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), incorporated under the laws of New Jersey in 1925, - and in Pennsylvania - Metropolitan Edison Company (Met-Ed), a Pennsylvania corporation incorporated in 1922, and Pennsylvania Electric Company (Penelec), a Pennsylvania corporation incorporated in 1919. 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 Energy Initiatives, Inc., EI Power, Inc., and EI Energy, Inc. (collectively, the "EI Group"), which develop, own and operate generation, transmission and distribution facilities in the United States and in foreign countries. GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and GPU Generation Corporation (Genco), which operates and maintains the fossil-fueled and hydroelectric units of the Subsidiaries, are also wholly owned subsidiaries of GPU. Wholly owned subsidiaries of the Subsidiaries are listed in Exhibit 21. The Subsidiaries own all of the common stock of the Saxton Nuclear Experimental Corporation, which owns a small demonstration nuclear reactor that has been partially decommissioned. All of these companies together with their affiliates 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 system, the GPU System 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 Public Utilities (NJBPU) 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. In addition, certain EI Group foreign subsidiaries are subject to limited rate and other regulation (see REGULATION).
INDUSTRY DEVELOPMENTS
The electric power markets have traditionally been served by integrated regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the development of increased competition in the electric utility industry. The electric utility industry is 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. 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 and the Energy Policy Act of 1992 (EPAct).
The EPAct has fostered further competition among utility and nonutility generators (NUGs) in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. Among its provisions, the EPAct allows the FERC, subject to certain criteria, to order owners of electric transmission systems to provide third parties with transmission access for wholesale power transactions. Although the legislation did not give the FERC the authority to order retail transmission access, movement toward opening the transmission network to retail customers is currently under consideration in many states, including New Jersey and Pennsylvania.
The competitive pressures resulting from the EPAct, coupled with increasing customer demands for lower-priced electricity, are expected to create opportunities to compete for new customers and revenues, as well as increase risk which could lead to the loss of customers and reduction in revenues from existing customers.
Operating in a competitive environment places new pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than are supportable in the marketplace will experience reduced earnings as they attempt to meet their customers' demands for lower-priced electricity. Competitive forces continue to influence some retail pricing. In some cases, commercial and industrial customers have indicated their intention to pursue competitively priced electricity from other providers, and in some instances have obtained price concessions from utilities. This prospect of increasing competition in the electric utility industry has already led the major credit rating agencies to apply more stringent guidelines in making credit rating determinations.
In response to competitive forces and regulatory changes, the GPU System has from time to time considered, and expects to continue to consider, various strategies designed to enhance its competitive position and to increase its ability to adapt to, and anticipate changes in, its business. These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of its wholesale and retail businesses, acquisitions of other businesses (including foreign utility companies), and additions to or dispositions of all or portions of its generation, transmission or distribution businesses. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to the ultimate effect thereof on the financial condition or competitive position of the GPU System.
Regulatory Initiatives
During 1995, there were a number of major federal and state developments in the area of competition within the electric utility industry as outlined below:
- The FERC ruled that a power purchase agreement between Connecticut Power & Light Co. and a NUG was invalid because the state law mandating the agreement provided for the utility to pay rates in excess of its "avoided costs," contrary to PURPA and the FERC's regulations. In February 1995, the FERC found that the California Public Utilities Commission's (CPUC) capacity procurement program also violated PURPA because, as designed, it resulted in contract rates above the state utilities' avoided costs. The FERC further expressed concerns that the CPUC had based its finding of
capacity requirements on stale data. Following these two decisions, other utilities, including the Subsidiaries, sought to have the FERC determine that certain of their NUG power purchase agreements are void on the same or similar grounds. The Subsidiaries have thus far been unsuccessful in these efforts. In addition, the GPU System is, together with other electric utilities, currently engaged in efforts to repeal PURPA.
- Legislation was introduced in the U.S. Senate that would repeal Section 210 of PURPA. Under that section, certain qualifying NUGs can "lock-in" long-term rates that may result in electric utilities being required to purchase power at costs higher than available alternative sources of energy. Similar legislation has been introduced in the House of Representatives. Other legislation has been introduced which would, among other things, repeal the 1935 Act and provide for the restructuring of the electric utility industry.
- The FERC issued a Notice of Proposed Rulemaking (NOPR) on open access nondiscriminatory transmission services by utilities and a supplemental NOPR on recovery of stranded costs. The new rules, if adopted, would in essence provide open access to the interstate electric transmission network and thereby encourage a fully competitive wholesale electric power market.
Among other things, the FERC's proposal would (1) require electric utilities to file nondiscriminatory open access transmission tariffs which would be available to all wholesale sellers and buyers of electricity; (2) require utilities to accept service under these new tariffs for their own wholesale transactions; and (3) permit utilities to recover their legitimate and verifiable "stranded costs" incurred when a franchise customer elects to purchase power from another supplier using the utility's transmission system.
With respect to stranded costs, the FERC proposed to provide recovery mechanisms where stranded costs result from municipalization or other instances where former retail customers become wholesale customers, as well as for wholesale stranded costs. The FERC stated that it would expect the state regulatory agencies to provide for recovery of stranded costs attributable to retail wheeling or direct access programs, and the FERC would intervene only when such agencies lacked necessary authority.
In addition, while it does not provide for "corporate unbundling," which the FERC defines as the disposing of ancillary services or creating separate affiliates to manage transmission services, the proposed rule does call for "functional unbundling" of transmission and ancillary services.
- An SEC Staff report recommended a series of legislative and administrative reforms to the 1935 Act. This included SEC Staff support for repeal of the 1935 Act with a minimum one year transition period, and a transfer of audit, reporting and certain other responsibilities to the FERC while giving state agencies access to holding company books and records. In the interim, the SEC Staff recommended that the SEC adopt a series of administrative reforms that would streamline such things as the
issuance of securities for routine financings and permit a wide range of energy related diversification activities. The SEC Staff also recommended that the SEC more flexibly interpret the 1935 Act's integrated system requirements by allowing utility acquisitions and specifically, combination electric and gas systems, where the affected state commissions concur.
In response to the SEC Staff report, the SEC has adopted certain changes which will streamline routine financings, and has proposed a number of others. GPU and other registered holding companies are seeking to repeal the 1935 Act because they believe it is a significant impediment to a registered holding company's ability to be competitive.
- The NJBPU issued Phase I of the New Jersey Energy Master Plan (NJEMP) promoting regulatory policy changes intended to move New Jersey's electric and gas utilities into a competitive marketplace. In the Phase I Report, the NJBPU recommended, among other things, (1) rate-flexibility legislation to allow utilities to compete in order to retain and attract customers in a changing regulatory environment; (2) alternative regulation as an interim and possibly a long-term measure to allow market forces to stimulate efficiency, productivity and innovation; (3) consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities and to ensure that all ratepayers benefit from the transition to greater competition; and (4) an integrated resource planning and competitive supply-side procurement process to streamline the regulatory review process, lower costs for all ratepayers, and ensure that New Jersey's environmental and energy conservation goals are met in a competitive marketplace. The Phase I Report also emphasized that regulation must continue to guarantee access to safe, adequate and reliable service at a reasonable cost; protect the public interest; meet environmental and energy efficiency goals; assure system reliability; and protect the financial integrity of utilities which have an obligation to serve the public.
- The NJBPU initiated Phase II of the NJEMP and established working groups to develop draft proposals and models by March 1996 on (1) competition issues; (2) stranded assets; (3) regional issues such as the environment and emissions standards; and (4) public policy issues, including social programs and conservation. The NJEMP is being developed in three phases, with Phase III expected to be completed by the end of 1996.
- The PaPUC has initiated an investigation into the role of competition in Pennsylvania's electric utility industry and solicited comments on various issues. Met-Ed and Penelec jointly filed responses suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investments, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on Pennsylvania utilities as compared with unregulated or out-of-state suppliers. In August 1995, the PaPUC released a staff report in which the staff decided not to recommend retail wheeling at this time. Evidentiary hearings on this matter began in December 1995 and the PaPUC is expected to present recommendations to the Governor and state General Assembly in the spring of 1996.
GPU System Initiatives
In response to the above federal and state regulatory developments, the GPU System has undertaken a number of initiatives during 1995:
- GPU made investments aggregating approximately $160 million in foreign utility companies and foreign generating facilities through the EI Group (see EI GROUP, in MANAGEMENT'S DISCUSSION AND ANALYSIS).
- JCP&L and Met-Ed bought out a total of five NUG (JCP&L two NUGs; Met-Ed three NUGs) power purchase contracts aggregating 540 MW (JCP&L 200 MW; Met-Ed 340 MW) of capacity, which is expected to save ratepayers more than $2 billion (JCP&L $0.7 billion; Met-Ed $1.3 billion) based on the projected cost of alternative sources of energy over the terms of these agreements. JCP&L and Met-Ed have agreed to pay the project developers up to a total of $84 million (JCP&L $17 million; Met-Ed $67 million) to cancel the contracts. JCP&L and Met-Ed have deferred the costs of these buyouts and are seeking to recover these costs through their energy adjustment clauses.
- The FERC accepted for filing, subject to possible rate refunds, the Subsidiaries' proposed open access transmission tariffs. The FERC has ordered that hearings be held on a number of aspects of these tariffs, including whether they are consistent in certain respects with FERC policy on open access and comparability of service. The tariffs provide for both firm and interruptible service on a point-to-point basis. Network service, where requested, will be negotiated on a case by case basis.
- The Subsidiaries, along with six other electric utility members of the Pennsylvania-New Jersey-Maryland Interconnection (PJM), filed with the FERC a detailed plan to increase competition in the Mid-Atlantic region. This comprehensive plan offers to all generators and wholesale buyers of electricity, a regional energy market and open access to high-voltage transmission lines which will result in greater availability of economic energy for wholesale electricity buyers and sellers. The Subsidiaries believe the plan will satisfy the goals of the FERC's NOPR on open access nondiscriminatory transmission services, and if approved by the FERC, open access transmission tariffs filed with the FERC under this plan would supersede the Subsidiaries' open access transmission tariffs.
The sponsoring PJM companies intend to make a comprehensive filing with the FERC consistent with this detailed plan by May 1996, and expect to implement the new structure by year-end 1996. The Subsidiaries have been advised that the Justice Department is reviewing possible antitrust implications of merger activity among PJM members.
- The Subsidiaries and certain of the PJM companies have proposed the formation of a wholesale market regional power pool managed by an Independent System Operator (ISO). The power pool would function as a spot market, with generators of electricity allowed to sell into the pool and purchasers of electricity allowed to buy from the pool. It would also accommodate contracts between specific buyers and sellers of power. The ISO would be responsible for supporting regional transmission planning and directing the operation of generation and transmission
facilities to assure the reliability and integrity of the regional electric grid.
The Subsidiaries have also proposed the use of a competitive transition charge (CTC) as an equitable approach to recover stranded costs. The CTC would be applied to all customers who depend on the electric system for delivery of their electric supply. Efforts by utilities to mitigate their stranded commitments could be required as part of the implementation of a CTC. The Subsidiaries also support in their proposals retail customer choice of energy suppliers, products and services.
With the expectation that a segment of the industry will continue to be regulated by the states, the proposals advocate the use of performance- based rates to encourage utilities to reduce costs while maintaining service reliability.
And in keeping with the public policy objectives associated with the electric utility industry, such as access to basic service for low income consumers, the proposals endorse the creation of a "public purpose charge" that would be collected from all consumers.
Statement of Financial Accounting Standards 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. Insofar as the Subsidiaries are concerned, potentially unrecoverable costs will most likely be related to generation investment, purchased power contracts, and "regulatory assets," which are deferred accounting transactions whose value depends on the Subsidiaries' ability to recover such costs from their respective customers in the future. In markets where there is excess capacity (as there currently is in the Mid- Atlantic and surrounding regions which include New Jersey and Pennsylvania) and many available sources of power supply, the market price of electricity is expected to be lower than what would be necessary to support full recovery of the investment in the generating facilities. 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 NUGs, are higher than future market prices (see NONUTILITY AND OTHER POWER PURCHASES). Utilities locked into expensive purchased power arrangements may be forced to value the contracts at market prices and recognize certain losses. The GPU System believes that to the extent that it no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result from such a valuation. At this time, it is difficult 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 to what extent regulators will allow recovery of such costs from customers.
