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

ITEM 1. BUSINESS.
General Public Utilities Corporation ("GPU" or the "Corporation"), a Pennsylvania corporation, organized in 1946, is a holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). GPU does not operate any utility properties directly, but owns all of the outstanding common stock of three electric utilities serving customers in New Jersey - Jersey Central Power & Light Company (JCP&L) - and Pennsylvania - Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The business of these subsidiaries (the Subsidiaries) consists predominantly of the generation, transmission, distribution and sale of electricity. GPU also owns all of the common stock of GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc. (EI), which develops, owns and operates nonutility generating facilities. Met-Ed owns all of the common stock of York Haven Power Company, the owner of a small hydroelectric generating station. Penelec owns all of the common stock of the Waverly Electric Light & Power Company, the owner of electric distribution facilities in the Village of Waverly, New York that are leased to Penelec. The Subsidiaries own all of the common stock of the Saxton Nuclear Experimental Corporation (Saxton), which owns a small demonstration nuclear reactor that has been partially decommissioned. All of these companies considered together are referred to as the "GPU System." The income of GPU consists almost exclusively of earnings on the common stock of the Subsidiaries.
As a registered holding company, GPU is subject to regulation by the Securities and Exchange Commission (SEC) under the 1935 Act. Retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each Subsidiary operates - in New Jersey by the New Jersey Board of Regulatory Commissioners (NJBRC) and in Pennsylvania by the Pennsylvania Public Utility Commission (PaPUC). The Nuclear Regulatory Commission (NRC) regulates the construction, ownership and operation of nuclear generating stations. The Subsidiaries are also subject to wholesale rate and other 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 Subsidiaries, 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 Subsidiaries are 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 Pennsylvania) 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 purchased power contracts, consisting primarily of contractual obligations with nonutility generators, are higher than future market prices. Utilities locked into expensive purchased 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 GPU System'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 GPU System 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, the Corporation 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 GPU System; Subsidiary ownership of the generating assets will remain with the Subsidiaries. GPU Generation will also build new generation facilities as needed by the Subsidiaries in the future. Involvement in the independent power generation market will continue through EI (See "Nonutility Businesses"). 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 JCP&L. Completion of these realignment initiatives will be subject to various regulatory reviews and approvals from the SEC, FERC, NJBRC and the 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 GPU System 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 Subsidiaries' share of the total cost of these agreements was estimated to be $500 million, the major part of which was expected to be incurred after 1994. In addition, JCP&L 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 Subsidiaries 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 JCP&L's request to participate in the proposed transactions. As a result of this action and other developments, the Subsidiaries notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Subsidiaries wrote off a total of approximately $25 million they had invested in the project.
THE SUBSIDIARIES
The electric generating and transmission facilities of the Subsidiaries are physically interconnected and are operated as a single integrated and coordinated system serving a population exceeding 4.8 million in New Jersey and Pennsylvania. For the year 1993, the Subsidiaries' revenues were about equally divided between Pennsylvania customers and New Jersey customers. During 1993, residential sales accounted for about 42% of operating revenues from customers and 36% of kilowatt-hour (KWH) sales to customers; commercial sales accounted for about 34% of operating revenues from customers and 32% of KWH sales to customers; industrial sales accounted for about 22% of operating revenues from customers and 29% of KWH sales to customers; and sales to rural electric cooperatives, municipalities (primarily for street and highway lighting) and others accounted for about 2% of operating revenues from customers and 3% of KWH sales to customers. The Subsidiaries also make interchange and spot market sales of electricity to other utilities. Reference is made to "System Statistics" on page, for additional information concerning the GPU System's sales and revenues.
The area served by the Subsidiaries extends from the Atlantic Ocean to Lake Erie, is generally comprised of small communities, rural and suburban areas and includes a wide diversity of industrial enterprises, as well as substantial farming areas. The Subsidiaries' transmission facilities are physically interconnected with neighboring nonaffiliated utilities in Pennsylvania, New Jersey, Maryland, New York and Ohio. The Subsidiaries 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.
The Subsidiaries 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, has 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.
In May 1993, the Pennsylvania Office of Consumer Advocate (Consumer Advocate) filed a petition for review of Met-Ed's rate order with the Pennsylvania Commonwealth Court seeking to set aside a March 1993 decision which allowed Met-Ed to (a) recover in the future certain Three Mile Island Unit 2 (TMI-2) retirement costs (radiological decommissioning and nonradiological cost of removal) and (b) defer the incremental costs associated with the adoption of the Statement of Financial Accounting Standards No. 106 (FAS 106) "Employers' Accounting for Postretirement Benefits Other Than Pensions." If the 1993 rate order is reversed, Met-Ed and Penelec would be required to write off a total of approximately $170 million for TMI-2 retirement costs. In addition, the Consumer Advocate is contesting utility deferral of FAS 106 costs in a proceeding involving another utility. The outcome of this proceeding may affect the recovery of FAS 106 costs for Met-Ed and Penelec. This matter is pending before the court. (See "Rate Proceedings.")
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 existing GPU System wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of Met-Ed or JCP&L. Penelec has made similar offers to certain wholesale customers now being served by other utilities. Although wholesale customers represent a relatively small portion of GPU System sales, the Subsidiaries will continue their efforts to retain and add customers.
NUCLEAR FACILITIES
The Subsidiaries have made investments in three major nuclear projects -- Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and TMI-2, which was damaged during the 1979 accident. At December 31, 1993, the Subsidiaries' net investment in TMI-1 and Oyster Creek, including nuclear fuel, was $670 million and $784 million, respectively. TMI-1 and TMI-2 are jointly owned by JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by JCP&L.
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 GPU System may also incur costs and experience reduced output at its 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 the Corporation and the Subsidiaries. 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 GPU System.
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 consolidated financial statements for further information regarding nuclear fuel disposal costs.
In 1990, the Subsidiaries submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Subsidiaries intend to complete the funding for Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1993 dollars) for TMI-1 and Oyster Creek are $143 million and $175 million, respectively. Based on NRC studies, a comparable funding target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 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 the radiological portions of decommissioning each plant to range from approximately $205 to $285 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 and $47 million, respectively.
The ultimate cost of retiring the GPU System's nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies 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 Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Subsidiaries have contributed to external trusts amounts written off for nuclear plant decommissioning in 1990 and 1991.
TMI-1 and Oyster Creek
JCP&L is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. JCP&L has also begun collecting revenues based on estimates, adopted in a February 26, 1993 summary rate order issued by the NJBRC, for the cost of removal of nonradiological structures and materials at each plant based on its share of an estimated $15.3 million for TMI-1 and $31.6 million for Oyster Creek. In January 1993, the PaPUC granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site-specific study. Effective October 1993, the PaPUC approved a rate change for Penelec which increased the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for 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 $29 million for TMI-1 and $80 million for Oyster Creek at December 31, 1993.
Management believes that 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 Corporation and its Subsidiaries have recorded a liability amounting to $229 million as of December 31, 1993, for the radiological decommissioning of TMI-2, reflecting the NRC funding target. The Subsidiaries record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Subsidiaries have also recorded a liability in the amount of $20 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 Subsidiaries have recorded a liability in the amount of $71 million for 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. JCP&L has made a nonrecoverable contribution of $15 million to an external decommissioning trust. Met-Ed and Penelec have made nonrecoverable contributions of $40 million and $20 million, respectively, to external decommissioning trusts relating to their shares of the accident- related portion of the decommissioning liability.
The NJBRC and the PaPUC have granted JCP&L and Met-Ed, respectively, decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials, although the PaPUC's order has been appealed by the Consumer Advocate (see "Rate Proceedings"). Penelec intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. 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 Subsidiaries are incurring incremental storage costs currently estimated at $1 million annually. The Subsidiaries have deferred the $20 million for the total estimated incremental costs attributable to monitored storage through 2014, the expected retirement date of TMI-1. The JCP&L share of these costs has been recognized in rates by the NJBRC. Met-Ed and Penelec believe these costs should be recoverable through the ratemaking process.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station (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 for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of 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 GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years 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 GPU System is subject to retrospective premium assessments of up to $52 million in addition to those payable under the Price-Anderson Act.
NONUTILITY AND OTHER POWER PURCHASES
The Subsidiaries have 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 Subsidiaries to purchase all of the power produced up to the contract limits. The agreements have been approved by the state regulatory commissions and permit the Subsidiaries to recover energy and demand costs from customers through their energy clauses. These agreements provide for the sale of approximately 2,452 MW of capacity and energy to the GPU System by the mid-to-late 1990s. As of December 31, 1993, facilities covered by these agreements having 1,193 MW of capacity were in service, and 215 MW were scheduled to commence operation in 1994. Payments made pursuant to these agreements were $491 million for 1993 and are estimated to aggregate $551 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 Subsidiaries have been granted full recovery of these costs from customers by the state commissions, there can be no assurance that the Subsidiaries 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 System's energy supply needs which, in turn, has caused the Subsidiaries to change their supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Subsidiaries 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 Subsidiaries may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before both the NJBRC and the PaPUC, as well as to litigation, and may result in claims against the Subsidiaries for substantial damages. There can be no assurance as to the outcome of these matters.
In July 1993, the PaPUC acted to initiate a rulemaking proceeding which, in general, would establish a mandatory all-source competitive bidding program by which utilities would meet their future capacity and energy needs.
Also in July, a 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 purchased power contracts with nonutility generators to determine whether there are any candidates for potential buy-out or other remedial measures. In response, JCP&L 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 JCP&L and the developer to negotiate contract repricing to a level more consistent with JCP&L'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 JCP&L, a one-year extension in the in- service dates for projects which were originally scheduled to be operational in 1997. JCP&L is awaiting a final written NJBRC order and may appeal this decision.
Also in November 1993, JCP&L 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, JCP&L 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, JCP&L 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. JCP&L 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, JCP&L is willing to give some consideration to proposals in excess of eight-year terms.
In November 1993, Penelec filed an appeal with the Commonwealth Court seeking to overturn a PaPUC order which directs Penelec to enter into two power purchase agreements with nonutility generators for a total of 160 MW under long-term contracts commencing in 1997 or later. Penelec believes it does not need this additional capacity and believes the costs associated with these contracts are not in the economic interests of its customers. The matter is pending before the Commonwealth Court.
JCP&L and Met-Ed have entered into arrangements for two peaking generation projects. JCP&L 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. JCP&L expects to complete the project by 1996. Met-Ed has received the PaPUC's approval to build a 134 MW gas-fired combustion turbine adjacent to its Portland Generating Station at a cost of $50 million. The approval has been appealed by a nonutility generator seeking to sell Met-Ed an equivalent amount of baseload capacity.
The Subsidiaries 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
Pennsylvania
In April 1992, Met-Ed filed with the PaPUC a petition requesting a net $55 million annual increase in retail base rates. The request for additional revenues included provisions for higher operating expenses, capital costs and nuclear plant decommissioning costs. In January 1993, the PaPUC issued a rate order denying revenues for certain TMI-2 retirement and incremental monitored storage costs and the collection of costs associated with the adoption of FAS 106.
