 118,229 137,934 156,156 250,000 74,114 98,819 123,524 148,229 172,934 195,756 300,000 89,114 118,819 148,524 178,229 207,934 235,356 350,000 104,114 138,819 173,524 208,229 242,934 274,956 400,000 119,114 158,819 198,524 238,229 277,934 314,556
(1) Career Average Compensation is the average annual compensation received from January 1, 1984 to retirement and includes Base Salary, Deferred Compensation and Incentive Compensation Plan awards. The Career Average Compensation amounts for the following named executive officers differ by more than 10% from the three- year average annual compensation set forth in the Summary Compensation Table and are as follows: Messrs. Baldassari - $140,376; Morrell - $117,030; Cudney - $117,193; Preis - $124,340; and McCarthy - $115,745. (2) Years of creditable service: Messrs. Baldassari - 24; Morrell - 22; Cudney - 32; Preis - 33; and McCarthy - 33. (3) Based on an assumed retirement at age 65 in 1994. To reduce the above amounts to reflect a retirement benefit assuming a continual annuity to a surviving spouse equal to 50% of the annuity payable at retirement, multiply the above benefits by 90%. The estimated annual benefits are not subject to any reduction for Social Security benefits or other offset amounts. (4) Annual retirement benefit cannot exceed 55% of the average compensation received during the last three years prior to retirement.
Remuneration of Directors
Nonemployee directors receive annual compensation of $13,000, a fee of $1,000 for each Board meeting attended and a fee of $1,000 for each Committee meeting attended. The Company has in effect a deferred remuneration plan pursuant to which outside directors may elect to defer all or a portion of current remuneration.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All of the Company's 15,371,270 outstanding shares of common stock are owned beneficially and of record by the Company's parent, General Public Utilities Corporation, 100 Interpace Parkway, Parsippany, New Jersey 07054.
The following table sets forth, as of February 1, 1994, the beneficial ownership of equity securities of the Company and other GPU System companies of each of the Company's directors and each of the executive officers named in the Summary Compensation Table, and of all directors and officers of the Company as a group. The shares owned by all directors and executive officers as a group constitute less than 1% of the total shares outstanding.
Title of Amount and Nature of Name Security Beneficial Ownership(1)
J. R. Leva GPU Common Stock 3,912 shares - Direct
D. Baldassari GPU Common Stock 945 shares - Direct
R. C. Arnold GPU Common Stock 6,751 shares - Direct
C. D. Cudney GPU Common Stock 1,445 shares - Direct
J. G. Graham GPU Common Stock 6,411 shares - Direct 1,780 shares - Indirect
E. J. McCarthy GPU Common Stock 897 shares - Direct
M. P. Morrell GPU Common Stock 1,003 shares - Direct
G. E. Persson GPU Common Stock None
P. H. Preis GPU Common Stock 1,305 shares - Direct
S. C. Van Ness GPU Common Stock None
S. B. Wiley GPU Common Stock None
All Directors and GPU Common Stock 28,658 shares - Direct Officers as a group 1,780 shares - Indirect
(1) The number of shares owned and the nature of such ownership, not being within the knowledge of the Company, have been furnished by each individual.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) See page for reference to Financial Statement Schedules required by this item.
1. Exhibits:
3-A Restated Certificate of Incorporation of Jersey Central Power & Light Company, as amended to date.
3-B Jersey Central Power & Light Company By-Laws, as amended.
10-A 1990 Stock Plan for Employees of General Public Utilities Corporation and Subsidiaries, incorporated by reference to Exhibit 10-B of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
10-B Form of Restricted Units Agreement under the 1990 Stock Plan, incorporated by reference to Exhibit 10-C of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
10-C Incentive Compensation Plan for Officers of GPU System Companies, incorporated by reference to Exhibit 10-E of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
12 Statements Regarding Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
23 Consent of Independent Accountants.
(b) Reports on Form 8-K:
For the month of December 1993, dated December 10, 1993, under Item 5 (Other Events).
For the month of February 1994, dated February 16 and February 28, 1994, under Item 5 (Other Events).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
JERSEY CENTRAL POWER & LIGHT COMPANY
Dated: March 10, 1994 BY: /s/ D. Baldassari D. Baldassari, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature and Title Date
/s/ J. R. Leva March 10, 1994 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ D. Baldassari March 10, 1994 D. Baldassari, President (Principal Operating Officer) and Director
/s/ R. C. Arnold March 10, 1994 R. C. Arnold, Director
/s/ J. G. Graham March 10, 1994 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ M. P. Morrell March 10, 1994 M. P. Morrell, Vice President and Director
/s/ P. H. Preis March 10, 1994 P. H. Preis, Vice President-Comptroller (Principal Accounting Officer) and Director
/s/ G. E. Persson March 10, 1994 G. E. Persson, Director
/s/ S. C. Van Ness March 10, 1994 S. C. Van Ness, Director
/s/ S. B. Wiley March 10, 1994 S. B. Wiley, Director
JERSEY CENTRAL POWER & LIGHT COMPANY
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Supplementary Data Page
Company Statistics
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quarterly Financial Data
Financial Statements
Report of Independent Accountants
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991
Balance Sheets as of December 31, 1993 and 1992
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Statement of Capital Stock as of December 31, 1993
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
Statement of Long-Term Debt as of December 31, 1993
Notes to Financial Statements
Financial Statement Schedules
Schedule V - Property, Plant and Equipment for the Years 1991-1993
Schedule VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Years 1991-1993
Schedule VIII - Valuation and Qualifying Accounts for the Years 1991-1993
Schedule IX - Short-Term Borrowings for the Years 1991-1993
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Financial Statements or Notes thereto.
Jersey Central Power & Light Company Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
In 1993, earnings available for common stock increased $44.8 million to $141.5 million principally due to additional revenues resulting from a February 1993 retail base rate increase and higher customer sales due primarily to the significantly warmer-than-normal summer temperatures as compared with the mild weather in 1992. Also contributing to the increase in earnings was reduced reserve capacity expense. The increase in earnings was partially offset by increased other operation and maintenance expense, the write-off of approximately $9 million of costs related to the cancellation of proposed energy-related agreements, and higher depreciation expense and financing costs associated with additions to utility plant. Financing costs reflect benefits derived from the early redemption of first mortgage bonds and preferred stock.
Earnings available for common stock decreased $37.3 million to $96.8 million in 1992 principally due to a reduction in customer sales resulting from the mild summer weather in 1992 as compared with 1991 when the Company's service territory experienced significantly warmer-than-normal temperatures. The earnings comparison also reflects the absence in 1992 of a nonrecurring credit with respect to a change in accounting policy resulting in the recognition of unbilled revenues in 1991 of $27.1 million. Also contributing to the decrease in earnings were increased financing costs and depreciation expense associated with additions to utility plant. These decreases in earnings were partially offset by an increase in revenues from new residential and commercial customers, a slight increase in nonweather- related usage and lower reserve capacity expense. Results for 1991 also include the recognition of certain Three Mile Island Unit 2 (TMI-2) costs.
The Company's return on average common equity was 11.1% for 1993 as compared with 8.0% and 11.9% for 1992 and 1991, respectively.