Corporate Realignment
In January 1996, GPU received regulatory approval from the SEC to form Genco to operate and maintain the fossil-fueled and hydroelectric units owned by the Subsidiaries as well as construct any new nonnuclear generation
facilities which the Subsidiaries may need in the future. The Subsidiaries had already received necessary regulatory approvals from the PaPUC and NJBPU.
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 of approximately five million in New Jersey and Pennsylvania. For the year 1995, the Subsidiaries' revenues were about equally divided between Pennsylvania customers and New Jersey customers. During 1995, sales to customers by customer class were as follows:
% Operating Revenues % KWH Sales GPU JCP&L Met-Ed Penelec GPU JCP&L Met-Ed Penelec Residential 42 45 42 36 36 41 35 29 Commercial 35 38 28 33 32 38 27 30 Industrial 21 16 28 27 29 21 36 34 Other* 2 1 2 4 3 - 2 7 100 100 100 100 100 100 100 100
* Rural electric cooperatives, municipalities, street and highway lighting, and others.
The Subsidiaries also make interchange and spot market sales of electricity to other utilities. Reference is made to System Statistics and Company Statistics on pages,,, and, for additional information concerning the GPU System's sales and revenues. Revenues of JCP&L, Met-Ed and Penelec derived from their largest single customers accounted for less than 3%, 2% and 1%, respectively, of their electric operating revenues for the year and their 25 largest customers, in the aggregate, accounted for approximately 9%, 13% and 12%, respectively, of such revenues.
In January 1996, one of JCP&L's larger industrial customers, Anchor Glass Company (Anchor), announced that it would be closing its Aberdeen, New Jersey plant during 1996. Anchor accounts for approximately $4 million of JCP&L's annual 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. JCP&L provides retail service in northern, western and east central New Jersey having an estimated population of approximately 2.5 million. Met-Ed provides retail electric service in all or portions of 14 counties, in the eastern and south central parts of Pennsylvania, having an estimated population of almost one million. Met-Ed also sells electricity at wholesale to four municipalities having an estimated population of over 11,000. Penelec provides retail and wholesale electric service within a territory located in western, northern and south central Pennsylvania extending from the Maryland state line northerly to the New York state line, with a population of about 1.5 million, approximately 24% of which is concentrated in ten cities and twelve boroughs, all with populations over 5,000. Penelec also provides wholesale service to five municipalities in New Jersey, and, as lessee of the property of the Waverly Electric Light & Power
Company, also serves a population of about 13,700 in Waverly, New York and vicinity.
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 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 EI GROUP
The EI Group is engaged in the development, ownership and operation of generation, transmission and distribution facilities in the United States and foreign countries. During 1995, the EI Group expanded its activities in the following areas:
EI Power acquired from the Bolivian government, for approximately $47 million, a 50% ownership interest in Empresa Guaracachi S.A., a Bolivian electric generating company having an aggregate capacity of 216 MW of gas- fired and oil-fired generation.
EI Energy, together with the Australian Gas Light Company, acquired Solaris Power (Solaris), an electric distribution company based in Melbourne, Australia, for a total purchase price of approximately $712 million, of which EI Energy's 50% share was $356 million. EI Energy made an equity investment in Solaris of approximately $112 million; the balance of the purchase price was provided through borrowings by Solaris from an Australian bank syndicate. Solaris, which provides electric service to more than 230,000 customers in and around Melbourne, was sold by the Government of Victoria through a competitive bid as part of that state's privatization of the electric industry.
EI Power, along with its development partners, has completed the financing for the acquisition of a 240 MW gas-fired generating plant in Barranquilla, Colombia and the construction of a new 750 MW gas-fired plant adjacent to the existing plant. Electricity generated by these plants will be sold to Corporacion Electrica de la Costa Atlantica under a 20-year contract. Total project costs, including the acquisition of the existing plant, are approximately $750 million, of which EI Power's equity contribution is expected to be approximately $65 million. The balance of the funds is being provided by a group of lenders, including the Overseas Private Investment Corporation (OPIC) and the U.S. Export-Import Bank (Eximbank) which have agreed to fund an aggregate of $303 million (OPIC $150 million and Eximbank $153 million) of project costs. EI Power has agreed to make additional equity contributions to the project of up to $58 million under certain circumstances. GPU has guaranteed all of EI Power's equity contribution commitments.
On March 1, 1996, President Clinton decertified the Republic of Colombia under the Foreign Assistance Act of 1961 for that country's failure to comply with the objectives of the 1988 United Nations anti-narcotics convention. That Act generally governs the terms and conditions under which the United States provides financial aid and support to foreign countries. On March 7, 1996, OPIC funded an additional $21 million of the Barranquilla project costs.
Eximbank has stated that it is seeking to clarify whether the decertification will affect its existing funding commitments to the project.
Loss of either OPIC or Eximbank financing for the Barranquilla project would adversely affect the cost and schedule for the project and could result in an event of default under the project's financing documents. In that event, unless substitute financing acceptable to the other lenders could be obtained, GPU could be required to immediately fund its equity contribution of up to $123 million to the project.
At December 31, 1995, the EI Group had ownership interests in eleven operating combined-cycle cogeneration plants located in the United States (totaling 932 MW of capacity) and five operating generating facilities located in Canada and South America (totaling 480 MW of capacity). The EI Group also has a number of additional projects at various stages of development, including a 300 MW gas-fired project and a 180 MW gas-fired project for which long-term power purchase agreements have been executed with Georgia Power Company and Wisconsin Public Service Company, respectively.
GPU has obtained SEC approval to finance investments in foreign utility companies and exempt wholesale generators (both domestically and internationally) up to an aggregate amount equal to 50% of GPU's average consolidated retained earnings. At December 31, 1995, GPU has investments, through the EI Group, in exempt wholesale generators and foreign utility companies totaling approximately $300 million. This amount includes investments made by the EI Group totaling $160 million, of which $81 million was contributed by GPU; and GPU guarantee obligations aggregating $140 million. In addition, GPU has investments, through the EI Group, in qualifying cogeneration facilities and project development activities aggregating $124 million. Selected financial data for the EI Group is as follows:
(In Millions) 1995* 1994 1993
Total assets $380 $130 $ 44
Capitalization: Common equity $209 $118 $ 39 Notes payable 2 - - Long-term debt 104 - - Total $315 $118 $ 39
Purchase of investments $165 $ 74 $ 16
Net income/(loss) $ 9 $ (3) $ (2)
* Total assets includes approximately $62 million held by a minority owner.
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 operating generation facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. At December 31, 1995, the Subsidiaries' net
investment, including nuclear fuel, in TMI-1 was $640 million (JCP&L $166 million; Met-Ed $318 million; Penelec $156 million) and $785 million for Oyster Creek. The Subsidiaries' net investment in TMI-2 at December 31, 1995 was $95 million (JCP&L $85 million; Met-Ed $2 million; Penelec $8 million). JCP&L is collecting revenues for TMI-2 on a basis which provides for the recovery of its remaining investment in the plant by 2008. Met-Ed and Penelec are collecting revenues for TMI-2 from their wholesale customers. 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 be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. The GPU System may also incur costs and experience reduced output at its nuclear plants because of the prevailing design criteria at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now assumed lives cannot be assured. Also, not all risks associated with ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric utilities to obtain adequate and timely recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of each plant's useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs through the ratemaking process, but recognizes that recovery is not assured.
TMI-1
The operating license for TMI-1, a 786 MW pressurized water reactor, expires in 2014. TMI-1 completed a 34-day scheduled refueling outage in October 1995, and operated at a capacity factor of 92.8% for the year. Its next refueling outage is scheduled to begin in September 1997.
Oyster Creek
The operating license for the Oyster Creek station, a 619 MW boiling water reactor (as rerated in January 1995 from 610 MW), expires in 2009. Oyster Creek operated at a 95.8% capacity factor for 1995. The station's next refueling outage is scheduled to begin in September 1996 and is expected to last approximately 6 to 8 weeks. This outage may be extended an additional 6 to 8 weeks in order to move spent nuclear fuel from the reactor's spent fuel pool to an on-site dry storage facility.
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
U.S. District Court for the Middle District of Pennsylvania. Some of the Subsidiaries. Approximately 2,100 of such claims are pending in the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Subsidiaries had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for up to an aggregate of $335 million in premium charges under such plan, and (c) an indemnity agreement with the NRC for up to $85 million, bringing their total primary, secondary and tertiary financial protection up to an aggregate of $560 million. Under the secondary level, the Subsidiaries are subject to a retrospective premium charge of up to $5 million per reactor, or a total of $15 million (JCP&L, $7.5 million; Met-Ed, $5 million; Penelec, $2.5 million).
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against the Corporation and the Subsidiaries and their suppliers (the defendants) under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages. A trial of ten allegedly representative cases is scheduled to begin in June 1996.
In October 1995, the U.S. Court of Appeals for the Third Circuit ruled that the Price-Anderson Act provides coverage under its primary and secondary levels for punitive as well as compensatory damages, but that punitive damages could not be recovered against the Federal Government under the third level of financial protection. In so doing, the Court of Appeals referred to the "finite fund" (the $560 million of financial protection under the Price- Anderson Act) to which plaintiffs must resort to get compensatory as well as punitive damages. The Corporation and its Subsidiaries have asked the U.S. Supreme Court to review that portion of the Court of Appeals' decision that punitive damages may be recovered in public liability actions under the Price- Anderson Act. The Corporation and its Subsidiaries do not know whether plaintiffs will appeal any aspect of the Court of Appeals' decision.
Based upon the Court of Appeals' decision, the Corporation and its Subsidiaries believe that any liability to which they might be subject by reason of the TMI-2 accident will not exceed their financial protection under the Price-Anderson Act.
In February 1996, the U.S. Supreme Court denied a petition filed by the Corporation and its Subsidiaries to review a finding by the Court of Appeals that the standard of care owed by the defendants to a plaintiff was determined by the specific level of radiation which was released into the environment, as measured at the site boundary, rather than as measured at the specific site where the plaintiff was located at the time of the accident (as the Corporation and its Subsidiaries proposed). The Court of Appeals had also held that each plaintiff still must demonstrate exposure to radiation released during the TMI-2 accident and that such exposure had resulted in injuries.
There can be no assurance as to the outcome of this litigation.
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 the NUCLEAR FUEL DISPOSAL FEE section of Note 2 to GPU's 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's remaining in long- term storage and being decommissioned at the same time as TMI-1. Based on NRC studies, a comparable funding target has been developed which takes into account the accident. Under the NRC regulations, the funding targets (in 1995 dollars) are as follows:
(Millions) Oyster Creek TMI-1 TMI-2
JCP&L $189 $ 39 $ 63 Met-Ed - 79 125 Penelec - 39 62 Total $189 $157 $250
The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
The Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, JCP&L has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990, and Met-Ed and Penelec have contributed amounts written off for TMI-2 nuclear plant decommissioning in 1991, to TMI-2's external trust (see TMI-2 Future Costs). Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the Balance Sheet.
In 1995, a consultant to GPUN performed site-specific studies of the TMI site, including both Units 1 and 2, and of Oyster Creek, that considered various decommissioning methods and estimated the cost of decommissioning the radiological portions and the cost of removal of the nonradiological portions of each plant, using the prompt removal/dismantlement method. GPUN management
has reviewed the methodology and assumptions used in the site-specific studies, is in agreement with them, and believes the results are reasonable as follows:
(Millions) Oyster GPU Creek TMI-1 TMI-2
Radiological decommissioning $347 $295 $358 Nonradiological cost of removal 33 73 37* Total $380 $368 $395
* Net of $3 million spent as of December 31, 1995.
(Millions) Oyster JCP&L Creek TMI-1 TMI-2
Radiological decommissioning $347 $74 $90 Nonradiological cost of removal 33 18 9* Total $380 $92 $99
* Net of $750 thousand spent as of December 31, 1995.
(Millions)
Met-Ed TMI-1 TMI-2
Radiological decommissioning $147 $179 Nonradiological cost of removal 37 19* Total $184 $198
* Net of $1.5 million spent as of December 31, 1995.