In March 1993, in response to a petition filed by Met-Ed for clarification, reconsideration and amendment, the PaPUC modified portions of its January 1993 rate order to allow for the future recovery of certain TMI- 2 retirement costs (radiological decommissioning and nonradiological cost of removal). (See "Nuclear Plant Retirement Costs.") In addition, the PaPUC action allowed both Met-Ed and Penelec to defer the incremental costs associated with the adoption of FAS 106. The PaPUC directed Met-Ed to reduce its amortization of TMI-2 to $8.3 million, retroactive to January 1993. The recovery of certain TMI-2 retirement costs will begin when the amortization of the TMI-2 investment ends in 1994 at the same annual amount ($6.3 million for recovery of radiological decommissioning and $2.0 million for nonradiological cost of removal, net of gross receipts tax). In May 1993, the Consumer Advocate filed a petition for review with the Pennsylvania Commonwealth Court seeking to set aside the PaPUC 1993 rate order. The matter is pending before the court. If the 1993 rate order is reversed, Met-Ed and Penelec would be required to write off a total of approximately $170 million for TMI-2 retirement costs. Penelec intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. Management intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
The PaPUC has recently completed its generic investigation into demand- side management (DSM) cost recovery mechanisms and issued a cost recovery and ratemaking order in December 1993. Penelec and Met-Ed are currently developing plans which will reflect changes since their original plans were filed in 1991. In December 1993, the Pennsylvania Industrial Energy Coalition (PIEC) appealed to the Commonwealth Court to reverse the PaPUC Order. On February 4, 1994, Met-Ed and Penelec filed a petition seeking a stay of the PaPUC's Order until the PIEC's appeal is resolved. (See "Demand Side Management.")
In February 1994, Met-Ed made an annual filing with the PaPUC for an increase in its Energy Cost Rate (ECR) of $4.7 million. The new rate is expected to become effective April 1, 1994.
In March 1994, Penelec made its annual filing with the PaPUC for an increase in its ECR of $38.3 million. The new rate is expected to become effective April 1, 1994.
The PaPUC is considering generic nuclear performance standards for Pennsylvania utilities. In January 1994, Met-Ed and Penelec submitted a proposal which, along with proposals submitted by the other Pennsylvania utilities, may result in the PaPUC adopting a generic nuclear performance standard.
New Jersey
In December 1993, JCP&L 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, JCP&L 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.
JCP&L'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, JCP&L 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 JCP&L 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 Subsidiaries had gross plant additions of approximately $520 million attributable principally to improvements and modifications to existing generating stations, additions to the transmission and distribution system and clean air requirements. During 1994, JCP&L, Met-Ed, Penelec and GPUSC contemplate gross plant additions of approximately $275 million, $167 million, $218 million and $3 million, respectively. The Subsidiaries' gross plant additions are expected to total approximately $589 million in 1995. The anticipated decrease in construction expenditures during 1995 is principally attributable to an anticipated reduction in the level of expenditures associated with clean air requirements and nuclear generation. 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 $ 93 Nonnuclear 228 Total Generation 321 Transmission & Distribution 291 Other 51 Total $663
In addition, expenditures for maturing debt are expected to be $133 million and $91 million for 1994 and 1995, respectively. Subject to market conditions, the Subsidiaries intend 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 GPU System's total capital needs for 1994 and 1995 will be satisfied through internally generated funds. The Subsidiaries expect to obtain the remainder of these funds principally through the sale of first mortgage bonds and preferred stock, subject to market conditions. The Subsidiaries' bond indentures and articles of incorporation include provisions that limit the amount of long- term debt, preferred stock and short-term debt the Subsidiaries may issue. The Subsidiaries' interest and preferred stock dividend coverage ratios are currently in excess of indenture or charter restrictions. Present plans call for the Subsidiaries 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 GPU System's 1994 construction program includes $120 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 $75 million for Clean Air Act compliance.
GPU's gross plant additions exclude nuclear fuel requirements provided under capital leases that amounted to $46 million in 1993. When consumed, the presently leased material, which amounted to $150 million at December 31, 1993, is expected to be replaced by additional leased material at an average rate of approximately $60 million annually. In the event the replacement nuclear fuel needs cannot be leased, the associated capital requirements would have to be met by other means.
The GPU System has a projected need, due in large part to anticipated peak load growth, of 644 MW of additional capacity by the year 1998 based on an average growth in sales to customers of about 1.7% annually with growth rates for the Subsidiaries projected from about 1.1% to 2.3%. GPU intends to provide for this increased energy need through a mix of economic sources.
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. Through 1998, GPU's plan consists of the continued utilization of most existing generating facilities, retirement of certain older units, power purchases, construction of new facilities, and the continued promotion of economic energy conservation and load management programs. Given the future direction of the industry, GPU'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 GPU System will resist efforts to compel it to add or contract for new capacity at costs that may exceed future market prices. In addition, the Subsidiaries 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 environments in both New Jersey and Pennsylvania encourage the development of new conservation and load management programs. This is evidenced by DSM incentive regulations adopted in New Jersey in 1992 and recent approval of a cost recovery mechanism for DSM in Pennsylvania. 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).
In New Jersey, the NJBRC approved JCP&L'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 JCP&L can also earn a performance-based incentive for successfully implementing cost effective programs. In addition, JCP&L will continue to make certain NJBRC mandated Core Program DSM investments which are recovered annually.
In 1990, Met-Ed and Penelec jointly filed a proposal with the PaPUC on demand-side management (DSM) issues. The proposal recommends that the PaPUC preapprove DSM programs of utilities to enable the collection of their costs and that the PaPUC issue an order on a generic basis. In December 1993, the PaPUC issued an order adopting generic guidelines for recovery of DSM
expenses. Also, in December 1993, the Consumer Advocate and the Pennsylvania Energy Office filed separate petitions for clarification and reconsideration of the PaPUC's order and the PIEC appealed to the Commonwealth Court to reverse the PaPUC order. On February 4, 1994, Met-Ed and Penelec filed a petition seeking a stay of the PaPUC's order until the PIEC's appeal is resolved.
FINANCING ARRANGEMENTS
The Corporation and its affiliates expect to have short-term debt outstanding from time to time throughout the year. The peak in short-term debt outstanding is expected to occur in the spring coinciding with normal cash requirements for revenue tax payments.
The Corporation and the Subsidiaries 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 Subsidiaries refinanced higher cost long-term debt in the principal amount of $723 million resulting in an estimated annualized after- tax savings of $6 million. Total GPU System long-term debt issued during 1993 amounted to $957 million. In addition, the Subsidiaries redeemed $156 million of high-dividend rate preferred stock issues.
During 1993, GPU sold four million shares of common stock at $33 1/8 per share through an underwritten public offering. The net proceeds of $128.7 million were used primarily to reimburse the Subsidiaries for the preferred stock redemptions.
In January 1994, Penelec issued an aggregate of $90 million of first mortgage bonds, of which a portion of the net proceeds were used to redeem $38 million principal amount of 6 5/8% series bonds in February 1994. Met- Ed issued, in February 1994, an aggregate of $50 million of first mortgage bonds, of which a portion of the net proceeds will be used to redeem $26 million principal amount of 7% series bonds in March 1994.
The Subsidiaries have regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock for various periods through 1995. Under existing authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the amount of $275 million, $250 million and $330 million, respectively, of which $100 million for each Subsidiary may consist of preferred stock. The Subsidiaries also have regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
Under the Subsidiaries' 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 presently leased material will be replaced by additional leased material. The Subsidiaries
are responsible for the disposal costs of nuclear fuel leased under these agreements.
REGULATION
As a registered holding company, GPU is subject to regulation by the SEC under the 1935 Act. The GPU System companies are 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 Subsidiaries constitute a single integrated public utility system under the standards of the 1935 Act. The 1935 Act also limits the extent to which the GPU System may engage in nonutility businesses. Each Subsidiary's retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which such Subsidiary operates - in New Jersey by the NJBRC and in Pennsylvania by the PaPUC. Moreover, with respect to wholesale rates, the transmission of electric energy, accounting, the construction and maintenance of hydroelectric projects and certain other matters, the Subsidiaries are 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. (See "Electric Generation and the Environment - Environmental Matters" for additional regulation to which the Subsidiaries are or may be subject.)
The rates charged by the Subsidiaries 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 JCP&L filed comments with the NJBRC.
In 1992, as a result of a rulemaking proceeding, the PaPUC established quarterly financial reporting requirements to monitor public utility earnings.
NONUTILITY BUSINESSES
GPC was organized to make investments apart from the businesses of the Subsidiaries. Currently, these are conducted by EI, a subsidiary of GPC, and its subsidiaries. EI is in the business of developing, owning, operating and investing in cogeneration and other nonutility power production facilities. As of December 31, 1993, EI had 223 MW of capacity in operation and an option to acquire a 20% equity interest in projects having an additional 350 MW of capacity. EI's potential business activities and markets have been significantly expanded as a result of the regulatory changes brought about by the Energy Act.
In 1993, EI entered into an agreement to invest up to $8.5 million over the next four years to acquire an up to 29% equity interest in a private independent power development company, which has commitments or prospects to provide more than 200 MW of electricity to utilities in Canada and plans to
develop other projects in the United States. EI also obtained the right to operate several of the projects. In addition, EI has been active as a bidder and has proposals pending for the development and acquisition of additional capacity in the United States. EI is also pursuing international development projects in Latin America and has been designated as a successful bidder on a proposed 750 MW repowering project in Colombia, South America. EI is also investigating other international opportunities.
At December 31, 1993, GPU's investment in GPC was $39 million. GPU intends to make additional investments in the development and ownership of nonutility generating facilities in an effort to expand these business activities. The timing and amounts of these investments, however, will depend upon the development of appropriate opportunities. GPU does not expect investments apart from the activities of EI to be a major part of its business activities; however, this may change as GPU's strategic plan is developed. (See "Regulation.")
ELECTRIC GENERATION AND THE ENVIRONMENT
Fuel
Of the portion of their energy requirements supplied by their own generation, the Subsidiaries utilized fuels in the generation of electric energy during 1993 in approximately the following percentages: Coal--60%; Nuclear--38%; Gas--1% and Oil--1%. Approximately 42% of the Subsidiaries' energy requirements in 1993 was supplied by purchases (including net interchange) from other utilities and nonutility generators. For 1994, the Subsidiaries estimate that their generation of electric energy will be in the following proportions: Coal--64%; Nuclear--33%; Gas--2% and 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 43% of the Subsidiaries' 1994 energy requirements are expected to be supplied by purchases (including net interchange) from other utilities and nonutility generators.
Fossil: The Subsidiaries have entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which they have ownership interests. The contracts, which expire between 1994 and the end of the expected service lives of the generating stations, require the purchase of fixed amounts of coal. The price of the coal under the contracts is generally based on adjustments of indexed cost components. One contract also includes a provision for the payment of environmental and post-employment benefits. Another coal contract sets coal prices that generally provide for the recovery by the mining companies of their costs of production. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $89 million for 1994.
The Subsidiaries' coal-fired generating stations now in service are estimated to require an aggregate of 160 million tons of coal over the next twenty years. Of this total requirement, approximately 13 million tons are expected to be supplied by nonaffiliated mine-mouth coal companies with the balance supplied through long-term contracts and spot market purchases.
At the present time, adequate supplies of fossil fuels are readily available to the Subsidiaries, but this situation could change rapidly as a result of actions over which they have no control.