REVENUES:
Total revenues increased 9.1% to $1.9 billion in 1993 after remaining relatively flat at $1.8 billion in 1992. The components of these changes are as follows:
(In Millions) 1993 1992
Kilowatt-hour (KWh) revenues increase (decrease) (excluding energy portion) $ 37.5 $(27.1) Rate increase 108.2 - Energy revenues 13.4 28.6 Other revenues 2.7 (0.6) Increase in revenues $161.8 $ 0.9
Kilowatt-hour revenues
KWh revenues increased in 1993 principally due to higher third quarter sales resulting from the significantly warmer-than-normal summer temperatures as compared with the milder weather during the same period in 1992. An increase in nonweather-related usage in the residential and commercial sectors, and a 1.4% increase in the average number of customers also contributed to the increase in kWh revenues. New customer growth occurred primarily in the residential sector, and was partially offset by a reduction in the number of industrial customers.
In 1992, kWh revenues decreased primarily due to mild weather during the third quarter of 1992 as compared with warmer-than-normal weather during the same period in 1991. This decrease was partially offset by a 1.0% increase in the average number of customers and a slight increase in nonweather-related usage. New customer growth occurred in the residential and commercial categories. The increase in nonweather-related usage was reflected primarily in the residential and commercial sectors.
Rate increase
In February 1993, the New Jersey Board of Regulatory Commissioners (NJBRC) authorized a $123 million increase in retail base rates, or approximately 7% annually.
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 1993 as a result of increased kWh sales to ultimate customers partially offset by decreased sales to other utilities.
In 1992, energy revenues increased as a result of the March 1992 increase in the energy cost rates in effect and a significant increase in kWh sales to other utilities. These increases were partially offset by a decrease in kWh sales in all other customer categories. The increase in 1992 reflects a 24% increase in energy revenues associated with electric 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 as they are substantially recovered through the Company's energy clause. Earnings in 1993, however, were favorably impacted by a reduction in reserve capacity expense resulting from the expiration of a purchase contract with another utility and a reduction in purchases from another utility. Power purchased and interchanged also decreased in 1993 due to a decrease in nonutility generation purchases.
In 1992, power purchased and interchanged increased due to an increase in nonutility generation purchases offset partially by reductions in energy and capacity purchases from other utilities and a decrease in interchange received.
Other operation and maintenance
Other operation and maintenance expense increased in 1993 primarily due to emergency and storm-related activities and higher-than-normal tree trimming expense. Other operation and maintenance expense also increased due to the recognition of current and previously deferred demand side management expenses as directed in the Company's rate orders, an increase in the accrual of nuclear outage maintenance costs and an increase in the amortization of previously deferred nuclear expenses.
The decrease in 1992 is due to the absence of $6.8 million of estimated costs recognized in 1991 for preparing the TMI-2 plant for long-term monitored storage and $2.5 million of previously deferred cleanup costs. Excluding these amounts, other operation and maintenance expense remained relatively stable.
Depreciation and amortization
Depreciation and amortization expense increased in 1993 due to additions to utility plant and the recognition of additional amortization expense for deferred assets as a result of the rate case completed in 1993. The 1992 increase was due to additions to utility plant. These additions consist primarily of additions to existing generating facilities to enhance system reliability and additions to the transmission and distribution system related to new customer growth.
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, net
The reduction in other income, net in 1993 is principally due to the write-off of approximately $9 million of costs related to the cancellation of proposed energy-related agreements between the Company and its affiliates and Duquesne Light Company (Duquesne). The decrease is also due to the absence of carrying charges on certain tax payments made by the Company in 1992, which are now being recovered through rates.
The increase in other income, net in 1992 is mainly attributable to an increase in miscellaneous income related to the anticipated recovery of carrying charges, offset partially by a reduction in interest income resulting from the 1991 collection of federal income tax refunds.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt increased in 1993 and 1992 primarily due to the issuance of additional long-term debt, offset partially by decreases associated with the refinancing of higher cost debt at lower interest rates. Other interest was favorably affected by lower short-term interest rates and a reduction in the average levels of short-term borrowings outstanding in both years. The decrease in other interest in 1992, however, was mainly the result of a lower federal income tax deficiency accrual level as tax deficiency payments relating to the 1983 and 1984 tax years were made in 1991.
Preferred dividends decreased in 1993 primarily due to the redemption of an aggregate $50 million of preferred stock. Preferred dividends increased in 1992 primarily due to the issuance of preferred stock in mid-1992, partially offset by the effect of a redemption in the latter part of 1992.
Liquidity and Capital Resources
CAPITAL NEEDS:
The Company's capital needs were $212 million in 1993, consisting of cash construction expenditures of $197 million and amounts for maturing obligations of $15 million. During 1993, construction funds were primarily used to continue to maintain and improve existing generating facilities and add to the transmission and distribution system. GPU System cash construction expenditures are estimated to be $663 million in 1994, of which the Company's share is $275 million. The expenditures consist mainly of $231 million for ongoing system development and $19 million for clean air requirements. Expenditures for maturing debt are expected to be $60 million for 1994 and $47 million for 1995. In the mid-1990s, construction expenditures may include substantial amounts for clean air requirements, the construction of new generation facilities and other Company needs. Management estimates that approximately one-half of the Company's 1994 capital needs will be satisfied through internally generated funds.
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $250 million ($125 million each for Oyster Creek and Three Mile Island Unit 1) of nuclear fuel costs may be outstanding at any one time. The Company's share of nuclear fuel capital leases at December 31, 1993 totaled $86 million. When consumed, portions of the currently leased material will be replaced by additional leased material at a rate of approximately $36 million annually. In the event this nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
FINANCING:
In 1993, the Company refinanced higher cost long-term debt in the principal amount of $394 million, resulting in an estimated annualized after- tax savings of $4 million. Total long-term debt issued during 1993 amounted to $555 million. In addition, the Company redeemed $50 million of high- dividend preferred stock issues.
The Company has regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock through June 1995. Under existing authorization, the Company may issue senior securities in the amount of $275 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short- term debt, a portion of which may be through the issuance of commercial paper.
The Company's cost of capital and ability to obtain external financing is affected by its security ratings, which continue to remain above minimum investment grade. The Company's first mortgage bonds are currently rated at an equivalent of an A- rating by the three major credit rating agencies, while an equivalent of a BBB+ rating is assigned to the preferred stock issues. In addition, the Company's commercial paper is rated as having good to very good credit quality.
During 1993, Standard & Poor's revised its financial benchmarking standards for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry. These guidelines now include an assessment of a company's business risk. Standard & Poor's new rating structure changed the business outlook for the debt ratings of approximately one-third of the industry, including the Company, which moved from "A-stable" to "A-negative," meaning their credit ratings may be lowered. The Company was classified as "below average" in its business risk position due to the perceived credit risk associated with large purchased power requirements, relatively high rates and a sluggish local economy. Moody's announced that it expects to reduce its average credit ratings for the electric utility industry within the next three years to take into account the effects of the new competitive environment. Duff & Phelps also indicated that it intends to introduce a forecast element to its quantitative analysis to, among other things, "alert investors to the possibility of equity value reduction and credit quality deterioration."