(Millions)
Penelec TMI-1 TMI-2
Radiological decommissioning $74 $89 Nonradiological cost of removal 18 9* Total $92 $98
* Net of $750 thousand spent as of December 31, 1995.
The ultimate cost of retiring the GPU System's nuclear facilities may be different from the cost estimates contained in these site-specific studies. Such costs are subject to (a) the escalation of various cost elements (including, but not limited to, general inflation), (b) the further development of regulatory requirements governing decommissioning, (c) the technology available at the time of decommissioning, and (d) the availability of nuclear waste disposal facilities.
In February, 1996 the Financial Accounting Standards Board (FASB) issued an Exposure Draft titled "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets," which includes nuclear plant retirement costs. If the Exposure Draft's current provisions are finalized,
Oyster Creek and TMI-1 future retirement costs will have to be recognized as a liability currently, rather than recorded over the life of the plants (as is currently the practice), with an offsetting asset recorded for amounts collectible through rates. Any amounts not collectible through rates will have to be charged to expense. For TMI-2, a liability has already been recognized since the plant is no longer operating (see TMI-2 Future Costs). Comments on the Exposure Draft are due by May 31, 1996, and a final statement is expected to be effective for fiscal years beginning after December 15, 1996.
TMI-1 and Oyster Creek
JCP&L is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. JCP&L is also collecting revenues, based on estimates of $15 million for TMI-1 and $32 million for Oyster Creek adopted in previous rate orders issued by the NJBPU, for its share of the cost of removal of nonradiological structures and materials. The PaPUC previously granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share ($37 million) of the NRC funding target and nonradiological cost of removal estimated in an earlier 1988 site-specific study to be $74 million (in 1995 dollars). The PaPUC also permitted Penelec to increase the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $73 million (JCP&L $23 million; Met-Ed $36 million; Penelec $14 million) for TMI-1 and $138 million for Oyster Creek at December 31, 1995. TMI-1 and Oyster Creek retirement costs are charged to depreciation expense over the expected service life of each nuclear plant, and amounted to $15 million (JCP&L $3 million; Met-Ed $8 million; Penelec $4 million) and $13 million, respectively, for 1995.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable under the current ratemaking process.
TMI-2 Future Costs
The estimated liabilities for TMI-2 Future Costs (reflected as Three Mile Island Unit 2 Future Costs on the Balance Sheet) as of December 31, 1995 are as follows: (millions) GPU JCP&L Met-Ed Penelec
Radiological Decommissioning $358 $ 90 $179 $ 89 Nonradiological Cost of Removal 37* 9 19 9 Incremental Monitored Storage 18 4 9 5 Total $413 $103 $207 $103
* Net of $3 million (JCP&L $750 thousand; Met-Ed $1.5 million; Penelec $750 thousand) spent as of December 31, 1995.
The liability recorded on the Balance Sheet for radiological decommissioning and nonradiological cost of removal is based on the 1995 site- specific study.
Offsetting the $413 million liability is $271 million (JCP&L $53 million; Met-Ed $147 million; Penelec $71 million) which is probable of recovery from customers and included in Three Mile Island Unit 2 Deferred Costs on the Balance Sheet, and $143 million (JCP&L $60 million; Met-Ed $57 million; Penelec $26 million) in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet. Of the $271 million still to be recovered from customers, $66 million (JCP&L $17 million; Met-Ed $33 million; Penelec $16 million) represents an increase from 1994 due to the 1995 site- specific study. Earnings on trust fund deposits collected from customers are included in amounts shown on the Balance Sheet under Three Mile Island Unit 2 Deferred Costs. TMI-2 decommissioning costs charged to expense in 1995 amounted to $14 million (JCP&L $3 million; Met-Ed $9 million; Penelec $2 million).
The NJBPU has granted JCP&L decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. In 1993, the Pennsylvania Office of Consumer Advocate filed a petition for review of a Met-Ed rate order with the Pennsylvania Commonwealth Court seeking to set aside a March 1993 PaPUC rate order which allowed Met-Ed to recover in the future certain TMI-2 retirement costs. In 1994, the Commonwealth Court reversed that rate order and, as a consequence, Met-Ed and Penelec recorded pre-tax charges totalling $128 million and $56 million, respectively. In September 1995, the Pennsylvania Supreme Court reversed the Commonwealth Court decision. Met-Ed and Penelec have therefore reversed the previous write-offs, resulting in the crediting of pre-tax income for $128 million and $56 million, respectively. However, notwithstanding the Supreme Court's decision, Met-Ed and Penelec have determined that the recovery of the incremental monitored storage costs is no longer probable, and have recorded pre-tax charges of $10 million and $4.7 million, respectively, during 1995.
At December 31, 1995, the accident-related portion of TMI-2 radiological decommissioning costs is considered to be $63 million (JCP&L $16 million; Met- Ed $32 million; Penelec $15 million), which is the difference between the 1995 TMI-1 and TMI-2 site-specific study estimates of $295 million and $358 million, respectively (JCP&L $74 million and $90 million; Met-Ed $147 million and $179 million; Penelec $74 million and $89 million). In connection with rate case resolutions at the time, JCP&L, Met-Ed and Penelec made contributions to irrevocable external trusts relating to their shares of the accident-related portions of the decommissioning liability. In 1990, JCP&L contributed $15 million and in 1991, Met-Ed and Penelec contributed $40 million and $20 million, respectively, to irrevocable external trusts. These contributions were not recovered from customers and have been expensed. The Subsidiaries will not pursue recovery from customers for any of these amounts contributed in excess of the $63 million accident-related portion referred to above.
JCP&L intends to seek recovery for any increases in TMI-2 retirement costs, and Met-Ed and Penelec intend to seek recovery for any increases in the nonaccident-related portion of such costs, but recognize that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage in late 1993, the Subsidiaries are incurring incremental storage costs of approximately $1 million (JCP&L $250 thousand; Met-Ed $500 thousand; Penelec $250 thousand) annually. The Subsidiaries estimate that the remaining storage costs will total $18 million through 2014, the expected retirement date of TMI-1. JCP&L's rates reflect its share of these costs.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors, subject to an annual maximum payment of $10 million per incident per reactor. In addition to the retrospective premiums payable under Price-Anderson, the GPU System is also subject to retrospective premium assessments of up to $69 million (JCP&L $41 million; Met-Ed $19 million; Penelec $9 million) in any one year under insurance policies applicable to nuclear operations and facilities.
The GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing to 80 percent of such amounts for years two and three.
NONUTILITY AND OTHER POWER PURCHASES
Pursuant to the requirements of PURPA and state regulatory directives, the Subsidiaries have entered into power purchase agreements with NUGs for the purchase of energy and capacity for periods up to 25 years each for JCP&L and Penelec, and 26 years for Met-Ed. The majority of these agreements contain certain contract limitations and subject the NUGs to penalties for nonperformance. While a few of these facilities are dispatchable, most are must-run and generally obligate the Subsidiaries to purchase, at the contract price, the net output up to the contract limits. As of December 31, 1995, facilities covered by these agreements having 1,624 MW (JCP&L 892 MW; Met-Ed 335 MW; Penelec 397 MW) of capacity were in service. Actual payments from 1993 through 1995, and estimated payments from 1996 through 2000 to NUGs, assuming that all facilities which have existing agreements, or which have obtained orders granting them agreements, enter service, are as follows:
Payments Under NUG Agreements (Millions)
Total JCP&L Met-Ed Penelec
1993 $ 491 $ 292 $ 95 $ 104 1994 528 304 101 123 1995 670 381 131 158 * 1996 696 369 151 176 * 1997 739 400 155 184 * 1998 837 430 210 197 * 1999 931 442 211 278 * 2000 987 463 216 308
* Estimate
Of these amounts, payments to the projects which are not in service at December 31, 1995 are estimated as follows:
Payments Under NUG Agreements Not In Service (Millions)
Total JCP&L Met-Ed Penelec
1997 $ 40 $ 25 $ 15 $ - 1998 123 53 65 5 1999 202 58 68 76 2000 231 62 71 98
In the year 2000, NUG agreements, in the aggregate, will provide for the purchase of approximately 2,062 MW (JCP&L 1,002 MW; Met-Ed 485 MW; Penelec 575 MW) of capacity and energy by the GPU System, at varying prices.
The emerging competitive generation market has created uncertainty regarding the forecasting of the System's energy supply needs which has caused the Subsidiaries to change their supply strategy to seek shorter-term agreements offering more flexibility. Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from generation facilities now in
service is currently and is expected to continue to be priced below the costs of new supply sources, at least for some time. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Subsidiaries' NUG agreements are substantially in excess of current and projected prices from alternative sources.
The Subsidiaries are seeking to reduce the above market costs of these NUG agreements by (1) attempting to convert must-run agreements to dispatchable agreements; (2) attempting to renegotiate prices of the agreements; (3) offering contract buyouts while seeking to recover the costs through their energy adjustment clauses (see Managing Nonutility Generation, in MANAGEMENT'S DISCUSSION AND ANALYSIS); and (4) initiating proceedings before federal and state agencies, and in the courts, where appropriate. In addition, the Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new NUG agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. These efforts may result in claims against the GPU System for substantial damages. There can, however, be no assurance as to the extent to which the Subsidiaries' efforts will be successful in whole or in part.
While the Subsidiaries thus far have been granted recovery of their NUG costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that for 1998, when substantially all of these NUG projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined-cycle facility) will range from $240 million to $350 million (JCP&L $100 to $150 million; Met-Ed $50 million to $80 million; Penelec $90 million to $120 million). The amount of these estimated above market payments may increase or decrease substantially based upon, among other things, payment escalations in the contract terms, changes in fuel prices and changes in the capital and operating cost of new generating equipment.
In 1995, the Subsidiaries entered into a three-year fuel management agreement with New Jersey Natural Energy Corporation, an affiliate of New Jersey Natural Gas Company, to manage the Subsidiaries' natural gas purchases and interstate pipeline capacity. The Subsidiaries' gas-fired facilities, as well as up to approximately 1,100 MW (JCP&L 885 MW; Met-Ed 200 MW; Penelec 15 MW) of NUG capacity, will be pooled and managed under this agreement, allowing the Subsidiaries to reduce their power purchase expenses. The Subsidiaries have conditional or final agreements with four NUGs (JCP&L three NUGs; Met-Ed one NUG), having an aggregate capacity of approximately 430 MW (JCP&L 385 MW; Met-Ed 45 MW), to supply natural gas from the pool.
In 1995, Met-Ed and Penelec filed a petition for enforcement and declaratory order with the FERC requesting that the FERC effectively invalidate four contracts (Met-Ed two contracts; Penelec two contracts) with NUGs, aggregating 487 MW (Met-Ed 327 MW; Penelec 160 MW) of capacity, on the grounds that the PaPUC's implementation of PURPA directing Met-Ed and Penelec to enter into these agreements was unlawful. The FERC has denied the petition, and Met-Ed and Penelec have not determined whether they will seek judicial review of the FERC's action. Subsequent to the FERC's decision, Met-Ed bought out the contracts for two of these projects, totaling 327 MW.
In 1993, the PaPUC ordered Penelec to enter into long-term contracts to purchase a total of 160 MW from two NUGs commencing in 1997 or later. Penelec's subsequent appeal of the PaPUC order to the Commonwealth Court was denied, but the case was remanded back to the PaPUC to recalculate the avoided costs to be paid for the power. In January 1996, a PaPUC Administrative Law Judge (ALJ) issued a decision recommending a levelized avoided cost which is in excess of current market prices. Penelec and other parties have filed exceptions to the ALJ's decision.
In August 1995, the Pennsylvania Supreme Court granted Penelec's petition to review the Commonwealth Court's decision which upheld the PaPUC order requiring Penelec to enter into such power purchase agreements. Briefs have been filed and oral argument was held in January 1996. These matters are pending.