Nuclear: Preparation of nuclear fuel for generating station use involves various manufacturing stages for which the GPU System contracts 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 Subsidiaries are 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 Subsidiaries are 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 Subsidiaries 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 GPU System 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 mine refuse piles, 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 GPU System's generating stations, where required, have expiration dates ranging through 1998. Timely reapplications for such permits have been filed as required by regulations.
The discharge permit received by JCP&L 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 GPUN's 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 JCP&L's Gilbert and Sayreville generating stations which, among other things, could require JCP&L to install cooling towers and/or modify the water intake/discharge systems at these facilities. JCP&L 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 JCP&L's hearing request. JCP&L has made filings with the NJDEPE that JCP&L 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 present 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 Subsidiaries are 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.
During 1993, Met-Ed entered into an agreement with various agencies to construct a fish passage facility at its York Haven hydroelectric project by the year 2000. The present estimated installed cost of the facility is $6.5 million.
Nuclear: Reference is made to "Nuclear Facilities" for information regarding the TMI-2 accident, its aftermath and the GPU System'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. GPUN's expected $29.5 million share of the cost for this facility is to be paid annually over an eight year period ending in 1999. In its February 1993 rate order, the NJBRC granted JCP&L'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 GPUN's share is $12 million. These payments are considered advance waste disposal fees and will be recovered during the facility's operation.
The Subsidiaries have 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 $47 million. The Subsidiaries made their initial payment in 1993. The remaining amount recoverable from ratepayers is $48 million at December 31, 1993.
Air: The Subsidiaries are subject to certain state environmental regulations of the NJDEPE, the New Jersey Department of Health and the PaDER. The Subsidiaries are 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 BTU of heat input, respectively. On a weighted average basis, the Subsidiaries have been able to obtain coal having a sulfur content meeting these criteria. If, and to the extent that, the Subsidiaries 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 will be necessary for the GPU System to install and operate emission control equipment as well as switch to slightly lower sulfur coal at some of the GPU System's coal-fired plants in order to achieve compliance. To comply with Title IV of the Clean Air Act, the GPU System expects to expend up to $590 million by the year 2000 for air pollution control equipment, of which approximately $91 million has been spent as of December 31, 1993. These capital expenditures for Penelec, Met-Ed and JCP&L are estimated to amount to $295 million, $150 million and $145 million, respectively, for the installation of scrubbers, low NOx burner technology and various precipitator upgrades. The capital costs of this equipment and the increased operating costs of the affected stations are expected to be recoverable through the ratemaking process. Met-Ed and the other owners of the Conemaugh Generating Station have awarded contracts for the installation of scrubbers, and construction is underway, on the two coal units at Conemaugh; Met-Ed's estimated 16.45% share of these costs is $64 million. This action is part of the GPU System's plans to comply with Phase I sulfur dioxide emission limitations. The current construction schedule provides for Conemaugh Units 1 and 2 scrubbers to be in service by January of 1995 and 1996, respectively. In its January 1993 rate order, the PaPUC approved Met-Ed's request for $24.5 million of current expenditures to be included in rate base representing certain costs associated with the installation of scrubbers at the Conemaugh Generating Station and other environmental compliance projects. The plan for Portland Station is to meet its Phase I compliance obligation through the use of emission allowances, including allowances allocated directly to Portland station by the EPA and allowances resulting from the scrubbing of Conemaugh station.
The GPU System's current strategy for Phase II compliance under the Clean Air Act is to install scrubbers at the Keystone station and evaluate the installation of scrubbers or fuel switching at the Homer City Unit 3 station. Switching to lower sulfur coal is currently planned for the Titus, Portland, Seward, and Warren Stations. Homer City Units 1 and 2 will use existing coal cleaning technology.
The GPU System continues to review available options to comply with the Clean Air Act, including those which may result from the development of an emission allowance trading market. The GPU System'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 nitrogen oxide will be required to implement Reasonably Available Control Technology (RACT) by May 31, 1995. This will affect the GPU System's 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. In order to comply with these RACT regulations, low NOx burners with separate overfire air are being installed at the Portland and Conemaugh Stations. A RACT compliance plan for Titus Station will be finalized in early 1994. 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. However, the Homer City Coal Processing Plant is being studied to determine if it is a major stationary source of air toxins.
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 (Homer City, Conemaugh, Keystone and Seward generating stations). The Homer City, Conemaugh and Keystone generating stations are jointly owned with nonaffiliated utilities. 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.
The area around the Warren generating station has been designated as nonattainment for sulfur dioxide. In the case of the Warren Generating station area, Penelec began a model evaluation study in early 1993. The results of the study will be used to determine if a nonguideline model can be used. The study results will be available in 1994. A Consent Order and
Agreement has been negotiated to allow the PaDER to revise the implementation plan for Warren Station. A model evaluation study is also being conducted at Shawville Station. The results of this study will be available in 1995.
The attainment issue has been taken into account as part of the design of the Conemaugh Station scrubbers. Met-Ed has initiated ambient air quality modeling studies for its Portland and Titus Stations that will take several years to complete. While the results are uncertain, these studies may result in a revised Pennsylvania State Implementation Plan (PaSIP) in order to attain NAAQS for sulfur dioxide. If sulfur dioxide emissions need to be reduced to meet the new PaSIP, Met-Ed will reevaluate its options available for Portland and Titus Stations.
Based on the results of the studies pursuant to NAAQS, significant sulfur dioxide reductions may be required at one or more of these stations 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 Subsidiaries 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 which intends to reduce greenhouse gas emissions to 1990 levels by the year 2000. The climate action plan relies heavily on voluntary action by industry. GPU notified the DOE that it supported the voluntary approach proposed by the President and expressed its 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 (CEMS) and quality assure the data for sulfur dioxide, nitrogen oxides, opacity and volumetric flow. In addition, Title VIII requires all affected sources to monitor carbon dioxide emissions. Monitoring systems have been installed and certified on Met-Ed's Phase I and Penelec's Phase I and Phase II affected units as required by EPA and PaDER regulations. Monitoring systems have been installed on Met-Ed's Phase II affected units and will be certified in 1994.
The PaDER has a CEMS enforcement policy to ensure consistent compliance with air quality regulations under federal and state statutes. The CEMS enforcement policy includes matters such as visible emissions, sulfur dioxide emission standards, nitrogen oxide emissions and a requirement to maintain certified continuous emission monitoring equipment. In addition, this policy provides a mechanism for the payment of certain prescribed amounts to the Pennsylvania Clean Air Fund (Clean Air Fund) for air pollutant emission excesses or monitoring failures. With respect to the operation of Met-Ed's and Penelec's generating stations for 1994, it is not anticipated that payments to be made to the Clean Air Fund will be material in amount.
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.
The EPA has established Best Available Retrofit Technology (BART) sulfur dioxide emission standards to be used for Penelec's Shawville and Seward generating stations under the Good Engineering Practice stack height regulation. Dependent upon the Chestnut Ridge Compliance Strategy and the results of the Shawville Model evaluation study mentioned above, lower sulfur coal purchases may be necessary for compliance. Discussions with the EPA regarding this matter are continuing.
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. JCP&L 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 in which it owns a 16.67% interest. In addition, coal-fired generating facilities owned by Met-Ed and Penelec supply electric energy to JCP&L and other New Jersey members of PJM. Hearings on the EDF petition were held during 1989 and 1990, and the matter is pending before the NJDEPE and the NJBRC.
In New Jersey, where the bulk of the GPU System's oil-fired generating capacity is located, NJDEPE regulations establish the maximum sulfur content of oil, which may not exceed .3% for most of JCP&L's generating stations and 1% for the balance.
In 1993, the Subsidiaries made capital expenditures of approximately $70 million in response to environmental considerations and have included approximately $121 million for this purpose in their 1994 construction programs. The operating and maintenance costs, including the incremental costs of low-sulfur fuel, for such equipment were approximately $105 million in 1993 and are expected to be approximately $108 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 presently underway.
Certain parties have alleged that the exposure to EMF associated with the operation of 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 Subsidiaries cannot determine at this time what effect, if any, this matter will have on them.
Residual Waste: The PaDER has finalized the residual waste regulations which became effective in July 1992. These regulations impose additional restrictions on operating existing ash disposal sites and for siting future disposal sites and will increase the costs of establishing and operating these facilities. The main objective of these regulations is to prevent degradation of groundwater and to abate any existing degradation.
One of the first significant compliance requirements of the regulations is conducting groundwater assessments of landfills if existing groundwater monitoring indicates the possibility of degradation. The assessments require the installation of additional monitoring wells and the evaluation of one year's worth of data. All of Penelec's active landfills require assessments. If the assessments show degradation of the groundwater, then the next step is to develop abatement plans. However, there is no specific timetable on the implementation of abatement activities, if required. Penelec and Met-Ed's landfills are to have preliminary permit modification applications submitted to the PaDER by July 1994, and complete permit applications under evaluation by July 1997. Met-Ed's Portland and Titus landfills have had preliminary assessments conducted which are currently under review by the PaDER. The Titus Station ash disposal site was upgraded in 1991 and subsequently meets all lined facility requirements. The Portland station ash disposal site will require significant modifications under the new regulations. Various alternatives for upgrading the site are being evaluated. In addition, the regulations can also be enforced at sites closed since 1980 at the PaDER's option.
Other compliance requirements at Penelec that will be implemented in the future include the lining of currently unlined disposal sites and storage impoundments. Impoundments also will eventually require groundwater monitoring systems and assessments of impact on groundwater. Groundwater abatement may be necessary at locations where pollution problems are identified. The removal of all the residual waste or "clean closed" will be done at some impoundments to eliminate the need for future monitoring and abatement requirements. Storage impoundments must have implemented groundwater monitoring plans by 2002, but PaDER can require this at any time prior to this date or defer full compliance beyond 2002 for some storage impoundments at their discretion. Also being evaluated are the exercising of beneficial use options authorized by the regulations, and source reductions.
Preliminary groundwater assessment plans have also been conducted at Met-Ed's Portland and Titus Stations' industrial waste treatment impoundments and are currently under review by the PaDER. Additional data will be collected and evaluated to determine if abatement will be required. The
Portland Station impoundments were upgraded in 1987 and meet the requirements for lined impoundments. The Titus Station impoundments will require significant modifications by 2002.
There are also a number of issues still to be resolved regarding certain waivers related to Penelec's existing landfill and storage impoundment compliance requirements. These waivers could significantly reduce the cost of many of the Company's facility compliance upgrades.
Another aspect of the regulations deals with the storage and disposal of polychlorinated biphenyl (PCB) wastes between two and 50 parts per million (ppm). Federal regulations only deal with wastes over 50 ppm. The compliance requirements for this regulation are currently being evaluated.
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 PCBs. Such regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs. The Subsidiaries have met all requirements of the TSCA necessary to allow the continued use of equipment containing PCBs and have taken substantive voluntary actions to reduce the amount of PCB containing electrical equipment in the System.