The Company's bond indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short-term debt the Company can issue. The Company's interest and preferred stock coverage ratios are currently in excess of indenture or charter restrictions. The ability to issue securities in the future will depend on coverages at that time. Current plans call for the Company to issue long- term debt and preferred stock during the next three years to finance construction activities and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION:
The Company supports its credit quality rating by maintaining capitalization ratios that permit access to capital markets at a competitive cost. The targets and actual capitalization ratios are as follows:
Capitalization Target Range 1993 1992 1991
Common equity 47-50% 47% 47% 47% Preferred stock 7-10 7 9 9 Notes payable and long-term debt 46-40 46 44 44 100% 100% 100% 100%
Recent evaluations of the industry by credit rating agencies indicate that the Company may have to increase its equity ratio to maintain its current credit ratings.
COMPETITIVE ENVIRONMENT:
The Push Toward Competition
The electric utility industry appears to be undergoing a major transition as it proceeds from a traditional rate regulated environment based on cost recovery to some combination of competitive marketplace and modified regulation of certain market segments. The industry challenges resulting from various instances of competition, deregulation and restructuring thus far have been minor compared with the impact that is expected in the future. The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry of competitors into the electric generation business. Since then, more competition has been introduced through various state actions to encourage cogeneration and, most recently, through the federal Energy Policy Act of 1992 (Energy Act). The Energy Act is intended to promote competition among utility and nonutility generators in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. This legislation, coupled with increasing customer demands for lower-priced electricity, is generally expected to stimulate even greater competition in both the wholesale and retail electricity markets. These competitive pressures may create opportunities to compete for new customers and revenues, as well as increase risk that could lead to the loss of customers.
Operating in a competitive environment will place added pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than supportable in the marketplace may experience reduced earnings as they attempt to meet their customers' demands for lower- priced electricity. This prospect of increasing competition in the electric utility industry has already led the credit rating agencies to address and apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the Federal Energy Regulatory Commission (FERC), subject to certain criteria, to order owners of electric transmission systems, such as the Company and its affiliates, to provide third parties transmission access for wholesale power transactions. The Energy Act did not give the FERC the authority, however, to order retail transmission access. That authority lies with the individual states, and movement toward opening the transmission network to retail customers is currently under consideration in several states.
Recent Events
Competition in the electric utility industry has already played a significant role in wholesale transactions, affecting the pricing of energy sales to electric cooperatives and municipal customers. During 1993, Penelec successfully negotiated power supply agreements with the Company's wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of the Company. The Company will continue its efforts to retain and add customers by offering competitive rates.
The competitive forces have also begun to influence some retail pricing in the industry. In a few instances, industrial customers, threatening to pursue cogeneration, self-generation or relocation to other service territories, have leveraged price concessions from utilities. Recent state regulatory actions, such as in New Jersey, suggest that utilities may have limited success with attempting to shift costs associated with such discounts to other customers. Utilities may have to absorb, in whole or part, the effects of price reductions designed to retain large retail customers. State regulators may put a limit or cap on prices, especially for those customers unable to pursue alternative supply options.
In December 1993, the Company filed a proposal with the NJBRC seeking approval to implement a new rate initiative designed to retain and expand the economic base in New Jersey. Under the proposed contract rate service, large retail customers could enter into contracts for existing electric service at prevailing rates, with limitations on their exposure to future rate increases. With this rate initiative, the Company will have to absorb any differential in price resulting from changes in costs not provided for in the contracts. This matter is pending before the NJBRC.
Proposed legislation has been introduced in New Jersey that is intended to allow the NJBRC, at the request of an electric or gas utility, to adopt a plan of regulation other than traditional ratemaking methods to encourage economic development and job creation. This flexible ratemaking would allow electric utilities to be more competitive with nonutility generators, who are
not subject to NJBRC regulation. Combined with other economic development initiatives, this legislation, if enacted, would provide more flexibility in responding to competitive pressures, but may also serve to accelerate the growth of competitive pressures.
Financial Exposure
In the transition from a regulated to competitive environment, there can be a significant change in the economic value of a utility's assets. Traditional utility regulation provides an opportunity for recovery of the cost of plant assets, along with a return on investment, through ratemaking. In a competitive market, the value of an asset may be determined by the market price of the services derived from that asset. If the cost of operating existing assets results in above-market prices, a utility may be unable to recover all of its costs, resulting in "stranded assets" and other unrecoverable costs. This may result in write-downs to remove stranded assets from a utility's balance sheet in recognition of their reduced economic value and the recognition of other losses.
Unrecovered costs will most likely be related to generation investment, purchased power contracts, and "regulatory assets," which are deferred accounting transactions whose value rests on the strength of a state regulatory decision to allow future recovery from ratepayers. In markets where there is excess capacity (as there currently is in the region including New Jersey) and many available sources of power supply, the market price of electricity may be too low to support full recovery of capital costs of certain existing power plants, primarily the capital intensive plants such as nuclear units. Another significant exposure in the transition to a competitive market results if the prices of a utility's existing purchase power contracts, consisting primarily of contractual obligations with nonutility generators, are higher than future market prices. Utilities locked into expensive purchase power arrangements may be forced to value the contracts at market prices and recognize certain losses. A third source of exposure is regulatory assets, that if not supported by regulators, would have no value in a competitive market. Financial Accounting Standard No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. If a portion of the Company's operations continues to be regulated, FAS 71 accounting may be applied only 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. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result. At this time, it is difficult for management to project the future level of stranded assets or other unrecoverable costs, if any, without knowing what the market price of electricity will be, or if regulators will allow recovery of industry transition costs from customers.
Positioning the GPU System
The typical electric utility today is vertically integrated, operating its plant assets to serve all customers within a franchised service territory. In the future, franchised service territories may be replaced by markets whose boundaries are defined by price, available capacity and transmission access. This may result in changes to the organizational structure of utilities and an emphasis on certain segments of the business among generation, transmission and distribution.
In order to achieve a strong competitive position in a less regulated future, the GPU System has in place a strategic planning process. In the initial phases of the program, task forces are defining the principal challenges facing the GPU System, exploring opportunities and risks, and defining and evaluating strategic alternatives.
Management is now analyzing issues associated with various competitive and regulatory scenarios to determine how best to position the GPU System for a competitive environment. An initial outcome of the GPU System ongoing strategic planning process was a realignment proposed in February 1994, of certain system operations. Subject to necessary regulatory approval, a new subsidiary, GPU Generation Corporation, will be formed to operate and maintain the GPU System's fossil-fueled and hydroelectric generating stations, which are now owned and operated by the Company and its affiliates. It is also intended to combine the remaining Met-Ed and Penelec operations without merging the two companies. The GPU System is also developing a performance improvement and cost reduction program to help assure ongoing competitiveness, and, among other matters, will also address workforce issues in terms of compensation, size and skill mix.