In March 1995, the U.S. Court of Appeals denied petitions for rehearing filed by JCP&L, the NJBPU, and the New Jersey Division of Ratepayer Advocate (Ratepayer Advocate), seeking reconsideration of the Court's earlier decision prohibiting the NJBPU from reexamining its order approving the rates payable to Freehold Cogeneration Associates (Freehold) under a long-term power purchase agreement entered into pursuant to PURPA. The U.S. Supreme Court has denied petitions for review filed by JCP&L and the Ratepayer Advocate. JCP&L also petitioned the FERC to invalidate the agreement as unlawful under PURPA. The FERC has denied JCP&L's petition and in February 1996 JCP&L requested the U.S. Court of Appeals to review the FERC's decision. JCP&L is also seeking to invalidate the Freehold power purchase agreement in a separate action pending in New Jersey Superior Court. Freehold has moved to dismiss JCP&L's claim, and the matter is pending. JCP&L believes that over the 20-year term of the agreement, the above market costs of this contract will amount to approximately $1.2 billion over alternative sources of energy.
In 1994, MidAtlantic Cogen Inc. requested the PaPUC to order Met-Ed to enter into a long-term agreement to buy 322 MW of capacity and energy from its Fairless Cogeneration Project. The PaPUC subsequently ordered that hearings be held and assigned the matter to an ALJ. Met-Ed moved to dismiss MidAtlantic's petition and, in February 1996, an ALJ issued a recommended decision granting Met-Ed's request. This matter is pending before the PaPUC.
JCP&L has entered into agreements with other utilities to purchase capacity and energy for various periods through 2004. These agreements will provide for up to 1,085 MW in 1996, declining to 878 MW in 1999 and 696 MW in 2004. Payments pursuant to these agreements are estimated to be $174 million in 1996, $164 million in 1997, $145 million in 1998, $124 million in 1999, and $95 million in 2000. Applications for approval of three of these agreements are pending before the NJBPU. These three agreements provide for the purchase of up to 351 MW in 1996, increasing to 696 MW in 1999, with payments pursuant to these agreements estimated to be $11 million in 1996, $37 million in 1997, $57 million in 1998, $82 million in 1999, and $95 million in 2000.
In January 1996, JCP&L issued an all-supply source solicitation for the short-term supply of energy and capacity to meet its minimum forecasted needs from 1999 through 2002 (see New Energy Supplies, in MANAGEMENT'S DISCUSSION AND ANALYSIS).
RATE PROCEEDINGS
Pennsylvania
In January 1996, Met-Ed filed a preliminary Energy Cost Rate (ECR) request with the PaPUC for an annual increase of $23.6 million, representing a 2.9% increase in overall retail customer charges. Met-Ed's request is primarily attributable to an increase in payments under NUG contracts and recovery of $17 million of buy-out costs for canceled NUG projects after giving effect to lower energy costs resulting from an anticipated increase in TMI-1 generation. The ECR change is proposed to go into effect April 1, 1996.
Also in January 1996, Penelec filed a preliminary ECR request with the PaPUC for an annual increase of $31.9 million, representing a 3.8% increase in overall retail customer charges. Penelec's request is primarily attributable to an increase in payments under NUG contracts and the per unit cost of coal- fired generation after giving effect to lower energy costs resulting from an anticipated increase in TMI-1 generation. The ECR change is proposed to go into effect April 1, 1996.
In September 1995, a Pennsylvania Supreme Court decision overturned a 1994 Commonwealth Court order and restored a 1993 PaPUC rate order allowing Met-Ed to recover certain TMI-2 retirement costs from customers (see NUCLEAR PLANT RETIREMENT COSTS - TMI-2 Future Costs).
In 1994, at the request of the PaPUC, the affected Pennsylvania electric utilities have submitted to the PaPUC proposals for the establishment of a nuclear performance standard. The matter is pending before the PaPUC.
New Jersey
In December 1995, JCP&L filed a petition with the NJBPU requesting a net increase in overall retail customer rates of $36.5 million annually, or an increase of 1.8%, effective March 1, 1996. The proposed increase is primarily related to JCP&L's demand side management programs, levelized energy adjustment clause (LEAC) charges, which include recovery of costs to buy out NUG contracts, and other tariff revisions.
Concurrent with the its proposed March 1996 LEAC change, JCP&L filed a petition with the NJBPU to implement a Manufactured Gas Plant Remediation Adjustment Clause (RAC) for the recovery of underrecovered Manufactured Gas Plant (MGP) costs. The RAC mechanism, which was approved by the NJBPU in December 1994, provides for the recovery of MGP costs, net of insurance and other recoveries, over rolling seven year periods with interest on any unamortized balance. In its petition, JCP&L proposes to recover $44,000 annually through the RAC.
In July 1995, New Jersey adopted energy rate-flexibility legislation that will enable electric utilities to offer rate discounts to certain customers. If certain conditions are met, utilities may be permitted to recover from customers, on a prospective basis following a base rate case, up to 50% of revenue lost as a result of rate discounts. JCP&L has submitted its initial compliance filing which sets forth JCP&L's minimum price for off-tariff rate agreements applicable to commercial and industrial customers. The legislation
also provides utilities with the opportunity to propose to the NJBPU alternative ways to set rates. JCP&L expects to file such an alternative rate plan with the NJBPU in 1996.
JCP&L's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate annual generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect of the performance standard charge at a 40% capacity factor would be approximately $10 million before tax. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBPU for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC.
The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from NUG projects. The proceeding was initiated, in part, to respond to contentions of the Ratepayer Advocate that by permitting utilities to recover such costs through the LEAC, an excess or "double" recovery may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1994, the NJBPU ruled that the LEAC periods prior to March 1991 were considered closed but subsequent LEAC periods remain open for further investigation. This matter is pending before a NJBPU Administrative Law Judge. JCP&L estimates that the potential refund liability for the LEAC periods from March 1991 through February 1996, the end of the most recent LEAC period, is $55 million. There can be no assurance as to the outcome of this proceeding.
CAPITAL PROGRAMS
General
During 1995, gross plant additions were approximately $459 million (JCP&L $232 million; Met-Ed $101 million; Penelec $123 million; GPUSC $3 million) attributable principally to improvements and modifications to existing generation, transmission and distribution facilities, a new generation facility, and clean air requirements. Expenditures for maturing obligations totaled $91 million (JCP&L $47 million; Met-Ed $41 million; GPUSC $3 million) in 1995. In addition, the EI Group made investments in 1995 totaling $165 million, consisting primarily of investments in generation facilities in South America and an electric distribution business in Australia (see THE EI GROUP). The principal categories of the 1996 anticipated Subsidiary construction expenditures, which include anticipated expenditures by GPUSC and an allowance for other funds used during construction, are as follows:
(In Millions)
GPU JCP&L Met-Ed Penelec
Generation - Nuclear $ 57 $ 41 $11 $ 5 Nonnuclear 82 26 15 41 Total Generation 139 67 26 46 Transmission & Distribution 269 140 60 69 Other 83 49 11 9 Total $491 $256 $97 $124
The anticipated increase in construction expenditures during 1996 is principally attributable to expenditures associated with ongoing system development and upgrading JCP&L's communication system. Gross plant additions are expected to be approximately $437 million in 1997 (JCP&L $200 million; Met-Ed $108 million; Penelec $116 million; GPUSC $13 million). The decrease in construction expenditures during 1997 is largely due to the anticipated completion in 1996 of JCP&L's communication system and a new generation facility. During 1996 and 1997, GPU will continue to provide the EI Group with capital contributions and credit support (in amounts which may be substantial) as project investment opportunities arise. In addition, expenditures for maturing obligations are expected to be $131 million for 1996 (JCP&L $36 million; Met-Ed $15 million; Penelec $75 million; GPUSC $3 million; EI Group $2 million) and $158 million for 1997 (JCP&L $86 million; Met-Ed $40 million; Penelec $26 million; GPUSC $3 million; EI Group $3 million).
GPU and the Subsidiaries estimate that a substantial portion of their anticipated total capital needs in each of 1996 and 1997 will be satisfied through internally generated funds.
The Subsidiaries expect to obtain the remainder of these funds principally through the sale, subject to market conditions, of first mortgage bonds (FMBs). The Subsidiaries' FMB indentures and charters include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Subsidiaries may issue (see LIMITATIONS ON ISSUING ADDITIONAL SECURITIES). Present plans call for the Subsidiaries to issue long-term debt during the next three years to, among other things, finance construction activities and fund the redemption of maturing senior securities.
The GPU System's gross plant additions exclude nuclear fuel requirements provided under capital leases that amounted to $52 million (JCP&L $19 million; Met-Ed $22 million; Penelec $11 million) in 1995. When consumed, the presently leased material, which amounted to $152 million (JCP&L $88 million; Met-Ed $43 million; Penelec $21 million) at December 31, 1995, is expected to be replaced by additional leased material at a rate of between $40 million and $45 million (JCP&L $20 million - $25 million; Met-Ed $13 million; Penelec $7 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.
Over the next five years, assuming the continuation of existing retail electric regulation, each of the Subsidiaries is expected to experience an average growth in sales to customers of about 2% annually, principally due to continued economic growth in the service territories and a slight increase in customers. The Subsidiaries intend to provide for these increased energy needs through a mix of economic supply 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" market purchases, and avoidance of long-term firm commitments. GPU's present strategy includes minimizing the financial exposure associated with new long-term purchase commitments and the construction of new facilities by evaluating these options in terms of an unregulated power market. As part of this strategy, GPU is also evaluating the future financial viability of its generating assets, including possible plant retirements, on an ongoing basis. The GPU System
will take necessary actions to avoid adding new capacity which would result in costs that may exceed future market prices. In addition, the Subsidiaries will continue to seek regulatory support to renegotiate or buy out contracts with NUGs where the pricing is in excess of projected prices of alternative sources.
In February 1996, JCP&L announced plans to close the 58 MW Werner Unit 4 and 72 MW Gilbert Unit 3 generating plants due to high operating costs. The combined remaining investment in these plants is approximately $15 million at December 31, 1995. JCP&L has not determined whether it will seek recovery of such costs through the ratemaking process.
Conservation and Load Management
The NJBPU and PaPUC continue to encourage the development of new conservation and load-management programs. The benefits of some of these programs may not, however, offset program costs and the Subsidiaries are working to mitigate the impacts these programs can have on their competitive position in the marketplace.
In New Jersey, JCP&L continues to conduct DSM programs approved in 1992 by the NJBPU. DSM includes utility-sponsored activities designed to improve energy efficiency in customer electricity use and load-management programs that reduce peak demand. These JCP&L programs have resulted in summer peak demand reductions of 79 MW through 1995. In August 1995, JCP&L filed a revised DSM plan for NJBPU approval covering programs for 1996 and 1997. This filing is currently under review by the NJBPU.
In a December 1993 order, the PaPUC adopted guidelines for the recovery of DSM costs and directed utilities to implement DSM programs. Met-Ed and Penelec subsequently filed DSM programs that were expected to be approved by the PaPUC in the first quarter of 1995. An industrial intervenor contested the PaPUC's guidelines. In January 1995, the Commonwealth Court reversed the PaPUC order and in February 1996 the Pennsylvania Supreme Court upheld the Commonwealth Court's decision. As a result, the nature and scope of Met-Ed and Penelec's DSM programs is uncertain at this time.
FINANCING ARRANGEMENTS
The Corporation and the Subsidiaries expect to have short-term debt outstanding from time to time throughout 1996. The peak in short-term debt outstanding is expected to occur in the spring, coinciding with normal cash requirements for revenue tax payments.
The GPU System has $529 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total borrowings outstanding at any time and are subject to various covenants and acceleration under certain conditions. The Credit Agreement borrowing rates and facility fee are dependent on the long-term debt ratings of the Subsidiaries.
In 1995, GPU sold five million shares of common stock. The net proceeds of $157.5 million were used to make cash capital contributions to the Subsidiaries and to repay GPU short-term debt, a portion of which had been incurred to acquire interests in a generating company in Bolivia and the Solaris distribution business in Australia.
The Subsidiaries have regulatory authority to issue and sell FMBs, which may be issued as secured medium-term notes, and preferred stock through various periods into 1997. Under existing authorizations, JCP&L, Met-Ed and Penelec may issue these senior securities in aggregate amounts of $225 million, $190 million and $160 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.
In 1995, the Subsidiaries issued an aggregate of $338 million (JCP&L $50 million; Met-Ed $89 million; Penelec $199 million) principal amount of FMBs. The proceeds from these issuances were used to refinance $128 million (Met-Ed $29 million; Penelec $99 million) principal amount of higher cost FMBs, to redeem at maturity $59 million (JCP&L $47 million; Met-Ed $12 million) principal amount of FMBs, to moderate short-term debt levels and to fund growth in capitalization. In addition, the EI Group has borrowed $68 million under a credit agreement, the proceeds of which were used primarily to finance the acquisition of Solaris (see THE EI GROUP).