Prior to 1953, the Subsidiaries owned and operated manufactured gas plants in New Jersey and Pennsylvania. 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 Subsidiaries 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. JCP&L has identified 17 such sites to date. JCP&L has entered into cost sharing agreements with New Jersey Natural Gas Company and Elizabethtown Gas Company under which JCP&L is responsible for 60% of all costs incurred in connection with the remediation of 12 of these sites. JCP&L has entered into Administrative Consent Orders (ACOs) with the NJDEPE for seven of these sites and has entered into Memoranda of Agreement (MOAs) with the NJDEPE for eight of these sites. JCP&L anticipates entering into MOAs for the remaining sites. The ACOs specify the agreed upon obligations of both JCP&L and the NJDEPE for remediation of the sites. The MOAs afford JCP&L greater flexibility in the schedule for investigation and remediation of sites. JCP&L is seeking NJDEPE approval of its plans for the remediation of these sites. The NJDEPE has approved JCP&L's implementation program for five of these sites.
At December 31, 1993, JCP&L 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, JCP&L believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties: JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are
subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In June 1993, the NJBRC approved a mechanism for the recovery of future manufactured gas plant remediation costs through JCP&L'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. JCP&L is currently awaiting a final NJBRC order. JCP&L 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. Pennsylvania and New Jersey have enacted legislation giving similar authority to the PaDER and the NJDEPE, respectively. Because of the nature of the Subsidiaries' business, various by-products and substances are produced and/or handled that are classified as hazardous under one or more of these statutes. The Subsidiaries generally provide 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 GPU System companies have been notified by the EPA and state environmental authorities that they are among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 10 hazardous and/or toxic waste sites (including those described below). In addition, the GPU System companies have been requested to supply information to the EPA and state environmental authorities on several other sites for which the GPU System companies have not as yet been named as PRPs. Met-Ed and Penelec have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment.
The Subsidiaries received notification in 1986 from the EPA that they are 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. JCP&L, Met-Ed, Penelec and Saxton are alleged to have contributed, in the aggregate, approximately 2.3% 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 EPA has initiated a suit under CERCLA and other laws for the initial cleanup of hazardous materials deposited at a waste disposal site at Harper Drive, Millcreek Township, Pennsylvania (Millcreek site). Penelec is one of over 50 PRPs at this site. Penelec does not know whether its insurance
carriers will assume the responsibility to defend and indemnify it in connection with this matter.
Two lawsuits involving property owners at or near the Millcreek site have been filed against Penelec and other PRPs. Penelec's insurance carriers are defending these actions but may not provide coverage in the event compensatory damages are awarded. In addition, claims have also been made for punitive damages which may not be covered by insurance.
Penelec, together with 24 others, has been named as a third party defendant in an action commenced under the CERCLA by the EPA in the U.S. District Court in Ohio. The EPA is seeking to recover costs for the cleanup of hazardous and toxic materials disposed at the New Lyme landfill site in Ashtabula, Ohio. Penelec, together with 22 others, has also been named as a third party defendant in an action under the CERCLA by the state of Ohio seeking to recover costs it has incurred and will incur in the future at the New Lyme landfill site.
Met-Ed, together with 35 others, has been named as a third party defendant in an action commenced under CERCLA by the EPA in the U.S. District Court for the Eastern District of Pennsylvania. The EPA is seeking to recover response costs for hazardous materials disposed at the Mabry/Oswald Site in Upper Macungie and Longswamp Townships, Pennsylvania. Met-Ed has reached settlement of its liability in this matter and expects to be dismissed from the litigation.
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 GPU System companies.
The GPU System companies are 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.
EMPLOYEE RELATIONS
At February 28, 1994, the GPU System had 11,939 full-time employees. The nonsupervisory production and maintenance employees of the Subsidiaries and certain of their nonsupervisory clerical employees are represented for collective bargaining purposes by local unions of the International Brotherhood of Electrical Workers (IBEW) at JCP&L, Met-Ed and Penelec and the Utility Workers Union of America (UWUA) at Penelec.
Penelec's five-year contracts with the IBEW and UWUA expire on May 14, 1998 and June 30, 1998, respectively. Met-Ed's three-year contract with the IBEW expires on April 30, 1994. JCP&L'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 GPU System had an aggregate effective summer capability of 6,739,000 net kilowatts (KW), as follows:
Name of Year of Name of Year of Station Installation Net KW Station Installation Net KW
COAL-FIRED: GAS/OIL-FIRED: Homer City(a) 1969-1977 942,000 (gas or oil) Shawville 1954-1960 597,000 Sayreville(d) 1930-1958 313,000 Portland 1958-1962 401,000 Gilbert 1930-1949 117,000 Keystone(b) 1967-1968 283,000 Combustion Conemaugh(c) 1970-1971 280,000 (gas or oil) Titus 1951-1953 241,000 Turbines 1960-1989 1,160,000 Seward 1950-1957 196,000 Werner (oil) 1953 58,000 Warren 1948-1949 82,000 Other(e) 1968-1977 332,000
NUCLEAR: HYDROELECTRIC 1905-1969 64,000 TMI-1 1974 786,000 PUMPED STORAGE:(f) Oyster Creek 1969 610,000 Yards Creek 1965 190,000 Seneca 1969 87,000 TOTAL 6,739,000
(a) Represents Penelec's undivided 50% interest in the station.
(b) Represents JCP&L's undivided 16.67% interest in the station.
(c) Represents Met-Ed's undivided 16.45% interest in the station.
(d) Effective February 1, 1994, 84,000 KW of capability were retired.
(e) Consists of internal combustion and combined cycle units.
(f) Represents the Subsidiaries' undivided interests in these stations which are net users rather than net producers of electric energy.
All the GPU System's coal-fired, hydroelectric (other than the Deep Creek Station) and pumped storage stations (other than the Yards Creek station) are located in Pennsylvania. The TMI-1 nuclear station is also located in Pennsylvania. The GPU System's gas-fired and oil-fired stations (other than some combustion turbines in Pennsylvania), the Yards Creek pumped storage station and the Oyster Creek nuclear station are located in New Jersey. The Deep Creek hydroelectric station is located in Maryland.
Substantially all of the Subsidiaries' properties are subject to the lien of their respective first mortgage bond indentures.
The peak load of the GPU System, which occurred on July 9, 1993, was 8,533,000 KW.
Transmission and Distribution System
At December 31, 1993, the GPU System owned 1,249 transmission and distribution substations that had an aggregate installed transformer capacity of 49,562,096 kilovoltamperes (KVA), and 6,714 circuit miles of transmission lines, of which 441 miles were operated at 500 KV, 149 miles at 345 KV, 1,603 miles at 230 KV, 14 miles at 138 KV, 1,909 miles at 115 KV and the balance of 2,598 miles at 69 KV, 46 KV and 34.5 KV. The Subsidiaries' distribution system included 21,142,583 KVA of line transformer capacity, 50,085 pole miles of overhead lines and 9,897 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 to Note 1 to consolidated financial statements contained in Item 8 for a description of certain pending legal proceedings involving the GPU System.
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.
Stock Trading
General Public Utilities Corporation is listed as GPU on the New York Stock Exchange. On February 28, 1994, there were approximately fifty-thousand registered holders of GPU common stock.
Dividends
Dividend declaration dates are the first Thursdays of April, June, October and December. Dividend payment dates fall on the last Wednesdays of February, May, August and November. Dividend declarations and quarterly stock price ranges for 1993 and 1992 are set forth below.
Common Stock
Dividends Declared Price Ranges* 1993 1992 1993 1992 Quarter High/Low High/Low
April $.40 $.40 First $30 1/4 $25 3/4 $27 3/8 $24 1/2 June .425 .40 Second 32 3/8 28 5/8 26 3/8 24 1/4 October .425 .40 Third 34 3/4 31 5/8 27 3/8 25 1/2 December .425 .40 Fourth 34 28 3/4 27 7/8 25 3/8
* Based on New York Stock Exchange Composite Transactions as reported in the Wall Street Journal.
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.
Information regarding GPU's directors is incorporated by reference to pages 2 through 5 of GPU's Proxy Statement for the 1994 Annual Meeting of Stockholders.
GPU's executive officers, 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, President and 1992 Chief Executive Officer I. H. Jolles (b) 55 Senior Vice President & 1990 General Counsel J. G. Graham (c) 55 Senior Vice President & 1987 Chief Financial Officer F. A. Donofrio (d) 51 Vice President, Comptroller 1985 & Chief Accounting Officer P. C. Mezey (e) 54 Senior Vice President, GPUSC 1992 D. W. Myers (f) 49 Vice President & Treasurer 1993 M. A. Nalewako (g) 59 Secretary 1988 P. R. Clark (h) 63 President, GPUN 1983 R. L. Wise (i) 50 President, Penelec 1986 F. D. Hafer (j) 52 President, Met-Ed 1986 D. Baldassari (k) 44 President, JCP&L 1992 R. C. Arnold (l) 56 Executive Vice President, GPUSC 1990
(a) Mr. Leva 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 JCP&L, Met-Ed, Penelec and GPC, and Chairman of the Board and a director of GPUN. Prior to assuming his present positions, Mr. Leva served as President of JCP&L since 1986.
(b) Mr. Jolles became Senior Vice President and General Counsel of GPU in 1990. He is also Executive Vice President, General Counsel and a director of GPUSC. He was previously a partner in the law firm of Berlack, Israels & Liberman.
(c) 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 JCP&L, Met-Ed and Penelec; Vice President and Chief Financial Officer of GPUN; President and a director of GPC and a director of EI.
(d) Mr. Donofrio became a Vice President of GPU in 1989, and in 1985 he became Comptroller and Chief Accounting Officer of GPU. He is also Senior Vice President - Financial Controls of GPUSC and a director of GPUSC, GPC and EI.
(e) Mr. Mezey became Senior Vice President - System Services of GPUSC in 1992. He previously served as Vice President of GPUSC from January 1991 through March 1992 and President of EI from February 1990 through December 1991. Prior to joining GPU, he was Vice President - Finance and CFO of Edgcore Technology.
(f) Mr. Myers became a Vice President and Treasurer of GPU in 1993. He is also Vice President and Treasurer of GPUSC, JCP&L, Met-Ed, Penelec, GPUN and GPC. Prior to assuming his present positions, Mr. Myers served as Vice President and Comptroller of GPUN since 1986.
(g) Mrs. Nalewako became Secretary of GPU, GPUSC and GPC in 1988. She is also Assistant Secretary of GPUN, JCP&L, Met-Ed and Penelec.
(h) Mr. Clark was elected President of GPUN in 1983. He was elected a director of GPUN in 1980 and served as Executive Vice President from 1980 to 1983. He was designated Chief Executive Officer of GPUN in 1984.
(i) Mr. Wise became President and a director of Penelec in December 1986. He is also a director of GPUSC and GPUN.
(j) Mr. Hafer became President of Met-Ed in March 1986. He is also a director of Met-Ed, GPUSC and GPUN.
(k) Mr. Baldassari became President of JCP&L and a director of GPUSC and GPUN in February 1992. Prior to assuming his present positions, Mr. Baldassari served as Vice President - Rates and a director of JCP&L since 1982. He also served as Vice President - Materials and Services of JCP&L since 1990, and as Treasurer of JCP&L from October 1979 through December 31, 1989.
(l) Mr. Arnold became Executive Vice President-Power Supply of GPUSC in 1990. He was Senior Vice President-Power Supply from 1987 to 1989. He is also a director of GPUSC, JCP&L, Met-Ed and Penelec.