MEETING ENERGY DEMANDS:
In response to the increasingly competitive business climate and excess capacity of nearby utilities, the GPU System's supply plan places an emphasis on maintaining flexibility. Supply planning focuses increasingly on short- term to intermediate-term commitments, reliance on "spot" markets, and avoidance of long-term firm commitments. The Company is expected to experience an average growth rate in sales to customers (exclusive of the loss of its wholesale customers) through 1998 of about 1.6% annually. The Company also expects to experience peak load growth although at a somewhat lesser rate. Through 1998, the Company's plan consists of the continued utilization of existing generating facilities combined with present commitments for power purchases and new power purchases (of short-term or intermediate-term duration), the construction of a new facility, and the utilization of capacity of its affiliates. The plan also includes the continued promotion of economical energy conservation and load management programs. Given the future direction of the industry, the Company's present strategy includes minimizing the financial exposure associated with new long-term purchase commitments and the construction of new facilities by including projected market prices in the evaluation of these options. The Company will resist efforts to compel it to add new capacity at costs that may exceed future market prices. In addition, the Company will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected avoided costs.
New Energy Supplies
The Company's supply plan includes the addition of 533 MW of currently contracted capacity by 1998 from nonutility generation suppliers, and reflects the construction of a new peaking unit. The Company currently has uncommitted capacity needs by 1998 of approximately 500 MW, which represents essentially all the uncommitted needs of the GPU System. These capacity needs may be filled by a combination of utility and nonutility purchases (of short-term or intermediate-term duration) as well as company-owned facilities. Additions are principally to replace expiring purchase arrangements rather than to serve new customer load.
In July 1993, an NJBRC Advisory Council recommended in a report that all New Jersey electric utilities be required to submit integrated resource plans for review and approval by the NJBRC.
The NJBRC has asked all electric utilities in the state to assess the economics of their purchase power contracts with nonutility generators to determine whether there are any candidates for potential buy-out or other remedial measures. The Company identified a 100-MW project now under development, which it believes is economically undesirable based on current cost projections. In November 1993, the NJBRC directed the Company and the developer to negotiate contract repricing to a level more consistent with the Company's current avoided cost projections or a contract buy-out. The developer has filed a federal court action contesting the NJBRC's jurisdiction in this matter.
In November 1993, the NJBRC granted two nonutility generators, having a total of 200 MW under contract with the Company, a one-year extension in the in-service date for projects originally scheduled to be operational in 1997. The Company is awaiting a final written NJBRC order.
Also in November 1993, the Company received approval from the NJBRC to withdraw the Company's request for proposals for the purchase of 150 MW from nonutility generators. In its petition, the Company cited, among other reasons, that solicitations for long-term contracts would have limited its ability to compete in a deregulated environment.
The Company has entered into an arrangement for a peaking generation project whereby it plans to install a gas-fired combustion turbine at its Gilbert Generating station and retire two steam units for an 88-MW net increase in capacity at an expected cost of $50 million. The Company expects to complete the project by 1996.
In December 1993, the NJBRC denied the Company's petition to participate in the proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne. As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. The capital costs of the GPU System's share of these transactions would have totaled approximately $500 million, of which the Company's share would have been $215 million.
In January 1994, the Company issued an all source solicitation for the short-term supply of energy and/or capacity to determine and evaluate the availability of competitively priced power supply options. The Company is seeking proposals from utility and nonutility generation suppliers, for periods of one to eight years in length, that are capable of delivering electric power beginning in 1996. This solicitation is expected to fulfill a significant part of the uncommitted sources identified in the Company's supply plan.
Conservation and Load Management
The regulatory environment in New Jersey encourages the development of new conservation and load management programs. This is evidenced by demand- side management (DSM) incentive regulations adopted in New Jersey in 1992. DSM includes utility-sponsored activities designed to improve energy efficiency in customer end-use, and includes load management programs (i.e., peak reduction) and conservation programs (i.e., energy and peak reduction).
The NJBRC approved the Company's DSM plan in 1992 reflecting DSM initiatives of 67 MW of summer peak reduction by the end of 1994. Under the approved regulation, qualified Performance Program DSM investments are recovered over a six-year period with a return earned on the unrecovered amounts. Lost revenues will be recovered on an annual basis, and the Company can also earn a performance-based incentive for successfully implementing cost-effective programs. In addition, the Company will continue to make certain NJBRC-mandated Core Program DSM investments, which are recovered annually.
ENVIRONMENTAL ISSUES:
The Company is committed to complying with all applicable environmental regulations in a responsible manner. Compliance with the federal Clean Air Act Amendments of 1990 (Clean Air Act) and other environmental needs will present a major challenge to the Company through the late 1990s.
The Clean Air Act will require substantial reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000. The Company's current plan includes installing and operating emission control equipment at the Keystone station in which the Company has a 16.67% ownership interest. To comply with
the Clean Air Act, the Company expects to expend up to $145 million by the year 2000 for air pollution control equipment. The GPU System reviews its plans and alternatives to comply with the Clean Air Act on a least-cost basis taking into account advances in technology and the emission allowance market, and assesses the risk of recovering capital investments in a competitive environment. The GPU System may be able to defer substantial capital investments while attaining the required level of compliance if an alternative such as increased participation in the emission allowance market is determined to result in the least-cost plan. This and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected station are expected to be recoverable through the ratemaking process, but management recognizes that recovery is not assured.
For more information, see the Environmental Matters section of Note 1 to the Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 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 Company and its affiliates and GPU and are still pending. For more information, see Note 1 to the Financial Statements.
EFFECTS OF INFLATION:
The Company is affected by inflation since the regulatory process results in a time lag during which increased operating expenses are not fully recovered in rates. Inflation may have an even greater effect in a period of increasing competition and deregulation as the Company and the utility industry attempt to keep rates competitive.
Inflation also affects the Company in the form of higher replacement costs of utility plant. In the past, the Company anticipated the recovery of these cost increases through the ratemaking process. However, as competition and deregulation accelerate throughout the industry, there can be no assurance of the recovery of these increased costs.
The Company is committed to long-term cost control and is continuing to seek measures to reduce or limit the growth in operating expenses. The prudent expenditure of capital and debt refinancing programs have kept down increases in capital costs and debt levels.
ACCOUNTING ISSUES:
In May 1993, the Financial Accounting Standards Board issued FAS 115, "Accounting for Certain Investments in Debt and Equity Securities," which is effective for fiscal years beginning after December 15, 1993. FAS 115 requires the recording of unrealized gains and losses with a corresponding offsetting entry to earnings or shareholder's equity. The impact on the Company's financial position is expected to be immaterial, and there will be no impact on the results of operations. FAS 115 will be implemented in 1994.
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors Jersey Central Power & Light Company Morristown, New Jersey
We have audited the financial statements and financial statement schedules of Jersey Central Power & Light Company as listed in the index on page of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jersey Central Power & Light Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As more fully discussed in Note 1 to financial statements, the Company is unable to determine the ultimate consequences of the contingency which has resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station. The matter which remains uncertain is the excess, if any, of amounts which might be paid in connection with claims for damages resulting from the accident over available insurance proceeds.
As discussed in Notes 5 and 7 to the financial statements, the Company was required to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993. Also, as discussed in Note 2 to the financial statements, the Company changed its method of accounting for unbilled revenues in 1991.