JCP&L Capital, L.P., a special-purpose partnership in which a subsidiary of JCP&L is the sole general partner, issued $125 million stated value of mandatorily redeemable preferred securities. The proceeds from the issuance were used to reduce JCP&L short-term debt and retire senior securities. Also in 1995, JCP&L repurchased $6 million stated value of cumulative preferred stock. The repurchased shares may be used to satisfy future sinking fund requirements.
In March 1996, JCP&L and Penelec expect to redeem approximately $26 million and $25 million principal amount of 6 1/8% series and 6 1/4% series FMBs, respectively, using lower cost short-term debt.
Present plans call for the Subsidiaries to issue long-term debt during the next three years to finance construction activities, fund the redemption of maturing senior securities, and depending on interest rates, refinance outstanding senior securities. In addition, significant further investments by the EI Group, or otherwise, may require GPU to issue additional debt and/or new shares of common stock.
During 1995, the Subsidiaries refinanced their nuclear fuel lease agreements with nonaffiliated fuel trusts. The new lease arrangements provide that an aggregate of up to $210 million ($100 million for Oyster Creek and $110 million for 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.
LIMITATIONS ON ISSUING ADDITIONAL SECURITIES
The Subsidiaries' FMB indentures and/or charters contain provisions which limit the total amount of securities evidencing secured indebtedness and/or unsecured indebtedness which the Subsidiaries may issue, the more restrictive of which are discussed below.
The Subsidiaries' FMB indentures require that, for a period of any twelve consecutive months out of the fifteen calendar months immediately preceding the issuance of additional FMBs, net earnings (before income taxes, with other income limited to 5% of operating income before income taxes for JCP&L and Met-Ed and 10% for Penelec) available for interest on FMBs shall have been at least twice the annual interest requirements on all FMBs to be outstanding immediately after such issuance. Moreover, the Subsidiaries' FMB indentures restrict the ratio of the principal amount of FMBs which may be issued to not more than 60% of available bondable value of property additions. In addition, the indentures, in general, permit the Subsidiaries to issue additional FMBs against a like principal amount of previously issued and retired FMBs.
At December 31, 1995, the net earnings requirement under the Subsidiaries' FMB indentures, as described above, would have permitted JCP&L, Met-Ed and Penelec to issue $1.3 billion, $537 million and $724 million, respectively, principal amount of additional FMBs at an assumed 8% interest rate. However, the Subsidiaries had bondable value of property additions sufficient to permit JCP&L, Met-Ed and Penelec to only issue approximately $330 million, $383 million and $236 million, respectively, principal amount of additional FMBs. In addition, the Subsidiaries' FMB indentures would have permitted JCP&L, Met-Ed and Penelec to issue approximately $316 million, $46 million and $107 million, respectively, of FMBs against a like principal amount of previously issued and retired FMBs.
Among other restrictions, the Subsidiaries' charters provide that without the consent of the holders of two-thirds of the outstanding preferred stock, no additional shares of preferred stock may be issued unless, for a period of any twelve consecutive months out of the fifteen calendar months immediately preceding such issuance, the after-tax net earnings available for the payment of interest on indebtedness shall have been at least one and one-half times the aggregate of (a) the annual interest charges on indebtedness and (b) the annual dividend requirements on all shares of preferred stock to be outstanding immediately after such issuance. At December 31, 1995, these provisions would have permitted JCP&L, Met-Ed and Penelec to issue $1.2 billion, $1.0 billion and $778 million, respectively, stated value of cumulative preferred stock at an assumed 7.5% dividend rate.
The Subsidiaries' charters also provide that, without the consent of the holders of a majority of the total voting power of the Subsidiaries' outstanding preferred stock, the Subsidiaries may not issue or assume any securities representing short-term unsecured indebtedness, except to refund certain outstanding unsecured securities issued or assumed by the Subsidiaries or to redeem all outstanding preferred stock, if immediately thereafter the total principal amount of all outstanding unsecured debt securities having an initial maturity of less than ten years (or within 3 years of maturity for JCP&L) would exceed 10% of the aggregate of (a) the total principal amount of all outstanding secured indebtedness issued or assumed by the Subsidiaries and (b) the capital and surplus of the Subsidiaries. At December 31, 1995, these
restrictions would have permitted JCP&L, Met-Ed and Penelec to have approximately $288 million, $132 million and $147 million, respectively, of unsecured indebtedness outstanding.
The Subsidiaries have obtained authorization from the SEC to incur short- term debt (including indebtedness under the Credit Agreement and commercial paper) up to the Subsidiaries' charter limitations.
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 NJBPU and in Pennsylvania by the PaPUC. Additionally, Penelec, as lessee, operates the facilities serving the village of Waverly, New York. Penelec's retail rates for New York customers, as well as Penelec's New York operations and property, are subject to regulation by the New York Public Service Commission. Although Penelec does not render electric service in Maryland, the Public Service Commission of Maryland has jurisdiction over the portion of Penelec's property located in that state. 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. JCP&L is also subject, in certain respects, to regulation by the PaPUC in connection with its participation in the ownership and operation of certain facilities located in Pennsylvania. (See ELECTRIC GENERATION AND THE ENVIRONMENT - Environmental Matters for additional regulation to which the Subsidiaries are or may be subject.)
Solaris, EI Energy's electric distribution subsidiary in Australia, is subject to regulation by the Office of the Regulator General. Solaris' network and connection charges are subject to regulatory review every five years, with the next review scheduled for January 1, 2000. In addition, Solaris' franchise license becomes nonexclusive in stages through the year 2001, at which time all customers will be permitted to choose their source of electric supply. Empresa Guaracachi S.A., EI Power's electric generation subsidiary in Bolivia, is subject to regulation under the Electricity Law of 1994. Twice each year, the Superintendency of Electricity recalculates the prices that Empresa Guaracachi S.A. and other electric generators may charge for capacity based upon an estimated cost of constructing a new generating unit. In addition, energy prices are recalculated semi-annually based upon a projected cost of generation, including fuel and nonfuel variable operation and maintenance costs.
ELECTRIC GENERATION AND THE ENVIRONMENT
Fuel
The Subsidiaries utilized fuels in the generation of electric energy during 1995 in approximately the following percentages:
GPU JCP&L Met-Ed Penelec
Coal 58% 20% 56% 88% Nuclear 38% 71% 41% 13% Gas 3% 7% 2% - Oil 1% 3% - - Other* - (1)% 1% (1)%
* Represents hydro and pumped storage (which is a net user of electricity).
Approximately 41% (JCP&L 56%; Met-Ed 40%; Penelec 32%) of the Subsidiaries' total energy requirements in 1995 was supplied by purchases and interchange from other utilities and NUGs. For 1996, the Subsidiaries estimate that their generation of electric energy will be in the following proportions:
GPU JCP&L Met-Ed Penelec
Coal 62% 25% 55% 88% Nuclear 34% 66% 41% 12% Gas 3% 10% 2% - Oil 1% 3% - - Other* - (4)% 2% -
* Represents hydro and pumped storage.
The anticipated changes in 1996 fuel utilization percentages are principally attributable to a refueling outage at Oyster Creek scheduled for September 1996. Approximately 41% (JCP&L 60%; Met-Ed 38%; Penelec 27%) of the Subsidiaries' 1996 energy requirements are expected to be supplied by purchases and interchange from other utilities and NUGs.
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 (JCP&L - 16.67% ownership interest in Keystone; Met-Ed - 16.45% ownership interest in Conemaugh; and Penelec - 50% ownership interest in Homer City). The contracts, which expire between 1996 and 2004, require the purchase of either fixed or minimum amounts of coal. The price of the coal under the contracts is based on adjustments of indexed cost components. One of Penelec's contracts for Homer City also includes a provision for the payment of postretirement benefits costs. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $115 million (JCP&L $20 million; Met-Ed $18 million; Penelec $77 million) for 1996.
The Subsidiaries' coal-fired generating stations now in service are estimated to require an aggregate of 167 million tons (JCP&L 15 million tons; Met-Ed 41 million tons; Penelec 111 million tons) of coal over the next twenty years. Of this total requirement, approximately 10 million tons (JCP&L 3 million tons; Penelec 7 million tons) are expected to be supplied by
nonaffiliated mine-mouth coal companies with the balance supplied through short- and 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. As a result of completion of an interim spent fuel dry storage facility in early 1996, Oyster Creek also 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.
Environmental Matters
The GPU System is subject to a broad range of federal, state and local environmental and employee health and safety legislation and regulations. 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, decommission or clean up waste disposal and other sites currently or formerly used by it, including formerly owned MGPs and mine refuse piles and generating facilities, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material. The consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant, are unknown. The GPU System 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. Additionally, water quality-based effluent limits (more stringent than "technology" limits) may be applied to utility waste water discharges based on receiving stream quality. 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."
The U.S. Environmental Protection Agency (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 are required for all of the Subsidiaries' steam generating stations. JCP&L's discharge permits have expired, and timely reapplications have been filed as required by regulations. Until new permits are issued, JCP&L's currently expired permits remain in effect. JCP&L has also filed an application with the New Jersey Department of Environmental Protection (NJDEP) for a discharge permit for its Yards Creek pumped storage facility. Discharge permits have been reissued for Met-Ed's Titus and York Haven stations and administratively extended for the Portland station pending action by the Pennsylvania Department of Environmental Protection (PaDEP) on timely reapplication. Penelec has obtained all required discharge permits.
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 NJDEP 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 October 1994, following six years of studies, the NJDEP issued a new Discharge to Surface Water Permit for the Oyster Creek station. The new permit grants JCP&L a variance from the New Jersey Surface Water Quality Standards. The variance allows the continued operation of the existing once-through cooling system without modifications such as cooling towers. The variance is effective through October 1999. The NJDEP could revoke the variance at any time upon failure to comply with the permit conditions.
The NJDEP 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 NJDEP 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 NJDEP'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 PaDEP and the NJDEP.
In 1993, York Haven Power Company, a wholly-owned subsidiary of Met-Ed, entered into an agreement with various agencies to construct a fish passage facility at the York Haven hydroelectric project by the year 2000. The present estimated installed cost of the facility is $8.5 million. Construction is expected to begin in 1998.
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 Connecticut have established the Northeast Compact, to construct a low level radioactive waste (radwaste) disposal facility in New Jersey. The estimated cost to license and build the facility is $100 million. GPUN's minimum expected $29.5 million share of the cost for this facility is to be paid annually over a six-year period from 1992 to 1997. In a February 1993 rate order, the NJBPU authorized JCP&L to recover these amounts currently from customers. Through December 1995, $6 million has been paid. The development of the facility is expected to continue after 1997 which will most likely result in additional costs in excess of $29.5 million.
Pennsylvania, Delaware, Maryland and West Virginia have established the Appalachian Compact (which includes eleven nuclear power plants - 9 in Pennsylvania and 2 in Maryland) to construct a facility for the disposal of low level radwaste in those states, including low level radwaste from TMI-1. To date $33 million, of a minimum estimated $88 million, of pre-construction costs has been paid. The eleven plants have so far shared equally in the pre- construction cost, including GPUN which has contributed $3 million. All contributors, including nonutility radwaste producers within the compact that make voluntary contributions, will receive certain credits from surcharges paid by all depositors of waste over a ten-year period. The methodology for the allocation of these credits has yet to be determined. In addition, $50 million of estimated construction costs will be funded by an independent contractor and recovered by the contractor through waste disposal fees collected during the first five years of the facility's operation.
GPUN is currently shipping low level radwaste to the Barnwell, South Carolina radwaste disposal site. The development of the Northeast Compact disposal facility is expected to continue beyond 1997, the projected completion date. The Appalachian Compact disposal facility is currently scheduled to open in June 1999. Continuing delays in the completion of the disposal facilities will require GPUN to perform an evaluation of its ability to safely store radwaste beyond these dates.