The executive officers of the GPU System are elected each year by their respective Boards of Directors at the first meeting of the Board held following the annual meeting of stockholders. Executive officers hold office until the next meeting of directors following the annual meeting of stockholders and until their respective successors are duly elected and qualified. There are no family relationships among GPU's executive officers.
Section 16(a) of the Securities Exchange Act of 1934 requires the Corporation's executive officers and directors, and persons who beneficially own more than ten percent of the Corporation's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission and the New York Stock Exchange. Officers, directors and greater than ten-percent shareholders are required by SEC regulation to furnish the Corporation with copies of all Section 16(a) forms they file.
Based on its review of the copies of such forms received by it, or written representations from these reporting persons, the Corporation believes that, during 1993 all such filing requirements applicable to its officers and directors (the Corporation not being aware of any ten percent holder) were complied with, with the exception that a report relating to one transaction involving the redemption by Pennsylvania Electric Company of shares of its cumulative preferred stock owned by Mr. Appell's wife was filed five days late.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated by reference to pages 9 through 18 of GPU's Proxy Statement for the 1994 Annual Meeting of Stockholders.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item is incorporated by reference to page 8 of GPU's Proxy Statement for the 1994 Annual Meeting of Stockholders.
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 GPUN By-Laws, as amended.
10-A General Public Utilities Corporation Restricted Stock Plan for Outside Directors
10-B 1990 Stock Plan for Employees of General Public Utilities Corporation and Subsidiaries
10-C Form of Restricted Units Agreement under the 1990 Stock Plan.
10-D Retirement Plan for Outside Directors of General Public Utilities Corporation.
10-E Incentive Compensation Plan for Officers of GPU System Companies.
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.
GENERAL PUBLIC UTILITIES CORPORATION
Dated: March 10, 1994 BY: /s/ J. R. Leva J. R. Leva, Chairman and 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 (Chief Executive Officer) President and Director
/s/ J. G. Graham March 10, 1994 J. G. Graham, Senior Vice President (Chief Financial Officer)
/s/ F. A. Donofrio March 10, 1994 F. A. Donofrio, Vice President and Comptroller (Chief Accounting Officer)
/s/ L. J. Appell, Jr. March 10, 1994 L. J. Appell, Jr., Director
/s/ D. J. Bainton March 10, 1994 D. J. Bainton, Director
/s/ T. H. Black March 10, 1994 T. H. Black, Director
/s/ T. B. Hagen March 10, 1994 T. B. Hagen, Director
/s/ H. F. Henderson, Jr. March 10, 1994 H. F. Henderson, Jr., Director
/s/ J. M. Pietruski March 10, 1994 J. M. Pietruski, Director
/s/ C. A. Rein March 10, 1994 C. A. Rein, Director
/s/ P. R. Roedel March 10, 1994 P. R. Roedel, Director
/s/ C. A. H. Trost March 10, 1994 C. A. H. Trost, Director
/s/ P. K. Woolf March 10, 1994 P. K. Woolf, Director
GENERAL PUBLIC UTILITIES CORPORATION
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Supplementary Data Page
System 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
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
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.
General Public Utilities Corporation and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1993, earnings per share were $2.65 compared to $2.27 per share in 1992 and net income increased $44.0 million to $295.7 million. The increase in earnings was principally due to additional revenues resulting from a February 1993 retail base rate increase at JCP&L and higher customer sales due primarily to the significantly warmer-than-normal summer temperatures as compared with the mild weather in 1992. These gains were partially offset by an increase in operation and maintenance expense, the write-off of $25 million of costs related to the cancellation of proposed energy-related agreements, and increased depreciation expense associated with additions to utility plant. In June 1993, GPU increased its quarterly common stock dividend by 6.3% to $0.425 per share. GPU's return on average common equity was 11.9% for 1993 as compared to 10.7% for 1992.
Net income for 1992 was $251.6 million, or $2.27 per share, compared to $275.9 million, or $2.49 per share in 1991. Earnings in 1992 were primarily affected by a reduction in weather-related sales and increased capital costs, partially offset by increased revenues from new residential and commercial customers. In 1991, increased revenues due to warmer-than-normal summer weather, the effect of a base rate increase at JCP&L and an increase in customer additions were substantially offset by higher reserve capacity expense and capital costs.
OPERATING REVENUES:
Revenues increased 4.7% to $3.6 billion in 1993 after increasing 1.9% to $3.4 billion in 1992. The components of these changes are as follows:
(In Millions) 1993 1992
Kilowatt-hour (KWH) revenues $ 61.0 $(29.9) (excluding energy portion) Rate increases 108.7 - Energy revenues (24.1) 72.5 Other revenues 16.3 20.0 Increase in revenues $161.9 $ 62.6
Kilowatt-hour revenues
KWH revenues increased principally due to higher third quarter sales in the JCP&L service territory resulting from the significantly warmer-than- normal summer temperatures as compared to the milder weather during the same
General Public Utilities Corporation and Subsidiary Companies
period in 1992. An increase in weather-related sales in the Met-Ed service territory, a 1.2% increase in the average number of customers and a slight increase in nonweather-related usage also contributed to the increase in KWH revenues. New customer growth, which occurred in the commercial and residential sectors, was partially offset by a slight reduction in the number of industrial customers.
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 1.2% increase in the average number of customers and a slight increase in nonweather-related usage. New customer growth mostly occurred in the JCP&L service territory in the residential and commercial sectors. The increase in nonweather-related usage was reflected primarily in the residential and commercial sectors in the JCP&L and Met-Ed service territories, while the dampening effects of the economy continued to impact customer usage in the Penelec service territory.
Customer Sales by Service Class
1988 1989 1990 1991 1992 1993
In millions of MWH 38.4 38.5 38.7 39.6 39.3 40.3 Industrial and Other 36% 35% 35% 34% 33% 32% Commercial 29% 30% 30% 31% 32% 32% Residential 35% 35% 35% 35% 35 36
Rate increases
In February 1993, the New Jersey Board of Regulatory Commissioners (NJBRC) authorized a $123 million increase in JCP&L retail base rates, or approximately 7% annually.
Energy revenues
1993 and 1992 Changes in energy revenues do not affect net income as they reflect corresponding changes in the energy cost rates billed to customers and expensed. The 1993 decrease in energy revenues is principally due to lower electric sales to other utilities as compared to 1992 when the GPU System experienced a significant increase in sales to other utilities. Energy revenues also increased in 1992 as a result of increases in the energy cost rates in effect.
General Public Utilities Corporation and Subsidiary Companies
Other revenues
1993 and 1992 Generally, changes in other revenues do not affect net income as they are offset by corresponding changes in expense, such as taxes other than income taxes. However, earnings in 1993 were favorably affected by a one- time benefit from the recognition of prior period transmission service revenues approved by the Pennsylvania Public Utility Commission (PaPUC). Other revenues increased in 1992 as a result of a timing difference in the receipt of Pennsylvania tax surcharge revenues received during the year for state tax increases enacted in the third quarter of 1991.
OPERATING EXPENSES:
Power purchased and interchanged
1993 and 1992 Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings as they are substantially recovered through the Subsidiaries' energy clauses. Earnings in 1993, however, were favorably impacted by a reduction in reserve capacity expense primarily resulting from the expiration of a purchase contract with another utility. Power purchased and interchanged increased in 1992 as a result of an increase in nonutility generation purchases offset partially by a reduction in purchases from other utilities.
Other operation and maintenance
Other operation and maintenance (O&M) expense increased primarily due to emergency and storm-related activities, higher than normal tree trimming expenses and increased costs related to fossil plant outages.
The decrease is due largely to the absence of $33.8 million of estimated costs recognized in 1991 for preparing the TMI-2 plant for long-term monitored storage. Excluding that amount, other O&M expense remained relatively stable.
Depreciation and amortization
1993 and 1992 Depreciation and amortization expense increased $20.2 million and $10.8 million, respectively, in 1993 and 1992 mostly due to additions to utility plant, exclusive of a $60 million charge in 1991 for certain TMI-2 decommissioning costs. Additions to utility plant primarily consist of additions to existing generating facilities to enhance system reliability and additions to the transmission and distribution system related to new customer growth.
General Public Utilities Corporation and Subsidiary Companies
Taxes, other than income taxes
1993 and 1992 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
The reduction in other income, net is principally due to the write-off of $25 million of costs related to the cancellation of proposed power supply and transmission facilities agreements between the Subsidiaries and Duquesne Light Company (Duquesne). The decrease is also due to the absence of carrying charges on certain tax payments made by JCP&L in 1992 which are now being recovered through rates.
The decrease is mainly attributable to a reduction in interest income resulting from the 1991 collection of federal income tax refunds, offset partially by an increase in other income related to the anticipated recovery of carrying charges.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
1993 and 1992 Interest on long-term debt increased in both years 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 in 1993 and 1992. The decrease in other interest in 1992 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. Other interest in 1992 also declined due to a reduction in the average level of short-term borrowing outstanding. Preferred dividends decreased in 1993 primarily due to the redemption of $156 million of preferred stock.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The GPU System's capital needs were $525 million in 1993, consisting of cash construction expenditures of $496 million and amounts for maturing obligations of $29 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. Construction expenditures are estimated to be $663 million in 1994, consisting mainly of $485 million for ongoing system development and $120 million for clean air requirements. Expenditures for maturing debt are expected to be $133 million for 1994 and $91 million for 1995. In the mid 1990s, construction expenditures may include substantial amounts for clean air requirements, the construction of new
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generation facilities and other system needs. Management estimates thatapproximately one-half of the GPU System's 1994 capital needs will be satisfied through internally generated funds.
The Subsidiaries' 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 TMI-1) of nuclear fuel costs may be outstanding at any one time. Nuclear fuel capital leases at December 31, 1993 totaled $150 million. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $60 million annually. In the event these nuclear fuel needs cannot be leased, the associated capital requirements would have to be met by other means.
Cash Construction Expenditures (In millions of dollars)
1989 1990 1991 1992 1993 1994
$487 $491 $467 $460 $496 $663*
* Forecast
FINANCING:
In 1993, the Subsidiaries refinanced higher cost long-term debt in the principal amount of $723 million resulting in an estimated annualized after- tax savings of $6 million. Total GPU System long-term debt issued during 1993 amounted to $957 million. In addition, the Subsidiaries redeemed $156 million of high-dividend rate preferred stock issues.
During 1993, GPU sold four million shares of common stock at $33 1/8 per share through an underwritten public offering. The net proceeds of $128.7 million were used primarily to reimburse the Subsidiaries for the preferred stock redemptions.
In January 1994, Penelec issued an aggregate of $90 million of first mortgage bonds, of which a portion of the net proceeds will be used to redeem $38 million principal amount of 6 5/8% series bonds in late February 1994. Met-Ed issued, in February 1994, an aggregate of $50 million of first mortgage bonds, of which a portion of the net proceeds will be used to redeem $26 million principal amount of 7% series bonds in March 1994.