Parsippany, New Jersey COOPERS & LYBRAND February 2, 1994
Jersey Central Power & Light Company
STATEMENTS OF INCOME
(In Thousands) For the Years Ended December 31, 1993 1992 1991
Operating Revenues $1 935 909 $1 774 071 $1 773 219
Operating Expenses: Fuel 98 683 84 851 100 758 Power purchased and interchanged: Affiliates 23 681 24 281 30 040 Others 578 131 616 418 576 217 Deferral of energy and capacity costs, net 28 726 4 232 (27) Other operation and maintenance 460 128 424 285 433 562 Depreciation and amortization 182 945 167 022 159 747 Taxes, other than income taxes 228 690 215 507 219 611 Total operating expenses 1 600 984 1 536 596 1 519 908
Operating Income Before Income Taxes 334 925 237 475 253 311 Income taxes 77 995 43 621 50 779 Operating Income 256 930 193 854 202 532
Other Income and Deductions: Allowance for other funds used during construction 2 471 4 015 3 136 Other income, net 6 281 21 519 20 664 Income taxes (2 847) (8 268) (8 459) Total other income and deductions 5 905 17 266 15 341
Income Before Interest Charges 262 835 211 120 217 873
Interest Charges: Interest on long-term debt 100 246 92 942 85 420 Other interest 6 530 4 873 11 540 Allowance for borrowed funds used during construction (2 285) (4 056) (5 547) Total interest charges 104 491 93 759 91 413 Income Before Cumulative Effect of Accounting Change 158 344 117 361 126 460 Cumulative effect as of January 1, 1991 of accounting change for unbilled revenues, net of income taxes of $13,942 - - 27 063 Net Income 158 344 117 361 153 523 Preferred stock dividends 16 810 20 604 19 440 Earnings Available for Common Stock $ 141 534 $ 96 757 $ 134 083
The accompanying notes are an integral part of the financial statements.
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands) December 31, 1993 1992 ASSETS Utility Plant: In service, at original cost $3 938 700 $3 692 318 Less, accumulated depreciation 1 380 540 1 262 562 Net utility plant in service 2 558 160 2 429 756 Construction work in progress 102 178 178 902 Other, net 116 751 130 307 Net utility plant 2 777 089 2 738 965
Current Assets: Cash and temporary cash investments 17 301 140 Special deposits 7 124 8 190 Accounts receivable: Customers, net 133 407 117 755 Other 31 912 26 401 Unbilled revenues 57 943 53 588 Materials and supplies, at average cost or less: Construction and maintenance 102 659 101 187 Fuel 11 886 23 576 Deferred income taxes 28 650 57 327 Prepayments 58 057 29 727 Total current assets 448 939 417 891
Deferred Debits and Other Assets: Three Mile Island Unit 2 deferred costs 146 284 153 912 Unamortized property losses 109 478 108 825 Deferred income taxes 110 794 59 599 Income taxes recoverable through future rates 121 509 - Decommissioning funds 139 279 114 650 Special deposits 82 103 76 807 Other 333 680 216 255 Total deferred debits and other assets 1 043 127 730 048
Total Assets $4 269 155 $3 886 904
The accompanying notes are an integral part of the financial statements.
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands) December 31, 1993 1992 LIABILITIES AND CAPITAL Capitalization: Common stock $ 153 713 $ 153 713 Capital surplus 435 715 435 715 Retained earnings 724 194 644 899 Total common stockholder's equity 1 313 622 1 234 327 Cumulative preferred stock: With mandatory redemption 150 000 150 000 Without mandatory redemption 37 741 87 877 Long-term debt 1 215 674 1 116 930 Total capitalization 2 717 037 2 589 134
Current Liabilities: Debt due within one year 60 008 14 485 Notes payable - 5 700 Obligations under capital leases 89 631 107 331 Accounts payable: Affiliates 34 538 54 618 Other 95 509 99 666 Taxes accrued 119 337 127 406 Deferred energy credits 23 633 1 257 Interest accrued 33 804 33 294 Other 50 950 53 967 Total current liabilities 507 410 497 724
Deferred Credits and Other Liabilities: Deferred income taxes 569 966 425 157 Unamortized investment tax credits 79 902 86 021 Three Mile Island Unit 2 future costs 79 967 80 000 Other 314 873 208 868 Total deferred credits and other liabilities 1 044 708 800 046
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 269 155 $3 886 904
The accompanying notes are an integral part of the financial statements.
NOTES TO FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was incorporated under the laws of New Jersey in 1925, is a wholly owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to herein as the "Company and its affiliates." The Company is also associated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc., which develops, owns and operates nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN and GPC are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has 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. At December 31, 1993, the Company's net investment in TMI-1 and Oyster Creek, including nuclear fuel, was $173 million and $784 million, respectively. TMI-1 and TMI-2 are jointly owned by the Company, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by the Company.
Costs associated with the operation, maintenance and retirement of nuclear plants have continued to increase and become less predictable, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at their nuclear plants because of the design criteria prevailing 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 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 the plants' useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs described above through the ratemaking process, but recognizes that recovery is not assured.
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. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates. Approximately 2,100 of such claims are pending in the U. S. 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. Questions have not yet been resolved as to whether the punitive damage claims are (a) subject to the overall limitation of liability set by the Price-Anderson Act ($560 million at the time of the accident) and (b) outside the primary insurance coverage provided pursuant to that Act (remaining primary coverage of approximately $80 million as of December 31, 1993). If punitive damages are not covered by insurance or are not subject to the Price-Anderson liability limitation, punitive damage awards could have a material adverse effect on the financial position of the Company.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of twelve allegedly representative cases is scheduled to begin in October 1994. 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 Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment.
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. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for 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 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1993 dollars) for TMI-1 is $143 million, of which the Company's share is $36 million, and for Oyster Creek is $175 million. Based on NRC studies, a comparable funding target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 million, of which the Company's share is $57 million. The NRC is currently studying 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 actual 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 $205 to $285 million, of which the Company's share is $51 to $71 million, and $220 to $320 million, respectively (adjusted to 1993 dollars). In addition, the studies estimated the cost of removal of nonradiological structures and materials for TMI-1 and Oyster Creek at $72 million, of which the Company's share is $18 million, and $47 million, respectively.
The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company charges to expense and contributes to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, in 1990 the Company contributed to an external trust an amount not recoverable from customers for nuclear plant decommissioning.
TMI-1 and Oyster Creek:
The Company is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. The Company is also collecting revenues for the cost of removal of nonradiological structures and materials at each plant based on its share ($3.83 million) of an estimated $15.3 million for TMI-1 and $31.6 million for Oyster Creek. Collections from customers for decommissioning expenditures are deposited in external trusts and are classified as Decommissioning Funds on the balance sheet, which includes the interest earned on these funds. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $13 million for TMI-1 and $80 million for Oyster Creek at December 31, 1993.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the ratemaking process.