The Subsidiaries have provided for future contributions to the Decontamination and Decommissioning Fund (part of the EPAct) for the cleanup of uranium enrichment plants operated by the Federal Government. The GPU System's total liability at December 31, 1995 amounted to $36 million (JCP&L $23 million; Met-Ed $9 million; Penelec $4 million). The Subsidiaries made their initial payment in 1993. The remaining amount recoverable from ratepayers at December 31, 1995 is $39 million (JCP&L $25 million; Met-Ed $9 million; Penelec $5 million).
Air: The Subsidiaries are subject to certain state environmental regulations of the NJDEP and the PaDEP. The Subsidiaries are also subject to certain federal environmental regulations of the EPA.
Current Pennsylvania environmental regulations prescribe criteria that generally limit the sulfur dioxide content of stack gas emissions from Penelec's 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. In the case of Met-Ed's facilities, the sulfur dioxide content of stack gas emissions is limited to 2.8 pounds or 3.7 pounds per million BTU of heat input depending on location. On a weighted average basis, the Subsidiaries have been able to obtain coal with 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 dioxide control equipment that may require substantial capital expenditures as well as substantial additional operating costs. Such retrofitting 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 years 1995 and 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 (the acid rain provisions) of the Clean Air Act, the GPU System expects to spend up to $410 million (JCP&L $42 million; Met-Ed $158 million; Penelec $210 million) for air pollution control equipment by the year 2000, of which approximately $234 million (JCP&L $41 million; Met-Ed $100 million; Penelec $93 million) has been spent as of December 31, 1995. The capital costs of equipment are for the installation of scrubbers, low NOx burner technology, selective noncatalytic reduction and particulate removal 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 but recovery is not assured. The second of two scrubbers was completed at the Conemaugh station during 1995. This action is part of the GPU System's plans to comply with Clean Air Act sulfur dioxide emission limitations. 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 station and other environmental compliance projects. The plan for the Portland station is to meet its Phase I compliance obligation through the use of sulfur dioxide emission allowances, including allowances allocated directly to Portland station by the EPA and allowances resulting from the installation of scrubbers at the Conemaugh station. Shawville station will require lower sulfur coal and/or the purchase of emission allowances to meet its Phase I requirements.
The GPU System's current strategy for Phase II compliance under Title IV of the Clean Air Act is to evaluate the installation of scrubbers, the use of fuel switching and allowances at the Keystone station and at the Homer City Unit 3 station. Switching to lower sulfur coal and/or the purchasing of allowances is currently planned for the Titus, Seward, Portland, Shawville and Warren stations. Homer City Units 1 and 2 will use existing coal cleaning technology. Additional control modifications are not expected to be necessary for compliance with Title IV in Phase II at Conemaugh, Gilbert and Sayreville stations.
The GPU System continues to reassess its options for compliance with the Clean Air Act including those that may result from the continued development of the emission trading allowance 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 region that includes 12 northeast states and the District of Columbia identified as the Ozone Transport Region (OTR). Pennsylvania and New Jersey are part of the OTR, and will be required to control NOx emissions to a level that will provide for the attainment of the ozone standard in the Northeast. As an initial step, major sources of NOx were required to implement Reasonably Available Control Technology (RACT) by May 31, 1995. Compliance with the PaDEP's RACT regulations has been achieved through operational modifications and installation of low NOx burners with separate overfire air at the Keystone, Titus, Portland and Conemaugh stations. An extension of time has been obtained to bring Homer City Units 1 and 2 into compliance with the PaDEP's RACT regulations. The NJDEP's RACT 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 NJDEP. A Memorandum of Understanding (MOU) has been signed by the members of the Ozone Transport Commission (OTC). This calls for inner and outer zones with seasonal NOx emission reductions of 65% and 55%, from 1990 emission levels, respectively, by May 1, 1999. Met-Ed and Penelec will spend an estimated $10 million and $50 million, respectively, to meet the reductions set by the OTC. The MOU also calls for a 75% reduction by May 2003, unless scientific data shows this level of reduction is unnecessary to achieve the Clean Air Act's 2005 National Ambient Air Quality Standard (NAAQS) for ozone. The ultimate impact of Title III of the Clean Air Act, which deals with emissions of hazardous air pollutants, is also highly uncertain. Specifically, the EPA has not completed a Clean Air Act study to determine whether it is appropriate to regulate emissions of hazardous air pollutants from electric utility steam generating units.
Both the EPA and the PaDEP are questioning the attainment of 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 stations are jointly owned with nonaffiliated utilities. The EPA and the PaDEP have approved the use of a nonguideline air quality model to evaluate the ambient air quality impacts of these generating stations. This nonguideline 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 station has been designated as nonattainment for sulfur dioxide. In early 1993, Penelec began a model evaluation study of the area. The PaDEP and the EPA have approved the use of the nonguideline model which is more representative than guideline models. A model evaluation study has also been conducted at Shawville station. The results of this
study, which remain subject to PaDEP approval, show attainment of the NAAQS at the Shawville station with current Pennsylvania sulfur dioxide emission limits.
The sulfur dioxide 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 compliance with NAAQS, significant sulfur dioxide reductions may be required at one or more of these stations which could result in significant 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 intended to reduce greenhouse gas emissions to 1990 levels by the year 2000. The Climate Change Action Plan relies heavily on voluntary action by industry. GPU has joined approximately 150 other electric utility companies by signing an accord that is part of the Department of Energy Climate Challenge Program. The GPU System's program is expected to avoid or reduce the equivalent of 8 million tons of carbon dioxide emissions between 1995 and 2000.
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 JCP&L, Met-Ed and Penelec's Phase I and Phase II affected units as required by EPA, NJDEP and PaDEP regulations.
The PaDEP 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 and Penelec's generating stations for 1995, 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 stations under the applicable stack height regulations. 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 and the PaDEP 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 NJDEP and the NJBPU 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 NJDEP and the NJBPU.
In New Jersey, where the bulk of the GPU System's oil-fired generating capacity is located, NJDEP regulations establish that the maximum sulfur content of No. 6 fuel oil may not exceed .3% for most of JCP&L's generating stations and 1% for the balance. For No. 2 fuel oil, the sulfur content may not exceed .2% for most of JCP&L's generating stations and .3% for the balance.
In 1995, the Subsidiaries made capital expenditures of approximately $93 million (JCP&L $36 million; Met-Ed $14 million; Penelec $43 million) in response to environmental considerations and have budgeted approximately $18 million (JCP&L $3 million; Met-Ed $3 million; Penelec $12 million) for this purpose in 1996. The incremental annual operating and maintenance costs for such equipment is expected to be immaterial.
Electromagnetic Fields: There have been a number of studies regarding the possibility of adverse health effects from electric and power frequency magnetic fields that are found everywhere there is electricity. While some of the studies have indicated some association between exposure to magnetic fields and cancer, other studies have indicated no such association. The studies have not shown any causal relationship between exposure to magnetic fields and cancer, or any other adverse health effects. In 1990, the EPA issued a draft report that identifies magnetic fields as a possible carcinogen, although it acknowledged 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." In 1994, results of a large-scale epidemiology study of electric utility workers suggested a statistical relationship between brain cancer and the class of workers who received the highest exposure. These
findings conflicted with two earlier large-scale studies that found no such relationship. Additional studies, which may foster a better understanding of the subject, are presently underway.
Certain parties have alleged that the exposure to electric and magnetic fields 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 NJDEP and bills introduced in the Pennsylvania legislature could, if enacted, establish a framework under which the intensity of the fields 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 their respective results of operations and financial position.
Residual Waste: PaDEP residual waste regulations 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.
The regulations require, among other things, 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 data. All of Penelec's active landfills require assessments. If the assessments show degradation of the groundwater, Penelec would be required to develop abatement plans. Penelec and Met-Ed's landfills had preliminary permit modification applications submitted to the PaDEP by July 1994, and complete permit applications must be under evaluation by July 1997. Met-Ed's Portland and Titus landfills have had preliminary assessments proposed which are currently under review by the PaDEP. Additional data will be collected and evaluated to determine if degradation has occurred and if development of abatement plans is necessary. The Titus station ash disposal site was upgraded in 1991 and now meets many of the 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, including beneficial uses of coal ash.
Other compliance requirements at Penelec that may need to 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 ("clean closure") 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 the PaDEP can require this at any time prior to this date or, at its discretion, defer full compliance beyond 2002 for some storage impoundments. Also being evaluated are the options for beneficial use of ash 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. New groundwater monitoring wells were installed at the Titus station. The Portland station assessment plan is pending with the PaDEP. 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 Penelec's facility compliance upgrades.
Hazardous/Toxic Wastes: Under the Toxic Substances Control Act (TSCA), the EPA has adopted certain regulations governing the use, storage, testing, inspection and disposal of electrical equipment that contains polychlorinated biphenyls (PCBs). Such regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs. The 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 MGPs in New Jersey and Pennsylvania. Waste contamination associated with the operation and dismantlement of these MGPs, are or may be present, both on-site and off-site. Claims have been asserted against the Subsidiaries for the cost of investigation and remediation of these sites. The amount of such remediation costs and penalties may be significant and may not be covered by insurance. To date, JCP&L has identified 17 former MGP sites and two off-site properties where waste may have been sent. 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 NJDEP for seven of these sites and has entered into Memoranda of Agreement (MOAs) with the NJDEP 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 NJDEP for remediation of the sites. The MOAs afford JCP&L greater flexibility in the schedule for investigation and remediation of sites.
As of December 31, 1995, JCP&L has an estimated environmental liability of $29 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 future costs may range as high as $50 million. Estimates of these costs are subject to significant uncertainties because: JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $50 million.
In December 1995, JCP&L filed a petition with the NJBPU to implement, concurrent with the its proposed March 1996 LEAC change, a Manufactured Gas Plant Remediation Adjustment Clause for the recovery of underrecovered MGP costs (see RATE PROCEEDINGS - New Jersey).
In 1994, JCP&L filed a complaint with the New Jersey Superior Court against several of its insurance carriers, relating to these MGP sites. JCP&L requested the Court to order the insurance carriers to reimburse JCP&L for all amounts it has paid, or may be required to pay, in connection with the remediation of the sites. Pretrial discovery has begun in this case.
The 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 PaDEP and the NJDEP, 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 11 hazardous and/or toxic waste sites (including those described below).
JCP&L MET-ED PENELEC GPUN GPU TOTAL
PRPs 6 4 2 1 1 11*
* In some cases, the Subsidiaries are named separately for the same site.
In addition, the Subsidiaries have been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which they have not yet been named as PRPs. The Subsidiaries have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. At December 31, 1995, the Subsidiaries have liabilities recorded on their balance sheets for environmental matters (in addition to the $29 million for JCP&L's MGP sites) totaling $8.2 million (JCP&L $6.6 million; Met-Ed $900 thousand; Penelec $700 thousand).
JCP&L, Met-Ed and GPUN 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. A negotiated settlement among all parties has been finalized and cleanup efforts have begun. The interim remediation work is estimated to cost $63 million, for which all responsible parties will be jointly and severally liable. The estimated allocation, which is based upon a percentage of the total volume of waste believed shipped to the site, is JCP&L $1.1 million, Met-Ed $400 thousand and GPUN $150 thousand.
In 1994, JCP&L received a letter from the EPA notifying it of potential liability for the disposal of PCB liquids and related equipment at the Kansas City, Missouri site of PCB Treatment, Incorporated. JCP&L's cleanup cost obligation is currently estimated to be $1.3 million based upon a percentage allocation of waste delivered by JCP&L to the site. The ultimate costs, however, may range as high as $3.3 million if JCP&L becomes liable for the potential nonpayment of other responsible parties. JCP&L is seeking indemnification from its waste broker.
In 1988, JCP&L received a PRP notice from the NJDEP alleging that JCP&L disposed of asbestos at the High Point Sanitary Landfill in Warren County, New Jersey. JCP&L is one of over 20 PRPs at this site. By 1993, JCP&L made payments totaling $131 thousand to the NJDEP for certain remediation investigation and feasibility studies. The extent of JCP&L's obligation for remediation costs, if any, will be subject to the results of additional studies. There can be no assurance as to the outcome of this matter.