The Subsidiaries have regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock for various periods through 1995. Under existing authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the amount of $275 million, $250 million and $330 million, respectively, of which $100 million for each Subsidiary may consist of preferred stock. The Subsidiaries also have regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
General Public Utilities Corporation and Subsidiary Companies
The GPU System's cost of capital and ability to obtain external financing is affected by the Subsidiaries' security ratings, which continue to remain above minimum investment grade. The Subsidiaries' first mortgage bonds are currently rated at an equivalent of either an A or A- rating by the three major credit rating agencies, while an equivalent of either an A- or BBB+ rating is assigned to the preferred stock issues. In addition, the Subsidiaries' commercial paper is rated as having good to high 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 the 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 JCP&L, which moved from "A-stable" to "A-negative", meaning their credit ratings may be lowered. JCP&L 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. Met-Ed and Penelec were both classified as having "average" business risk positions. 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 Subsidiaries' bond indentures and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Subsidiaries may issue. The Subsidiaries' interest and preferred 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. Present plans call for the Subsidiaries 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 GPU System 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 45-48% 47% 46% 46% Preferred stock 8-10 5 9 9 Notes payable and long-term debt 47-42 48 45 45 100% 100% 100% 100%
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The sale of GPU common stock in 1993 was used primarily to reimburse the Subsidiaries for preferred stock redemptions. Management believes these actions strengthened GPU's capital structure by increasing common equity without increasing the overall cost of capital or diluting shareholder earnings. Recent evaluations of the industry by credit rating agencies indicate that the Subsidiaries may have to increase their equity ratios to maintain their current credit ratings.
In 1993, the quarterly dividend on common stock was increased by 6.3% to an annualized rate of $1.70 per share. In addition, GPU set a target payout ratio of 70-75% to be reached over the next few years. GPU will continue to review its dividend policy to determine how to best serve the long-term interests of shareholders.
NONUTILITY BUSINESS:
General Portfolios Corporation (GPC) was organized to make investments apart from the businesses of the Subsidiaries. Currently, these are conducted by Energy Initiatives, Inc. (EI), a subsidiary of GPC, and its subsidiaries. EI is in the business of developing, operating and investing in cogeneration and other nonutility power production facilities. As of December 31, 1993, EI had five combined-cycle cogeneration plants in service aggregating 223 MW of capacity and an option to acquire a 20% equity interest in projects having an additional 350 MW of capacity.
As a result of the federal Energy Policy Act of 1992 (Energy Act), EI has expanded its business activities to include development of exempt wholesale generating facilities in both the domestic and limited international markets.
In 1993, EI entered into an agreement to invest up to $8.5 million over the next four years to acquire a 29% equity interest in a private independent power development company, which has commitments or prospects to provide more than 200 MW of electricity to utilities in Canada and plans to develop other projects in the United States. EI also obtained the right to invest in and operate several of the projects. In addition, EI has been active as a bidder and has proposals pending for the development of additional capacity in the United States. EI is also pursuing international development projects in Latin America while investigating other international opportunities.
At December 31, 1993, GPU's investment in GPC was $39 million. GPU intends to make additional investments in the development and ownership of nonutility generating facilities in an effort to expand these business activities. The timing and amounts of these investments, however, will depend upon the development of appropriate opportunities. GPU does not expect investments apart from these activities to be a major part of its business activities.
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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, 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 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 Subsidiaries, 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 several existing GPU System wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of Met-Ed or JCP&L. Penelec has made similar offers to certain wholesale customers now being served by other utilities. Although wholesale customers represent a relatively small portion of GPU System sales, the Subsidiaries will continue their efforts to retain and add customers by offering competitive rates.
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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, JCP&L 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, JCP&L 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 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 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 Pennsylvania) 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
General Public Utilities Corporation and Subsidiary Companies
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 GPU System'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 GPU System 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 GPU, exploring opportunities and risks, and defining and evaluating strategic alternatives.
Management is now analyzing issues associated with various competition 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 Subsidiaries. It is also intended to combine the remaining Met-Ed and Penelec operations without merging the two companies. GPU 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.
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MEETING ENERGY DEMANDS:
The Subsidiaries have a projected need, due in large part to peak load growth, of 644 MW of additional capacity by the year 1998 based on an average growth in sales to customers of about 1.7% annually, with growth rates for the Subsidiaries projected from 1.1% to 2.3%. GPU intends to provide for this increased energy need through a mix of economic sources. Current and projected capacity and sources of energy are as follows:
Capacity 1993 1998 MW % MW % Coal 3,022 30 3,040 29 Nuclear 1,396 14 1,406 13 Gas, hydro & oil 2,321 23 2,605 24 Contracted purchases 3,233 33 3,034 29 Uncommitted sources - - 531 5 Total 9,972 100 10,616 100
Sources of Energy 1993 1998 GWH % GWH % Coal 16,969 35 17,949 35 Nuclear 10,614 22 9,766 19 Gas, hydro & oil 575 1 1,177 2 Contracted purchases 14,717 30 18,103 36 Uncommitted sources & interchange 5,650 12 4,233 8 Total 48,525 100 51,228 100
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. Through 1998, GPU's plan consists of the continued utilization of existing generating facilities combined with power purchases, the construction of new facilities, and the continued promotion of economic energy conservation and load management programs. Given the future direction of the industry, GPU'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 GPU System will resist efforts to compel it to add new capacity at costs that may exceed future market prices. In addition, GPU 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 GPU System's supply plan includes the addition of 1,259 MW of presently contracted capacity by 1998 from nonutility generation suppliers and reflects the construction of new peaking units. The supply plan also includes the addition of 531 MW of currently uncommitted capacity, which may be filled
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by a combination of utility and nonutility purchases as well as company owned facilities. Additions are principally related to the expiration of existing commitments rather than to serve new customer load.
In July 1993, the PaPUC acted to initiate a rulemaking proceeding which, in general, would establish a mandatory all source competitive bidding program by which utilities would meet their future capacity and energy needs. Also in July, a 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. JCP&L 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 JCP&L and the developer to negotiate contract repricing to a level more consistent with JCP&L'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 JCP&L, a one-year extension in the in-service date for projects originally scheduled to be operational in 1997. JCP&L is awaiting a final written NJBRC order.
Also in November 1993, JCP&L received approval from the NJBRC to withdraw its request for proposals for the purchase of 150 MW from nonutility generators. In its petition, JCP&L cited, among other reasons, that solicitations for long-term contracts would have limited its ability to compete in a deregulated environment.
In November 1993, Penelec filed an appeal with the Commonwealth Court seeking to overturn a PaPUC order which directs Penelec to enter into two power purchase agreements with nonutility generators for a total of 160 MW under long-term contracts commencing in 1997 or later. Penelec does not need this additional capacity and believes the costs associated with these contracts are not in the economic interests of its customers.
JCP&L and Met-Ed have entered into arrangements for two peaking generation projects. JCP&L 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. JCP&L expects to complete the project by 1996. Met-Ed has filed an application with the PaPUC for approval to build a 134 MW gas-fired combustion turbine adjacent to its Portland Generating Station at a cost of $50 million. The application has been opposed by a nonutility generator seeking to sell Met-Ed an equivalent amount of baseload capacity.
In December 1993, the NJBRC denied JCP&L's petition to participate in the proposed power supply and transmission facilities agreements between the Subsidiaries and Duquesne. As a result of this action and other developments, the Subsidiaries notified Duquesne that they were exercising their rights
General Public Utilities Corporation and Subsidiary Companies
under the agreements to withdraw from and thereby terminate the agreements. The capital costs of these transactions would have totaled approximately $500 million.
In January 1994, JCP&L 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. JCP&L 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. This solicitation is expected to fulfill a significant part of the uncommitted sources identified in GPU's supply plan.
Conservation and Load Management
The regulatory environments in both New Jersey and Pennsylvania encourage 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 and recent approval of a cost recovery mechanism for DSM in Pennsylvania. 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).
In New Jersey, the NJBRC approved JCP&L'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 JCP&L can also earn a performance-based incentive for successfully implementing cost effective programs. In addition, JCP&L will continue to make certain NJBRC mandated Core Program DSM investments which are recovered annually.
The PaPUC has recently completed its generic investigation into DSM cost recovery mechanisms and issued a cost recovery and ratemaking order in December 1993. Penelec and Met-Ed are currently developing plans which will reflect changes since their original plans were filed in 1991. New targets for DSM initiatives are currently being determined and will be identified when the new DSM plans are filed in the first quarter of 1994.
ENVIRONMENTAL ISSUES:
The GPU System 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 GPU System through the late 1990s.
The Clean Air Act will require substantial reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000. The GPU System's current plan includes installing and operating emission control equipment at some of the Subsidiaries' coal-fired plants as well as switching to lower sulfur coal at other coal-fired plants. To comply with the Clean Air Act, the GPU System
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control equipment. GPU reviews its plans and alternatives to comply with the expects to expend up to $590 million by the year 2000 for air pollutionClean 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. GPU may be able to defer sub- stantial 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 stations 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 consolidated 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 GPU and the Subsidiaries and are still pending. For more information, see Note 1 to the consolidated financial statements.
EFFECTS OF INFLATION:
The GPU System 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 GPU and the utility industry attempt to keep rates competitive.
Inflation also affects the GPU System in the form of higher replacement costs of utility plant. In the past, GPU 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 GPU System 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 debt levels and capital costs.
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 shareholders' equity. The impact on the GPU System'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.
General Public Utilities Corporation and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors General Public Utilities Corporation Parsippany, New Jersey
We have audited the consolidated financial statements and financial statement schedules of General Public Utilities Corporation and Subsidiary Companies as listed in the index on page of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Corporation'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 consolidated financial position of General Public Utilities Corporation and Subsidiary Companies as of December 31, 1993 and 1992, and the consolidated results of their operations and their 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 consolidated 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 the consolidated financial statements, the Corporation is unable to determine the ultimate consequences of certain contingencies which have resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The matters which remain uncertain are (a) the extent to which the retirement costs of TMI-2 could exceed amounts currently recognized for ratemaking purposes or otherwise accrued, and (b) 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 6 and 8 to the consolidated financial statements, the Corporation 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 consolidated financial statements, the Corporation changed its method of accounting for unbilled revenues in 1991.
COOPERS & LYBRAND New York, New York February 2, 1994
General Public Utilities Corporation and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Public Utilities Corporation (the Corporation) is a holding company registered under the Public Utility Holding Company Act of 1935. The Corporation does not directly operate any utility properties, but owns all the outstanding common stock of three electric utilities -- Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec) (the Subsidiaries). The Corporation also owns all the common stock of GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc., which develops, owns and operates nonutility generating facilities. All of these companies considered together with their subsidiaries are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Subsidiaries have made investments in three major nuclear projects -- Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. At December 31, 1993, the Subsidiaries' net investment in TMI-1 and Oyster Creek, including nuclear fuel, was $670 million and $784 million, respectively. TMI-1 and TMI-2 are jointly owned by JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by JCP&L.
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 GPU System may also incur costs and experience reduced output at its 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.
General Public Utilities Corporation and Subsidiary Companies
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 the Corporation and the Subsidiaries. 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 GPU System.
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 Subsidiaries submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Subsidiaries intend to complete the funding for Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1993 dollars) for TMI-1 and Oyster Creek
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are $143 million and $175 million, respectively. Based on NRC studies, a comparable funding target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 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 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 and $47 million, respectively.