TMI-2:
The Company and its affiliates have recorded a liability, amounting to $229 million, of which the Company's share is $57 million as of December 31,
1993, for the radiological decommissioning of TMI-2, reflecting the NRC funding target (unadjusted for an immaterial decrease in 1993). The Company and its affiliates record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company and its affiliates have also recorded a liability in the amount of $20 million, of which the Company's share is $5 million, for incremental costs specifically attributable to monitored storage. Such costs are expected to be incurred between 1994 and 2014, when decommissioning is forecast to begin. In addition, the Company and its affiliates have recorded a liability in the amount of $71 million, of which the Company's share is $18 million, for nonradiological cost of removal. The Company's share of the above amounts for retirement costs and monitored storage are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. The Company has made a nonrecoverable contribution of $15 million to an external decommissioning trust.
The New Jersey Board of Regulatory Commissioners (NJBRC) has granted the Company decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. Management intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
Upon TMI-2's entering long-term monitored storage, the Company and its affiliates will incur currently estimated incremental annual storage costs of $1 million, of which the Company's share is $.25 million. The Company and its affiliates have deferred the $20 million, of which the Company's share is $5 million, for the total estimated incremental costs attributable to monitored storage. The Company's share of these costs has been recognized in rates by the NJBRC.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered one site for insurance purposes) 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 to stabilize 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 the stations.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $9.4 billion. Coverage for the first $200 million of such liability is provided by private
insurance. The remaining coverage, or secondary protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary 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 three reactors, subject to an annual maximum payment of $10 million per incident per reactor. In 1993, GPUN requested an exemption from the NRC to eliminate the secondary protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at their nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years at decreasing levels beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1, per week.
Under their insurance policies applicable to nuclear operations and facilities, the Company and its affiliates are subject to retrospective premium assessments of up to $52 million in any one year, of which the Company's share is $31 million, in addition to those payable under the Price-Anderson Act.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including, but not limited to, acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the cost of which could be material. Management intends to seek recovery through the ratemaking process for any additional costs, but recognizes that recovery cannot be assured.
To comply with the federal Clean Air Act Amendments of 1990, the Company and its affiliates expect to expend up to $590 million for air pollution control equipment by the year 2000, of which the Company's share is approximately $145 million. Costs associated with the capital invested in this equipment and the increased operating costs of the Company's affected station should be recoverable through the ratemaking process.
The Company has been notified by the Environmental Protection Agency (EPA) and a state environmental authority that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at six hazardous and/or toxic waste sites. In addition, the Company has been requested to supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Company.
The Company has entered into agreements with the New Jersey Department of Environmental Protection and Energy for the investigation and remediation of 17 formerly owned manufactured gas plant sites. One of these sites has been repurchased by the Company. The Company has also entered into various cost sharing agreements with other utilities for some of the sites. At December 31, 1993, the Company has an estimated environmental liability of $35 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, the Company 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 the Company 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 the Company is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In June 1993, the NJBRC approved a mechanism for the recovery of future manufactured gas plant remediation costs through the Company's Levelized Energy Adjustment Clause (LEAC) when expenditures exceed prior collections. The NJBRC 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. At December 31, 1993, the Company has collected from customers $5.2 million in excess of expenditures of $12.8 million. The Company is currently awaiting a final NJBRC order. The Company is pursuing reimbursement of the above costs from its insurance carriers, and will seek to recover costs to the extent not covered by insurance through this mechanism.
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant. Management believes the costs described above should be recoverable through the ratemaking process.
OTHER COMMITMENTS AND CONTINGENCIES
The NJBRC 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 New Jersey Public Advocate, Division of Rate Counsel (Rate Counsel), 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 September 1993, the Company and the other New Jersey electric utilities filed motions for summary judgment with the NJBRC requesting that the NJBRC dismiss contentions being made by Rate Counsel that adjustments for alleged "double recovery" in prior periods are warranted. Rate Counsel 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 the Company for the 1988-92 period would be approximately
$102 million. Management believes that the position of Rate Counsel is without merit. This matter is pending before the NJBRC.
The Company's two operating nuclear units are subject to the NJBRC'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 $10 million. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBRC for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC.
In December 1993, the NJBRC denied the Company's request to participate in the proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne Light Company (Duquesne). As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Company and its affiliates wrote off the $25 million, of which the Company's share was $9 million, they had invested in the project.
The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $275 million during 1994. As a consequence of reliability, licensing, environmental and other requirements, substantial 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 any such costs through the ratemaking process, but recognizes that recovery is not assured.
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71), the Company's financial statements reflect assets and costs based on current cost- based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of certain actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Company has entered into a long-term contract with a nonaffiliated mining company for the purchase of coal for the Keystone generating station of which the Company owns a one-sixth undivided interest. This contract, which expires in 2004, requires the purchase of minimum amounts of the station's coal requirements. The price of the coal is determined by a formula providing for the recovery by the mining company of its costs of production. The Company's share of the cost of coal purchased under this agreement is expected to aggregate $21 million for 1994.
The Company and its affiliates have entered into agreements with other utilities for the purchase of capacity and energy for various periods through 1999. These agreements provide for up to 2130 MW in 1994, declining to 1307 MW by 1995 and 183 MW by 1999. Payments pursuant to these agreements are estimated to aggregate $244 million in 1994. The price of the energy purchased under these agreements is determined by contracts providing generally for the recovery by the sellers of their costs.
The Company has also entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Company to purchase all of the power produced up to the contract limits. The agreements have been approved by the NJBRC and permit the Company to recover energy and demand costs from customers through its energy clause. These agreements provide for the sale of approximately 1,194 MW of capacity and energy to the Company by the mid-to- late 1990s. As of December 31, 1993, facilities covered by these agreements having 661 MW of capacity were in service, and 215 MW were scheduled to commence operation in 1994. Payments made pursuant to these agreements were $292 million, $316 million and $216 million for 1993, 1992 and 1991,
respectively, and are estimated to aggregate $325 million for 1994. The price of the energy and capacity to be purchased under these agreements is determined by the terms of the contracts. The rates payable under a number of these agreements are substantially in excess of current market prices. While the Company has been granted full recovery of these costs from customers by the NJBRC, there can be no assurance that the Company will continue to be able to recover these costs throughout the terms of the related contracts. The emerging competitive market has created additional uncertainty regarding the forecasting of the GPU System's energy supply needs which, in turn, has caused the Company and its affiliates to change their supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Company and its affiliates are attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation contracts where opportunities arise. The extent to which the Company and its affiliates may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before the NJBRC, as well as to litigation, and may result in claims against the Company for substantial damages. There can be no assurance as to the outcome of these matters.
During the normal course of the operation of its business, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by both current and former employees alleging unlawful employment practices. It is not expected that the outcome of these matters will have a material effect on the Company's financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The Company's accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and adopted by the NJBRC. Certain reclassifications of prior years' data have been made to conform with current presentation.
REVENUES
The Company recognizes electric operating revenues for services rendered and, beginning in 1991, an estimate of unbilled revenues to record services provided to the end of the respective accounting period.
DEFERRED ENERGY COSTS
Energy costs are recognized in the period in which the related energy clause revenues are billed.
UTILITY PLANT
It is the policy of the Company to record additions to utility plant (material, labor, overhead and an allowance for funds used during construction) at cost. The cost of current repairs and minor replacements is charged to appropriate operating and maintenance expense and clearing accounts, and the cost of renewals is capitalized. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.