Met-Ed received a PRP notice from the PaDEP asserting that Met-Ed disposed of hazardous waste at the Industrial Solvents & Chemical Company site, a former solvents recycler. This site is being remediated under the Pennsylvania Hazardous Sites Cleanup Act. Met-Ed made immaterial payments in 1995 to the PRP group for the removal of tanks, drums and other materials at the site. A feasibility study to determine the extent of ground water contamination is expected to be completed in 1996. Met-Ed cannot reasonably estimate its remaining liability until the feasibility study results are available and the PaDEP selects a remedy for ground water contamination.
Penelec has been named as a PRP by the EPA, along with over 1,000 other PRPs, for allegedly disposing of hazardous materials at the Jack's Creek/Sitken site, a former metals recycling and smelting operation in Mifflin County, Pennsylvania. Penelec joined a PRP group, which is working on the issues presented at the site. The PRP group is also exploring a settlement with the EPA, but Penelec cannot predict the ultimate outcome of the negotiations.
Pursuant to certain federal monitoring requirements, Penelec has reported to the PaDEP that contaminates from coal mine refuse piles were identified in storm water run-off at Penelec's Seward station property. Penelec signed a Consent Order and is negotiating with the PaDEP to determine a schedule for long-term remediation based on possible future operating scenarios, including the installation of fluidized bed combustion technology. If the station is reboilered using this technology, a low cost solution would be to mix the ash from the reboilered station with the existing refuse. Early negotiations with the PaDEP indicate that this approach would be acceptable. If the station is not reboilered using such technology, remediation of the site may be required. Based upon a conceptual engineering report prepared by Penelec, the cost of remediation is estimated to range from $12 million to $25 million. These costs are subject to uncertainties based on the extent of remediation and available technologies. Penelec must notify the PaDEP by December 31, 1996 of its decision.
The ultimate cost of remediation of these sites 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.
The Corporation and its Subsidiaries 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 but realizes recovery is not assured.
FRANCHISES AND CONCESSIONS
JCP&L operates pursuant to franchises in the territory served by it and has the right to occupy and use the public streets and ways of the state with its poles, wires and equipment upon obtaining the consent in writing of the owners of the soil, and also to occupy the public streets and ways underground with its conduits, cables and equipment, where necessary, for its electric operation. JCP&L has the requisite legal franchise for the operation of its electric business within the State of New Jersey, including in incorporated cities and towns where designations of new streets, public ways, etc., may be obtained upon application to such municipalities. JCP&L holds a FERC license expiring in 2013 authorizing it to operate and maintain the Yards Creek pumped storage hydroelectric station in which JCP&L has a 50% ownership interest.
Met-Ed and Penelec have the necessary franchise rights to furnish electric service in the various respective municipalities or territories in which each company now supplies such services. These electric franchise rights, which are generally nonexclusive rights, consist generally of (a) charter rights and (b) certificates of public convenience issued by the PaPUC and/or "grandfather rights". Such electric franchise rights are free from unduly burdensome restrictions and unlimited as to time, except in a few relatively minor cases and except as otherwise described below. The secondary franchise granted by the Borough of Boyertown to Met-Ed contains a provision that the Borough shall have the right at any time to purchase the electric system in the Borough at a valuation to be fixed by appraisers. Met-Ed holds a FERC license expiring in 2014 for the continued operation and maintenance of the York Haven hydroelectric project. Penelec holds a license from the FERC, which expires in 2002, for the continued operation and maintenance of the Piney hydroelectric project. In addition, Penelec and the Cleveland Electric Illuminating Company hold a license expiring in 2015 for the Seneca Pumped Storage Hydroelectric station in which Penelec has a 20% undivided interest. For the same station, Penelec and the Cleveland Electric Illuminating Company hold a Limited Power Permit issued by the Pennsylvania Water and Power Resources Board which is unlimited as to time. For purposes of the Homer City station, Penelec and New York State Electric & Gas Corporation hold a Limited Power Permit issued by the Pennsylvania Water and Power Resources Board which expires in 2017, but is renewable by the permittees until they have recovered all capital invested by them in the project. Penelec also holds a Limited Power Permit issued by the Pennsylvania Water and Power Resources Board for its Shawville station which expires in 2003, but is renewable by Penelec until it has recovered all capital invested in the project.
EMPLOYEE RELATIONS
At February 29, 1996, the GPU System had 10,310 full-time employees (JCP&L 3,049; Met-Ed 2,133; Penelec 2,216; all other companies 2,912). 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, 1997. JCP&L's two-year contract with the IBEW expires on October 31, 1996.
ITEM 2.
ITEM 2. PROPERTIES.
Generating Stations
At December 31, 1995, the generating stations of the Subsidiaries had an aggregate effective capability of 6,592,000 net kilowatts (KW), as follows:
Name of Year of Net KW Station Subsidiary Installation (Summer) COAL-FIRED: Homer City(a) Penelec 1969-1977 942,000 Shawville Penelec 1954-1960 597,000 Portland Met-Ed 1958-1962 401,000 Keystone(b) JCP&L 1967-1968 283,000 Conemaugh(c) Met-Ed 1970-1971 280,000 Titus(d) Met-Ed 1951-1953 243,000 Seward Penelec 1950-1957 196,000 Warren Penelec 1948-1949 82,000
NUCLEAR: TMI-1(e) All 1974 786,000 Oyster Creek(f) JCP&L 1969 619,000
GAS/OIL-FIRED: Sayreville JCP&L 1930-1958 229,000 Gilbert(g) JCP&L 1930-1949 72,000 Combustion Turbines(h) All 1960-1989 1,160,000 Werner(i) JCP&L 1953 58,000 Other(j) All 1968-1977 298,000 Hydroelectric(k) Met-Ed/Penelec 1905-1969 64,000
PUMPED STORAGE:(l) Yards Creek JCP&L 1965 195,000 Seneca Penelec 1969 87,000 TOTAL 6,592,000
Aggregate Effective Capability by Subsidiary
Net KW (Summer) (Winter) JCP&L 2,704,000 3,068,000 Met-Ed 1,604,000 1,705,000 Penelec 2,284,000 2,365,000 TOTAL 6,592,000 7,138,000
(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 June 19, 1995, the Titus station was rerated from 241,000 KW.
(e) Jointly owned by JCP&L, Met-Ed and Penelec in percentages of 25%, 50% and 25%, respectively.
(f) Effective January 17, 1995, the Oyster Creek station was rerated from 610,000 KW.
(g) Effective November 1, 1995, 45,000 KW of capability were retired. JCP&L announced plans to close this station in 1996.
(h) JCP&L - 762,000 KW, Met-Ed - 266,000 KW and Penelec 132,000 KW.
(i) JCP&L announced plans to close this station in 1996.
(j) Consists of internal combustion and combined-cycle units (JCP&L - 290,000 KW, Met-Ed - 2,000 KW and Penelec - 6,000 KW).
(k) Consists of Met-Ed's York Haven station (19,000 KW) and Penelec's Piney (27,000 KW) and Deep Creek stations (18,000 KW).
(l) Represents the Subsidiaries' undivided interests in these stations which are net users rather than net producers of electric energy. Effective June 1, 1995, the Yards Creek station was rerated from 190,000 KW.
The Subsidiaries' 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 Subsidiaries' 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 FMB indentures.
The peak loads of the GPU System and its Subsidiaries were as follows:
(In KW) Company Date Peak Load
GPU Aug. 2, 1995 9,101,000 JCP&L July 9, 1993 4,564,000 Met-Ed Aug. 2, 1995 2,186,000 Penelec Dec. 11, 1995 2,589,000
EI Group Facilities
The EI Group has ownership interests in sixteen natural gas-fired cogeneration and other nonutility power production facilities located in the United States, South America and Canada with an aggregate capability of 1,412,000 KW as follows:
U.S. Facilities
Name of Year of EI Ownership Facility Location Installation Total KW Interest (KW)
Selkirk NY 1992/94 350,000 70,000 Lake* FL 1993 112,000 47,150 Pasco* FL 1993 112,000 56,000 Onondaga* NY 1993 80,000 40,000 Syracuse* NY 1992 80,000 3,500 Marcal* NJ 1989 65,000 32,500 Ada* MI 1991 29,000 290 Camarillo* CA 1988 27,000 13,500 Chino* CA 1987 27,000 13,500 FPB CA 1983 26,000 7,800 Berkeley* CA 1987 24,000 12,000 Total 932,000 296,240
Non-U.S. Facilities
Termobarran- quilla* Colombia 1972-83 240,000 72,000 Guaracachi* Bolivia 1975-94 161,000 80,500 Aranjuez* Bolivia 1974-94 40,000 20,000 Karachipampa* Bolivia 1982 15,000 7,500 Brooklyn* Canada 1996 24,000 18,000 Total 480,000 198,000
Total capability 1,412,000 494,240
* The EI Group has operating responsibility for these facilities.
Transmission and Distribution System
At December 31, 1995, the GPU System owned the following: GPU System JCP&L Met-Ed Penelec Total Transmission and Distribution Substations 296 288 468 1,052
Aggregate Installed Transformer Capacity of Substations (in kilovoltamperes - KVA) 20,893,974 11,827,100 15,914,320 48,635,394
Transmission System:
Lines (In Circuit Miles):
500 KV 18 188 235 441 345 KV - - 149 149 230 KV 570 383 650 1,603 138 KV - 3 11 14 115 KV 232 361 1,325 1,918 69 KV, 46 KV and 34.5 KV 1,760 472 364 2,596 Total 2,580 1,407 2,734 6,721
Distribution System:
Line Transformer Capacity (KVA) 9,618,670 5,654,976 6,213,003 21,486,649
Pole Miles of Overhead Lines 15,649 12,613 22,797 51,059
Trench Miles of Underground Cable 6,738 1,943 1,834 10,515
In addition, Solaris provides service to more than 230,000 customers in and around a 385 square mile area in Melbourne, Australia (see THE EI GROUP under Item 1). Solaris owns a total of 3,629 pole miles of overhead lines.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to NUCLEAR FACILITIES - TMI-2, RATE PROCEEDINGS, and ELECTRIC GENERATION AND THE ENVIRONMENT - Environmental Matters under Item 1 and to Note 1 to GPU's 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.
All of JCP&L, Met-Ed and Penelec's outstanding common stock is owned by GPU. During 1995, the Subsidiaries paid dividends on their common stock to GPU as follows: JCP&L $140 million, Met-Ed $95 million and Penelec $75 million.
In accordance with the Subsidiaries' FMB indentures, as supplemented, the balances of retained earnings at December 31, 1995 that are restricted as to the payment of dividends on their common stock are as follows:
JCP&L - $1.7 million Met-Ed - $3.4 million Penelec - $10 million
Stock Trading
General Public Utilities Corporation is listed as GPU on the New York Stock Exchange. On February 1, 1996, there were approximately 46,300 registered holders of GPU common stock.
Dividends
GPU common stock 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 1995 and 1994 are set forth below.
Common Stock
Dividends Declared Price Ranges* 1995 1994 1995 1994 Quarter High/Low High/Low
April $.47 $.45 First $30 5/8 26 1/4 $30 7/8 $27 5/8 June .47 .45 Second 31 28 1/4 31 5/8 26 October .47 .45 Third 31 1/4 28 1/8 27 1/2 23 3/4 December .47 .45 Fourth 34 30 5/8 26 7/8 24
* Based on New York Stock Exchange Composite Transactions as reported in the Wall Street Journal.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
See pages and for references to each registrant's Selected Financial Data required by this item.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
See pages and for references to each registrant's 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 pages and for references to each registrant's Financial Statements and Quarterly Financial Data (unaudited) required by this item.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Identification of Directors
Information regarding GPU's directors is incorporated by reference to pages 2 through 4 of GPU's Proxy Statement for the 1996 Annual Meeting of Stockholders. The current directors of JCP&L, Met-Ed and Penelec, their ages, positions held and business experience during the past five years are as follows: Year First Name Age Position Elected JCP&L: J. R. Leva (a) 63 Chairman of the Board 1986 and Chief Executive Officer D. Baldassari (b) 46 President 1982 R. C. Arnold (c) 58 Director 1989 J. G. Graham (d) 57 Vice President and Chief 1986 Financial Officer M. P. Morrell (e) 47 Vice President 1993 G. E. Persson (f) 64 Director 1983 D. W. Myers (g) 51 Vice President and Comptroller 1994 S. C. Van Ness (h) 62 Director 1983 S. B. Wiley (i) 66 Director 1982
Year First Elected Met-Ed/Penelec: Met-Ed Penelec J. R. Leva (a) 63 Chairman of the Board 1992 1992 and Chief Executive Officer F. D. Hafer (j) 54 President 1978 1994 J. G. Graham (d) 57 Vice President and 1986 1986 Chief Financial Officer J. F. Furst (k) 49 Vice President 1994 1994 G. R. Repko (l) 50 Vice President 1994 1993 R. S. Zechman (m) 52 Vice President 1994 1994 R. C. Arnold (c) 58 Director 1989 1989
(a) Mr. Leva is also Chairman, President, Chief Executive Officer and a director of GPUSC; Chairman, Chief Executive Officer and a director of Genco; and Chairman and a director of GPUN, Energy Initiatives, Inc. (EI), EI Power, Inc. (EI Power), and EI Energy, Inc. (EI Energy), all subsidiaries of GPU. Prior to 1992, Mr. Leva served as President of JCP&L since 1986. Mr. Leva is also a director of Utilities Mutual Insurance Company.