The ultimate cost of retiring the GPU System's nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies 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 Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Subsidiaries have contributed to external trusts amounts written off for nuclear plant decommissioning in 1990 and 1991.
TMI-1 and Oyster Creek:
JCP&L is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. JCP&L is also collecting revenues based on estimates, adopted in rate orders issued in 1991 and 1993 by the New Jersey Board of Regulatory Commissioners (NJBRC), for the cost of removal of nonradiological structures and materials at each plant based on its share of an estimated $15.3 million for TMI-1 and $31.6 million for Oyster Creek. In January 1993, the Pennsylvania Public Utility Commission (PaPUC) granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site-specific study. Effective October 1993, the PaPUC approved a rate change for Penelec which increased the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for
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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 $29 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 Corporation and its Subsidiaries have recorded a liability amounting to $229 million as of December 31, 1993, for the radiological decommissioning of TMI-2, reflecting the NRC funding target. The Subsidiaries record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Subsidiaries have also recorded a liability in the amount of $20 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 Subsidiaries have recorded a liability in the amount of $71 million for 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. JCP&L has made a nonrecoverable contribution of $15 million to an external decommissioning trust. Met-Ed and Penelec have made nonrecoverable contributions of $40 million and $20 million, respectively, to external decommissioning trusts relating to their shares of the accident-related portion of the decommissioning liability.
The NJBRC and the PaPUC have granted JCP&L and Met-Ed, respectively, decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. In March 1993, a PaPUC rate order for Met-Ed allowed for the future recovery of certain TMI-2 retirement costs. The recovery of these TMI-2 retirement costs will begin when the amortization of the TMI-2 investment ends, at the same annual amount ($6.3 million for recovery of radiological decommissioning and $2.0 million for nonradiological cost of removal, net of gross receipts tax). In May 1993, the Pennsylvania Office of Consumer Advocate filed a petition for review with the Pennsylvania Commonwealth Court seeking to set aside the PaPUC's 1993 rate order. The matter is pending before the court. If the 1993 rate order is reversed, Met-Ed and Penelec would be required to write off a total of approximately $170 million for retirement costs. Penelec intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. 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 Subsidiaries will incur currently estimated incremental annual storage costs of $1 million. The Subsidiaries have deferred the $20 million for the total estimated incremental
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costs attributable to monitored storage. The JCP&L share of these costs has been recognized in rates by the NJBRC. Met-Ed and Penelec believe these costs should be recoverable through the ratemaking process.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station (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 for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of 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 GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years at decreasing levels beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1, per week.
Under its insurance policies applicable to nuclear operations and facilities, the GPU System is subject to retrospective premium assessments of up to $52 million in any one year, in addition to those payable under the Price-Anderson Act.
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ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the GPU System may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles, 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. 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 GPU System expects to expend up to $590 million for air pollution control equipment by the year 2000. Costs associated with the capital invested in this equipment and the increased operating costs of the affected stations should be recoverable through the ratemaking process.
The GPU System companies have been notified by the Environmental Protection Agency (EPA) and state environmental authorities that they are among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at ten hazardous and/or toxic waste sites. In addition, the GPU System companies have been requested to supply information to the EPA and state environmental authorities on several other sites for which they have not yet been named as PRPs. The Subsidiaries have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the GPU System companies.
JCP&L 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 JCP&L. JCP&L has also entered into various cost sharing agreements with other utilities for some of the sites. At December 31, 1993, JCP&L 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
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the remediation is currently expected to be performed are lengthened, JCP&L believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties as JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In June 1993, the NJBRC approved a mechanism for the recovery of future manufactured gas plant remediation costs through JCP&L'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. JCP&L is currently awaiting a final NJBRC order. JCP&L 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 GPU System companies are unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant. 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, JCP&L 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 JCP&L 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.
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JCP&L'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. At the request of the PaPUC, Met-Ed and Penelec, as well as the other Pennsylvania utilities, have supplied the PaPUC with proposals which may result in the PaPUC adopting a generic nuclear performance standard in the future.
In December 1993, the NJBRC denied JCP&L's request to participate in the proposed power supply and transmission facilities agreements between the Subsidiaries and Duquesne Light Company (Duquesne). As a result of this action and other developments, the Subsidiaries notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Subsidiaries wrote off the $25 million they had invested in the project.
The GPU System's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $663 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 GPU System's financial statements reflect assets and costs based on current cost- based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
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c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the GPU System's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed. Management believes that to the extent that the GPU System no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Subsidiaries have entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which they have ownership interests. The contracts, which expire between 1994 and the end of the expected service lives of the generating stations, require the purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal is determined by formulas providing for the recovery by the mining companies of their costs of production. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $89 million for 1994.
The Subsidiaries 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.
The Subsidiaries have 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 Subsidiaries to purchase all of the
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power produced up to the contract limits. The agreements have been approved by the state regulatory commissions and permit the Subsidiaries to recover energy and demand costs from customers through their energy clauses. These agreements provide for the sale of approximately 2,452 MW of capacity and energy to the GPU System by the mid-to-late 1990s. As of December 31, 1993, facilities covered by these agreements having 1,193 MW of capacity were in service, and 215 MW were scheduled to commence operation in 1994. Payments made pursuant to these agreements were $491 million, $471 million and $343 million for 1993, 1992 and 1991, respectively, and are estimated to aggregate $551 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 Subsidiaries have been granted full recovery of these costs from customers by the state commissions, there can be no assurance that the Subsidiaries 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 System's energy supply needs which, in turn, has caused the Subsidiaries to change their supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Subsidiaries 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 Subsidiaries may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before both the NJBRC and the PaPUC, as well as to litigation, and may result in claims against the Subsidiaries for substantial damages. There can be no assurance as to the outcome of these matters.
During the normal course of the operation of their businesses, in addition to the matters described above, the GPU System companies are from time to time involved in disputes, claims and, in some cases, as defendants in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these matters will have a material effect on the GPU System's financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS
The consolidated financial statements include the accounts of all subsidiaries. Certain reclassifications of prior years' data have been made to conform with current presentation. The Subsidiaries' accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the PaPUC and NJBRC.
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REVENUES
The Corporation and its Subsidiaries recognize 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 GPU System 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 GPU System 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 Subsidiaries used depreciation rates which, on an aggregate composite basis, resulted in annual rates of 3.19%, 3.17% and 3.20% 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 6.80%, 7.33% and 8.39% for the years 1993, 1992 and 1991, respectively.
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AMORTIZATION POLICIES
Accounting for TMI-2 and Forked River Investments: JCP&L 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 2008. In its 1993 base rate decision, the PaPUC reduced Met-Ed's annual retail revenues for the amortization of the TMI-2 investment to $8.3 million, a level sufficient for Met-Ed to recover its remaining investment in TMI-2 in 1994. Penelec has collected all of its TMI- 2 investment attributable to its retail customers. At December 31, 1993, $97 million is included in Unamortized Property Losses on the balance sheet for JCP&L's Forked River project. JCP&L 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 Subsidiaries have not been provided revenues for a return on the unamortized balances 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 Subsidiaries have 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 $47 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 Subsidiaries made their initial payment to this fund in 1993. The Subsidiaries have recorded an asset for remaining amounts recoverable from ratepayers of $48 million at December 31, 1993 in Deferred Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS
The GPU System accrues incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE
The Subsidiaries are 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 Subsidiaries entered into contracts in 1983
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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 $147 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 Subsidiaries have reflected such excess of $25 million at December 31, 1993 in Deferred Debits and Other Assets - Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over remaining periods of 13 years for JCP&L, 14 years for Met-Ed and 4 years for Penelec.
The Subsidiaries are collecting 1 mill per kilowatt-hour from their 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, which may be assessed against the group.
Deferred income taxes, which result primarily from liberalized depreciation methods, deferred energy costs, decommissioning funds and discounted Forked River and TMI-2 investments, 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 GPU System 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 consolidated 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 GPU System had $216 million of short-term notes outstanding, of which $37 million was commercial paper and the remainder was issued under bank lines of credit (credit facilities).
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The Corporation and the Subsidiaries 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. LONG-TERM DEBT
At December 31, 1993, the Corporation's subsidiaries had long-term debt outstanding, as follows:
Interest Rates 4 5/8% to 7% to 9% to Maturities 6.97% 8 7/8% 10 1/2% Total
(In Thousands) First mortgage bonds: 1994-2003 $555,005 $ 410,191 $188,500 $1,153,696 2004-2013 145,120 338,300 - 483,420 2014-2023 55,000 517,200 50,000 622,200 2025 150,000 - - 150,000 Total $905,125 $1,265,691 $238,500 2,409,316
Amounts due within one year (130,000) Total 2,279,316
Other long-term debt (net of $3,232 due within one year) 46,204 Unamortized net discount (5,136) Total $2,320,384
The above amounts do not include $125 million of 10 1/8 % first mortgage bonds as a result of depositing with the trustee, in 1993, an amount needed for their early redemption in April 1994. For the years 1994, 1995, 1996, 1997 and 1998, the Subsidiaries have long-term debt maturities of $133 million, $91 million, $119 million, $145 million and $103 million, respectively. Substantially all of the utility plant owned by the Subsidiaries is subject to the lien of their respective mortgages.
The estimated fair value of the Corporation's long-term debt, as of December 31, 1993 and 1992 is as follows:
(In Thousands) Carrying Fair Amount Value
1993 $2,320,384 $2,446,407 1992 2,221,617 2,304,701
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The fair value of the Corporation's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Corporation for debt of the same remaining maturities.
5. CAPITAL STOCK
COMMON STOCK
The following table presents information relating to the common stock ($2.50 par value) of the Corporation:
1993 1992
Authorized shares 150,000,000 150,000,000 Issued shares 125,783,338 125,783,338 Reacquired shares 10,816,561 14,965,309 Outstanding shares 114,966,777 110,818,029 Restricted units 74,076 38,816
In 1993, the Corporation sold four million shares of common stock through an underwritten public offering. In 1993 and 1992, pursuant to the 1990 Restricted Stock Plan, the Corporation issued to officers restricted units representing rights to receive shares of common stock, on a one-for-one basis, at the end of the restriction period. The restricted units do not affect the issued and outstanding shares of common stock until conversion at the end of the restriction period. However, the restricted units are considered common stock equivalents and therefore are included in average common shares outstanding for the earnings per share computation on the income statement. The restricted units accrue dividends on a quarterly basis. In 1993 and 1992, the Corporation awarded to plan participants 32,740 and 39,735 restricted units, respectively. In 1993, 1992 and 1991, the Corporation issued a total of 3,200, 3,053 and 39,600 restricted shares, respectively, from previously reacquired shares. No shares of common stock were reacquired in 1993, 1992 or 1991. The Corporation has standby authorization from the Securities and Exchange Commission to repurchase up to five million shares of common stock through 1995.