DEPRECIATION
The Company provides for depreciation at annual rates determined and revised periodically, on the basis of studies, to be sufficient to depreciate the original cost of depreciable property over estimated remaining service lives, which are generally longer than those employed for tax purposes. The Company used depreciation rates that, on an aggregate composite basis, resulted in annual rates of 3.59%, 3.51% and 3.51% for the years 1993, 1992 and 1991, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the pretax cost of borrowed funds and to other income for the allowance for other funds. While AFUDC results in an increase in utility plant and represents current earnings, it is realized in cash through depreciation or amortization allowances only when the related plant is recognized in rates. On an aggregate composite basis, the annual rates utilized were 7.80%, 8.19% and 8.64% for the years 1993, 1992 and 1991, respectively.
AMORTIZATION POLICIES
Accounting for TMI-2 and Forked River Investments:
The Company is collecting annual revenues for the amortization of TMI-2 of $9.6 million. This level of revenue will be sufficient to recover the remaining investment by the year 2008. At December 31, 1993, $97 million is included in Unamortized property losses on the balance sheet for the Forked River project. The Company is collecting annual revenues for the amortization of this project of $11.2 million, which will be sufficient to recover its remaining investment by the year 2006. Because the Company has not been provided revenues for a return on the unamortized balances of its share of the damaged TMI-2 facility and the cancelled Forked River project, these
investments are being carried at their discounted present values. The related annual accretion, which represents the carrying charges that are accrued as the asset is written up from its discounted value, is recorded in Other income, net.
Nuclear Fuel:
Nuclear fuel is amortized on a unit of production basis. Rates are determined and periodically revised to amortize the cost over the useful life.
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1993 amounted to $29 million, and is primarily reflected in Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants will contribute a total of $150 million annually, based on an assessment computed on prior enrichment purchases, over a 15-year period up to a total of $2.3 billion (in 1993 dollars). The Company made its initial payment to this fund in 1993. The Company has recorded an asset for remaining amounts recoverable from ratepayers of $28 million at December 31, 1993 in Deferred Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS
The Company accrues incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE
The Company is providing 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. The Company entered into contracts in 1983 with the DOE for the disposal of spent nuclear fuel. The total liability under these contracts, including interest, at December 31, 1993, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $110 million, and is reflected in Deferred Credits and Other Liabilities - Other. As the actual liability is substantially in excess of the amount recovered to date from ratepayers, the Company has reflected such excess of $25 million at December 31, 1993 in Deferred Debits and Other Assets - Other. The rates currently charged to customers provide for the collection of these costs, plus interest, over a remaining period of 13 years.
The Company is collecting 1 mill per kilowatt-hour from its customers for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. These amounts are remitted quarterly to the DOE.
INCOME TAXES
The GPU System files a consolidated federal income tax return, and all participants are jointly and severally liable for the full amount of any tax, including penalties and interest, that may be assessed against the group. Each subsidiary is allocated the tax reduction attributable to GPU expenses, in proportion to the average common stock equity investment of GPU in such subsidiary, during the year. In addition, each subsidiary will receive in current cash payments the benefit of its own net operating loss carrybacks to the extent that the other subsidiaries can utilize such net operating loss carrybacks to offset the tax liability they would otherwise have on a separate return basis (after taking into account any investment tax credits they could utilize on a separate return basis). This method of allocation does not allow any subsidiary to pay more than its separate return liability.
Deferred income taxes, which result primarily from New Jersey unit tax, liberalized depreciation methods, deferred energy costs, discounted Forked River and TMI-2 investments, and unbilled revenues, are provided for differences between book and taxable income. Investment tax credits (ITC) are amortized over the estimated service lives of the related facilities.
Effective January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes," which requires the use of the liability method of financial accounting and reporting for income taxes. Under FAS 109, deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amounts recognized for tax purposes.
STATEMENTS OF CASH FLOWS
For the purpose of the statements of cash flows, temporary investments include all unrestricted liquid assets, such as cash deposits and debt securities, with maturities generally of three months or less.
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1993, the Company had no short-term notes outstanding issued under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $398 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks that permits total borrowing of $150 million outstanding at any one time. The credit facilities generally provide for the payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually. Borrowings under these credit facilities generally bear interest based on the prime rate or money market rates. Notes issued under the Credit Agreement, which expires April 1, 1995, are subject to various covenants and acceleration under certain conditions.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of December 31, 1993 and 1992, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1993: Cumulative preferred stock with mandatory redemption $ 150 $ 161 Long-term debt 1 216 1 276
December 31, 1992: Cumulative preferred stock with mandatory redemption 150 148 Long-term debt 1 117 1 158
The fair values of the Company's cumulative preferred stock with mandatory redemption provisions and long-term debt are estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments of the same remaining maturities.
5. INCOME TAXES
Effective January 1, 1993, the Company implemented FAS 109 "Accounting for Income Taxes". In 1993, the cumulative effect on net income of this accounting change was immaterial. Also in 1993, the federal income tax rate changed from 34% to 35%, retroactive to January 1, 1993, resulting in an increase in the deferred tax assets of $5 million and an increase in the deferred tax liabilities of $20 million. The tax rate change did not have a material effect on net income as the changes in deferred taxes were substantially offset by the recording of regulatory assets and liabilities. The balance sheet effect as of December 31, 1993 of implementing FAS 109 resulted in a regulatory asset for income taxes recoverable through future rates of $122 million (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $43 million (related to unamortized ITC), substantially due to the recognition of amounts not previously recorded.