PREFERRED STOCK
At December 31, 1993, the Subsidiaries had the following issues of cumulative preferred stock outstanding:
General Public Utilities Corporation and Subsidiary Companies
Stated Value Shares (In Thousands) Series per Share Outstanding Stated Value
With mandatory redemption:
7.52% - 8.65% $100 1,500,000 $150,000
Without mandatory redemption:
3.70% - 4.70% $100 723,912 $ 72,391 7.68% - 8.36% $100 850,000 85,000 Total 1,573,912 157,391 Premium 851 Total $158,242
During 1993, the Subsidiaries redeemed preferred stock as follows: JCP&L redeemed all of its outstanding 8.12% Series and 8% Series cumulative preferred stock (aggregate stated value of $50 million) at a total cost of $52.4 million. Met-Ed redeemed all of its outstanding 8.32% Series H, 8.32% Series J, 8.12% Series I and its 8.12% cumulative preferred stock (aggregate stated value of $81 million) at a total cost of $85.3 million. Penelec redeemed all of its outstanding 8.12% Series I cumulative preferred stock (aggregate stated value of $25 million) at a total cost of $26.0 million. These redemptions resulted in a net $6.9 million charge to Retained Earnings.
During 1992, JCP&L issued 500,000 shares of 7.52% series cumulative preferred stock with mandatory redemption provisions. The series is callable beginning in the year 2002 at various prices above its stated value. The series is to be redeemed ratably over twenty years beginning in the year 1998. This issue provides that JCP&L may, at its option, redeem an amount of shares equal to its mandatory sinking fund requirement at such time as the mandatory sinking fund redemption is made. Expenses of $0.5 million incurred in connection with the issuance of the cumulative preferred stock were charged to Capital Surplus on the balance sheet.
During 1992, JCP&L redeemed all its outstanding 8.75% Series H cumulative preferred stock (aggregate stated value of $50 million), at a total cost of $51.6 million. This resulted in a $1.6 million charge to Retained Earnings. Additional preferred stock expenses of $0.7 million were charged to Retained Earnings.
During 1991, Penelec redeemed all its outstanding 9% Series L cumulative preferred stock (aggregate stated value of $35 million), at a total cost of $36.4 million. This resulted in a $1.4 million charge to Retained Earnings.
The issued and outstanding shares of preferred stock without mandatory redemption are callable at various prices above their stated values. At December 31, 1993, the aggregate amount at which these shares could be called by the Subsidiaries was $164 million. The issued and outstanding shares with mandatory redemption have aggregate redemption requirements of $32.5 million for the years 1994 through 1998.
General Public Utilities Corporation and Subsidiary Companies
At December 31, 1993 and 1992, the Subsidiaries were authorized to issue 37,035,000 shares of cumulative preferred stock. If dividends on any of the preferred stock of any of the Subsidiaries are in arrears for four quarters, the holders of preferred stock, voting as a class, are entitled to elect a majority of the board of directors of that subsidiary until all dividends in arrears have been paid. A Subsidiary may not redeem preferred stock unless dividends on all of that Subsidiary's preferred stock for all past quarterly dividend periods have been paid or declared and set aside for payment.
6. INCOME TAXES
Effective January 1, 1993, the GPU System 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 $9 million and an increase in the deferred tax liabilities of $48 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 $555 million (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $111 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: Non-current: Revenue taxes $ 12 Liberalized Unbilled revenue 14 depreciation: Deferred energy 6 previously flowed Other 2 through $ 327 Total $ 34 future revenue requirements 228 $ 555 Non-current: Unamortized ITC $111 Liberalized Decommissioning 48 depreciation 726 Contribution in aid Forked River 30 of construction 22 Other 78 Other 94 Total $1,389 Total $275
General Public Utilities Corporation and Subsidiary Companies
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 $296 $252 $276 Preferred stock dividends 29 37 36 Income tax expense 197 174 165 Book income subject to tax $522 $463 $477
Federal statutory rate 35% 34% 34% Effect of difference between tax and book depreciation for which deferred taxes were not provided 2 2 3 Amortization of ITC (2) (3) (3) State tax, net of federal benefit 4 5 3 Other (1) - (2) Effective income tax rate 38% 38% 35%
Federal and state income tax expense is comprised of the following:
(In Millions) 1993 1992 1991
Provisions for taxes currently payable $127 $165 $161
Deferred income taxes: Liberalized depreciation 32 34 36 New Jersey revenue tax 32 3 (7) Deferral of energy costs 6 (16) 5 Accretion income 7 9 11 TMI-2 pre-monitored storage costs 3 8 (14) Other 2 (16) (11) Deferred income taxes, net 82 22 20 Amortization of ITC, net (12) (13) (16) Income tax expense $197 $174 $165
The Internal Revenue Service has completed its examinations of the GPU System's federal income tax returns through 1986. The GPU System and the Internal Revenue Service have reached an agreement to settle the Corporation'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 Corporation estimates
General Public Utilities Corporation and Subsidiary Companies
that the Subsidiaries would receive net refunds totaling $17 million, which would be credited to their customers. The GPU System would also be entitled to receive net interest estimated to total $45 million (before income taxes) through December 31, 1993, which would be credited to income. The years 1987, 1988 and 1989 are currently under audit.
7. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following:
(In Millions) 1993 1992 1991
Maintenance $275 $251 $239 Other taxes: New Jersey unit tax $202 $197 $201 Pennsylvania state gross receipts 68 67 66 Real estate and personal property 21 22 22 Other 53 42 44 Total $344 $328 $333
8. EMPLOYMENT BENEFITS
Pension Plans:
The GPU System maintains defined benefit pension plans covering substantially all employees. The GPU System'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 $ 28.6 $ 26.3 $ 28.2 Interest cost on projected benefit obligation 91.8 87.8 80.0 Less: Expected return on plan assets (96.6) (89.5) (84.3) Amortization (2.2) (2.5) (2.6) Net periodic pension cost $ 21.6 $ 22.1 $ 21.3
The actual return on the plans' assets for the years 1993, 1992 and 1991 were gains of $145.9 million, $53.2 million and $191.3 million, respectively.
General Public Utilities Corporation and Subsidiary Companies
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 $ 982.3 $ 820.6 Nonvested benefits 122.9 93.6 Total ABO 1,105.2 914.2 Effect of future compensation levels 197.2 194.3 Projected benefit obligation (PBO) $ 1,302.4 $ 1,108.5
PBO $(1,302.4) $(1,108.5) Plan assets at fair value 1,288.6 1,167.1 PBO (in excess of) less than plan assets (13.8) 58.6 Less: Unrecognized net (gain) loss 19.8 (56.7) Unrecognized prior service cost (5.9) (12.7) Unrecognized net transition asset (8.6) (9.5) Adjustment required to recognize minimum liability (2.3) - Accrued pension liability $ (10.8) $ (20.3)
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 $122 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. Both the unrecognized prior service cost resulting from retroactive changes in benefits and the unrecognized net transition asset arising out of the adoption of Statement of Financial Accounting Standards No. 87 are being amortized as a credit to pension cost over the average remaining service periods for covered employees.
At December 31, 1993, GPUSC had an accumulated pension obligation in excess of amounts accrued, as a result, an additional minimum liability of $2.3 million was accrued with a corresponding charge to Retained Earnings.
Savings Plans:
The GPU System also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The GPU System's savings plans provide for various levels of matching contributions. The matching contributions for the GPU System for 1993, 1992 and 1991 were $12.2 million, $11.2 million and $9.7 million, respectively.
General Public Utilities Corporation and Subsidiary Companies
Postretirement Benefits Other than Pensions:
The GPU System provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the GPU System. 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 $16.6 million and $16.3 million, respectively.
Effective January 1, 1993, the GPU System 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 GPU System 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 $ 12.5 Interest cost on the accumulated postretirement benefit obligation 34.3 Expected return on plan assets (3.4) Amortization of transition obligation 18.1 Net periodic postretirement benefit cost 61.5 Less, deferred for future recovery (27.5) Postretirement benefit cost, net of deferrals $ 34.0
The actual return on the plans' assets for the year 1993 was a gain of $3.9 million.
The funded status of the plans at December 31, 1993, was as follows:
Accumulated Postretirement Benefit Obligation:
Retirees $ 207.1 Fully eligible active plan participants 72.4 Other active plan participants 223.1 Total accumulated postretirement benefit obligation (APBO) $ 502.6
APBO $(502.6) Plan assets at fair value 47.1 APBO (in excess of) plan assets (455.5) Less: Unrecognized net loss 65.2 Unrecognized prior service cost 2.9 Unrecognized transition obligation 343.6 Accrued postretirement benefit liability $ (43.8)
General Public Utilities Corporation and Subsidiary Companies
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 Discount rate 7.5
The GPU System 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 JCP&L's most recent base rate proceeding, the NJBRC allowed JCP&L 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 (EITF) Issue Number 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises", JCP&L is deferring the amounts above that level. Both Met-Ed and Penelec have begun to defer the incremental postretirement benefit costs, charged to expense, associated with the adoption of FAS 106 and in accordance with EITF Number 92-12 as authorized by the PaPUC in 1993. A portion of the increase in annual costs recognized under FAS 106 of approximately $27.5 million is being deferred and should be recoverable through the ratemaking process. The Consumer Advocate in Pennsylvania is contesting utility deferral of FAS 106 costs in a proceeding involving another utility. The outcome of this proceeding may affect the recovery of deferred FAS 106 costs for Met-Ed and Penelec.
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 $49 million and the aggregate of the service and interest cost components of net postretirement health-care cost for 1994 by approximately $5 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 GPU System 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 GPU.
General Public Utilities Corporation and Subsidiary Companies
9. 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 Subsidiaries participated with nonaffiliated utilities in the following jointly owned stations at December 31, 1993:
Balance (In Millions) % Accumulated Station Owner Ownership Investment Depreciation
Homer City Penelec 50 $428.9 $151.3 Conemaugh Met-Ed 16.45 119.4 28.5 Keystone JCP&L 16.67 77.9 20.8 Yards Creek JCP&L 50 24.3 6.3 Seneca Penelec 20 16.5 4.4
10. LEASES
The GPU System's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1993 and 1992 totaled $150 million and $156 million, respectively (net of amortization of $199 million and $153 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Subsidiaries 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 presently leased material will be replaced by additional leased material. The Subsidiaries 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 $66 million, $74 million and $66 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 Subsidiaries are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.
JCP&L and Met-Ed have sold and leased back substantially all of their respective ownership interests in the Merrill Creek Reservoir Project. The minimum lease payments under these operating leases, which have remaining terms of 39 years, average approximately $3 million annually for each company.
GENERAL PUBLIC UTILITIES CORPORATION and Subsidiary Companies SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (continued) (In Thousands)
See Note 2 to consolidated financial statements contained on page for information concerning the cost of property, plant and equipment and the depreciation and amortization methods used during the three years ended December 31, 1993. Also see Note 10 to consolidated financial statements contained on page for information concerning the capital lease agreements.
(a) Reflects a reclassification of $55,500 of nuclear fuel costs associated with decontamination of the government's enrichment plants to Deferred Debits and Other Assets - Other to conform with current presentation.
(b) Includes an increase in property under capital leases of $2,334, which is comprised primarily of additions and amortization of $62,988 and $59,874, respectively.
(c) Includes a reduction in property under capital leases of $20,172, which is comprised primarily of additions and amortization of $48,087 and $67,820, respectively.
(d) Includes a reduction in property under capital leases of $7,820, which is comprised primarily of additions and amortization of $57,609 and $62,781, respectively; and a decrease of $15,433 and $6,115 due to the write-offs of prior years' expenditures related to the Duquesne Project and certain nuclear equipment, respectively.