A summary of the components of deferred taxes as of December 31, 1993 follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
Current: Noncurrent: New Jersey unit tax $ 12 Liberalized Unbilled revenue 9 depreciation: Deferred energy 8 previously flowed Total $ 29 through $80 future revenue requirements 42 $122 Noncurrent: Unamortized ITC $ 43 Decommissioning 19 Liberalized Contribution in aid depreciation 364 of construction 17 Forked River 30 Other 32 Other 54 Total $111 Total $570
The reconciliations from net income to book income subject to tax and from the federal statutory rate to combined federal and state effective tax rates are as follows:
(In Millions) 1993 1992 1991
Net income $158 $117 $153 Income tax expense 81 52 73 Book income subject to tax $239 $169 $226
Federal statutory rate 35% 34% 34% Effect of difference between tax and book depreciation for which deferred taxes were not provided 2 2 2 Amortization of ITC (3) (4) (3) Other - (1) (1) Effective income tax rate 34% 31% 32%
Federal and state income tax expense is comprised of the following:
(In Millions) 1993 1992 1991
Provisions for taxes currently payable $42 $37 $56
Deferred income taxes: Liberalized depreciation 19 24 23 Gain/loss on reacquired debt 9 4 - Deferral of energy costs (8) - 2 Abandonment loss - Forked River (4) (4) (4) Nuclear outage maintenance costs - (3) 5 Accretion income 6 6 7 Unbilled revenues 5 (2) 8 Information system costs capitalized - 6 - New Jersey unit tax 32 3 (7) Other (14) (12) (10) Deferred income taxes, net 45 22 24
Amortization of ITC (6) (7) (7)
Income tax expense $81 $52 $73
The Internal Revenue Service (IRS) has completed its examinations of the GPU System's federal income tax returns through 1986. The GPU System and the IRS have reached an agreement to settle the GPU System's claim that TMI-2 has been retired for tax purposes. When approved by the Joint Congressional Committee on Taxation, this settlement will provide refunds for previously paid taxes. The GPU System estimates that the Company and its affiliates would receive net refunds totaling $17 million, of which the Company's share is approximately $4 million, which would be credited to the Company's customers. The Company and its affiliates would also be entitled to receive net interest estimated to total $45 million (before income taxes), of which the Company's share is approximately $11 million, through December 31, 1993, which the Company would credit to income. The years 1987, 1988 and 1989 are currently under audit.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following:
(In Millions) 1993 1992 1991
Maintenance $135 $125 $117
Other taxes: New Jersey unit tax $202 $197 $201 Real estate and personal property 6 7 7 Other 21 12 12
Total $229 $216 $220
For the years 1993, 1992 and 1991, the cost to the Company of services rendered to it by GPUSC amounted to approximately $39 million, $37 million and $36 million, respectively, of which approximately $29 million, $28 million and $27 million, respectively, was charged to income. For the years 1993, 1992 and 1991, the cost to the Company of services rendered to it by GPUN amounted to approximately $227 million, $247 million and $274 million, respectively, of which approximately $184 million, $170 million and $181 million, respectively, was charged to income. For the years 1993, 1992 and 1991, the Company purchased $23 million, $22 million and $21 million, respectively, in energy from a cogeneration project in which an affiliate has a 50 percent partnership interest.
7. EMPLOYMENT BENEFITS
Pension Plans:
The Company maintains defined benefit pension plans covering substantially all employees. The Company's policy is to currently fund net pension costs within the deduction limits permitted by the Internal Revenue Code.
A summary of the components of net periodic pension cost follows:
(In Millions) 1993 1992 1991
Service cost-benefits earned during the period $ 8.7 $ 8.1 $ 8.1 Interest cost on projected benefit obligation 29.4 27.6 25.7 Expected return on plan assets (32.1) (29.1) (27.9) Amortization (.4) (.6) (.6) Net periodic pension cost $ 5.6 $ 6.0 $ 5.3
The actual returns on the plans' assets for the years 1993, 1992 and 1991 were gains of $48.0 million, $17.5 million and $62.7 million, respectively.
The funded status of the plans and related assumptions at December 31, 1993 and 1992 were as follows:
(In Millions) 1993 1992 Accumulated benefit obligation (ABO): Vested benefits $ 310.7 $ 260.3 Nonvested benefits 36.2 28.2 Total ABO 346.9 288.5 Effect of future compensation levels 61.8 65.1 Projected benefit obligation (PBO) $ 408.7 $ 353.6
PBO $(408.7) $(353.6) Plan assets at fair value 425.2 384.6 PBO less than plan assets 16.5 31.0 Unrecognized net gain (10.1) (28.6) Unrecognized prior service cost 4.0 4.1 Unrecognized net transition asset (4.3) (4.8) Prepaid pension costs $ 6.1 $ 1.7
Principal actuarial assumptions(%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.5 Annual increase in compensation levels 5.0 6.0
Changes in assumptions in 1993 primarily due to reducing the discount rate assumption from 8.5% to 7.5% resulted in a $36 million change in the PBO as of December 31, 1993. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net gain represents actual experience different from that assumed, which is deferred and not included in the determination of pension cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits is being amortized as a charge to pension cost, while the unrecognized net transition asset arising out of the adoption of Statement of Financial Accounting Standards No. 87 is being amortized as a credit to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1993, 1992 and 1991 were $2.4 million, $2.1 million and $1.4 million, respectively.
Postretirement Benefits Other than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. For 1992 and 1991, the annual premium costs associated with providing these benefits totaled approximately $4.5 million and $4.4 million, respectively.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993, over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1993 follows:
(In Millions)
Service cost-benefits attributed to service during the period $ 3.4 Interest cost on the accumulated postretirement benefit obligation 10.4 Expected return on plan assets (.7) Amortization of transition obligation 5.7 Net periodic postretirement benefit cost 18.8 Deferred for future recovery (9.6) Postretirement benefit cost, net of deferrals $ 9.2
The actual return on the plans' assets for the year 1993 was a gain of $.9 million. The funded status of the plans at December 31, 1993, was as follows:
Accumulated Postretirement Benefit Obligation (APBO): Retirees $ 52.7 Fully eligible active plan participants 28.8 Other active plan participants 58.2 Total accumulated postretirement benefit obligation $ 139.7
APBO $(139.7) Plan assets at fair value 10.3 APBO in excess of plan assets (129.4) Unrecognized net loss 7.5 Unrecognized transition obligation 108.3 Accrued postretirement benefit liability $ (13.6)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 Discount rate 7.5
The Company intends to continue funding amounts for postretirement benefits collected from customers and other amounts with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
In the Company's most recent base rate proceeding, the NJBRC allowed the Company to collect $3 million annually of the incremental postretirement benefit costs, charged to expense, recognized as a result of FAS 106. Based on the final order and in accordance with Emerging Issues Task Force Issue Number 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," the Company is deferring the amounts above that level. A portion of the increase in annual costs recognized under FAS 106 of approximately $9.6 million is being deferred and should be recoverable through the ratemaking process.
The accumulated postretirement benefits obligation was determined by application of the terms of the medical and life insurance plans, including the effects of established maximums on covered costs, together with relevant actuarial assumptions and health-care cost trend rates of 14% for those not eligible for Medicare and 11% for those eligible for Medicare for 1994, decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 1, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $14 million and the aggregate of the service and interest cost components of net postretirement health-care cost for 1994 by approximately $1 million.
Postemployment Benefits:
In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112) which addresses accounting by employers who provide benefits to former or inactive employees after employment but before retirement, which is effective for fiscal years beginning after December 15, 1993. The Company adopted the accrual method required under FAS 112 during 1993, which did not have a material impact on the financial position or results of operations of the Company.
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the investment and charges its share of operating expenses to the appropriate expense accounts. The Company participated with affiliated and nonaffiliated utilities in the following jointly owned stations at December 31, 1993:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation Three Mile Island 25 $207.2 $57.5 Keystone 16.67 77.9 20.8 Yards Creek 50 24.3 6.3
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1993 and 1992 totaled $86 million and $105 million, respectively (net of amortization of $137 million and $108 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. An aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any one time. It is contemplated that when consumed, portions of the currently leased material will be replaced by additional leased material. The Company and its affiliates are responsible for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases are renewable annually. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1993, 1992 and 1991 these amounts were $34 million, $36 million and $29 million, respectively. The leases may be terminated at any time with at least five months notice by either party prior to the end of the current period. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.
The Company has sold and leased back substantially all of its ownership interest in the Merrill Creek Reservoir project. The minimum lease payments under this operating lease, which has a remaining term of 39 years, average approximately $3 million annually.