(b) Mr. Baldassari was elected President of JCP&L in 1992. Prior to that, Mr. Baldassari served as Vice President - Materials & Services of JCP&L since 1990. Mr. Baldassari is also a director of GPUSC, GPUN, Genco and First Morris Bank of Morristown, NJ.
(c) Mr. Arnold has been Executive Vice President-Power Supply of GPUSC since 1990. He is also a director of GPUSC and Genco.
(d) Mr. Graham was elected Senior Vice President of GPU in 1989. He is also Executive Vice President, Chief Financial Officer and a director of GPUSC; Vice President and Chief Financial Officer of GPUN; and a director of Genco, EI, EI Power and EI Energy. Mr. Graham is also a director of Edisto Resources, Inc., Nuclear Electric Insurance Limited, Nuclear Mutual Limited and Utilities Mutual Insurance Company.
(e) Mr. Morrell became Vice President - Regulatory and Public Affairs in 1994. Prior to that, Mr. Morrell served as Vice President of GPU since 1989. He is also a director of Utilities Mutual Insurance Company.
(f) Mrs. Persson serves as liaison (Special Assistant Director) between the N.J. Division of Consumer Affairs and various State Boards. Prior to 1995, she was owner and President of Business Dynamics Associates of Red Bank, NJ. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College.
(g) Prior to 1994, Mr. Myers served as Vice President and Treasurer of GPU, GPUSC, JCP&L, Met-Ed and Penelec since 1993. He served as Vice President and Comptroller of GPUN from 1986 to 1993.
(h) Mr. Van Ness has been affiliated with the law firm of Pico, Mack, Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since 1990. He is also a director of The Prudential Insurance Company of America.
(i) Mr. Wiley has been a partner in the law firm of Wiley, Malehorn and Sirota of Morristown, NJ since 1973. He is also Chairman of First Morris Bank of Morristown, NJ.
(j) Mr. Hafer became President of Met-Ed and Penelec in 1994. Prior to that, he was President of Met-Ed since 1986. Mr. Hafer is also a director of GPUSC, GPUN, Genco, Meridian Bancorp, Meridian Bank of Reading, PA and Utilities Mutual Insurance Company.
(k) Mr. Furst was elected Vice President - Rates & Marketing of Met-Ed and Penelec in 1994. Prior to that, he served as Vice President - Customer Services of Penelec since 1984.
(l) Mr. Repko was elected Vice President - Customer Services and Operations of Met-Ed and Penelec in 1994. Prior to that, he served as Vice President - Division Operations of Penelec from 1986 to 1993.
(m) Mr. Zechman was elected Vice President-Administration and Finance of Met-Ed and Penelec in 1994. Prior to that, he served as Vice President - Administrative Services of Met-Ed since 1992 and as Vice President - Human Resources of Met-Ed from 1990 to 1992.
The directors of the Subsidiaries are elected at their respective annual meetings of stockholders to serve until the next meeting of stockholders and until their respective successors are duly elected and qualified. There are no family relationships among the directors of the Subsidiaries.
Identification of Executive Officers
The current executive officers of GPU, JCP&L, Met-Ed and Penelec, their ages, positions held and business experience during the past five years are as follows:
Year First Name Age Position Elected GPU: J. R. Leva (a) 63 Chairman, President and Chief 1992 Executive Officer I. H. Jolles (b) 57 Senior Vice President and General 1990 Counsel J. G. Graham (c) 57 Senior Vice President and Chief 1987 Financial Officer F. A. Donofrio (d) 53 Vice President, Comptroller and 1985 Chief Accounting Officer P. C. Mezey (e) 56 Senior Vice President, GPUSC 1992 T. G. Howson (f) 47 Vice President and Treasurer 1994 M. A. Nalewako (g) 61 Secretary 1988 T. G. Broughton (h) 50 President, GPUN 1996 R. L. Wise (i) 52 President, Genco 1994 F. D. Hafer (j) 54 President, Met-Ed and Penelec 1994 D. Baldassari (k) 46 President, JCP&L 1992 B. L. Levy (l) 40 President and Chief Executive 1991 Officer, EI, EI Power and EI Energy R. C. Arnold (m) 58 Executive Vice President, GPUSC 1990
JCP&L: J. R. Leva (a) 63 Chairman of the Board and Chief 1992 Executive Officer D. Baldassari (k) 46 President 1992 C. R. Fruehling 60 Vice President - Engineering and 1982 Operations J. G. Graham (c) 57 Vice President and Chief 1987 Financial Officer E. J. McCarthy (n) 57 Vice President - Customer Operations 1982 and Sales M. P. Morrell (o) 47 Vice President - Regulatory 1993 and Public Affairs T. G. Howson (f) 47 Vice President and Treasurer 1994 D. W. Myers (p) 51 Vice President - Operations Support 1994 and Comptroller R. J. Toole (q) 53 Vice President - Generation 1990 J. J. Westervelt (r) 55 Vice President - Human Resources 1982 and Corporate Services R. S. Cohen 53 Secretary and Corporate Counsel 1986
Year First Elected Name Age Position Met-Ed Penelec Met-Ed/Penelec: J. R. Leva (a) 63 Chairman of the Board and 1992 1992 Chief Executive Officer F. D. Hafer (j) 54 President 1986 1994 J. G. Graham (c) 57 Vice President and Chief Financial Officer 1987 1987 J. F. Furst (s) 49 Vice President - Rates and 1994 1984 Marketing T. G. Howson (f) 47 Vice President and Treasurer 1994 1994 G. R. Repko (t) 50 Vice President - Customer 1994 1986 Services and Operations R. J. Toole (q) 53 Vice President - Generation 1989 1996 R. S. Zechman (u) 52 Vice President - Administration 1990 1994 and Finance D. L. O'Brien 53 Comptroller 1981 1994 W. A. Boquist II (v) 48 Vice President - Legal Services 1994 1994 C. B. Snyder (w) 50 Vice President - Public Affairs 1994 1994 W. C. Matthews II (x) 43 Secretary 1994 1990
(a) See Note (a) on page 47.
(b) Mr. Jolles is also Executive Vice President, General Counsel and a director of GPUSC, General Counsel of GPUN and Genco, and a director of EI, EI Power, EI Energy and Genco.
(c) See Note (d) on page 48.
(d) Mr. Donofrio was elected Vice President of GPU in 1989. He is also Senior Vice President - Financial Controls of GPUSC and a director of GPUSC.
(e) Mr. Mezey was elected Senior Vice President - System Services of GPUSC in 1992 and is a director of EI, EI Power and EI Energy. He previously served as Vice President of GPUSC from January 1991 through March 1992 and President of EI from February 1990 through December 1991.
(f) Mr. Howson is also Vice President and Treasurer of GPUSC, GPUN and Genco. He served as Vice President - Materials, Services and Regulatory Affairs and a director of JCP&L in 1992. Prior to that, he served as Vice President - Corporate Strategic Planning for GPUSC since 1989.
(g) Mrs. Nalewako is also Secretary of GPUSC and Genco and Assistant Secretary of GPUN, JCP&L, Met-Ed and Penelec.
(h) Mr. Broughton previously served as Executive Vice President for GPUN since September 1995. Prior to that, he served as Vice President-TMI of GPUN since 1991. Mr. Broughton is also a director of GPUSC and Genco.
(i) Mr. Wise is also a director of GPUSC, GPUN, Genco, EI, EI Power and EI Energy. He previously served as President, Fossil Generation-GPUSC since 1994. Prior to that, Mr. Wise served as President and a director of Penelec since December 1986. He is also a director of U.S. Bancorp and U.S. National Bank of Johnstown, PA.
(j) See Note (j) on page 48.
(k) See Note (b) on page 47.
(l) Mr. Levy is also a director of EI, EI Power, EI Energy and Genco. He has served as President, Chief Executive Officer and director of EI since 1991. Prior to that, Mr. Levy served as Vice President - Business Development of EI since 1985.
(m) See Note (c) on page 47.
(n) Mr. McCarthy became Vice President - Customer Operations and Sales in 1994. Prior to that, he served as Vice President - Customer Services of JCP&L since 1982.
(o) See Note (e) on page 48.
(p) See Note (g) on page 48.
(q) Mr. Toole was also elected a Vice President and a director of Genco in 1996.
(r) Mr. Westervelt became Vice President - Human Resources and Corporate Services in 1994. Prior to that, he served as Vice President - Human Resources of JCP&L since 1982.
(s) See note (k) on page 48.
(t) See note (l) on page 48.
(u) See note (m) on page 48.
(v) Mr. Boquist also served as Corporate Counsel and Secretary of Met-Ed from 1992 to 1994 and Assistant Secretary of Met-Ed from 1988 to 1992.
(w) Mrs. Snyder also served as Regional Director of Met-Ed from 1991 to 1994. Prior to that, she was Divisional Director of Met-Ed since 1990.
(x) Mr. Matthews was elected Secretary of Met-Ed and Penelec in 1994. Prior to that, he served as Corporate Counsel and Secretary of Penelec from 1990.
The executive officers of the GPU System companies 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 the executive officers.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item with respect to GPU is incorporated by reference to pages 7 through 17 of GPU's Proxy Statement for the 1996 Annual Meeting of Stockholders. The following table sets forth remuneration paid, as required by this Item, to the most highly compensated executive officers of JCP&L, Met-Ed and Penelec for the year ended December 31, 1995.
The managements of Met-Ed and Penelec were combined in a 1994 reorganization. Accordingly, the amounts shown below represent the aggregate remuneration paid to such executive officers by Met-Ed and Penelec during 1995.
(1) "Other Annual Compensation" is composed entirely of the above-market interest accrued on the pre-retirement portion of deferred compensation.
(2) The restricted units issued in 1995 under the 1990 Stock Plan for Employees of GPU Corporation and Subsidiaries (the "1990 Stock Plan") are performance based as shown in the "Long-Term Incentive Plans - Awards in Last Fiscal Year" table (the "LTIP table"). Dividends are paid or accrued on the aggregate restricted shares/units awarded under the 1990 Stock Plan and reinvested.
The aggregate number and value (based on the stock price per share at December 31, 1995) of nonvested restricted shares/units include the amounts shown on the LTIP table and at the end of 1995 were:
Aggregate Aggregate Shares/Units Value JCP&L: D. Baldassari 7,575 $257,550 M. P. Morrell 3,275 $111,350 E. J. McCarthy 2,915 $ 99,110 D. W. Myers 2,990 $101,660 R. S. Cohen 2,750 $ 93,500
Met-Ed/Penelec: F. D. Hafer 8,875 $301,750 R. J. Toole 3,100 $105,400 G. R. Repko 3,000 $102,000 R. S. Zechman 2,815 $ 95,710
(3) Consists of Performance Cash Incentive Awards paid on the 1990 restricted stock awards which have vested under the 1990 Stock Plan. These amounts are designed to compensate recipients of restricted stock/unit awards for the amount of federal and state income taxes that are payable upon vesting of the restricted stock/unit awards. Amounts for Mr. Herbein include Performance Cash Incentive Awards of $10,665 on the 1990 restricted stock award, $57,901 on the 1992, 1993 and 1994 restricted stock awards which vested upon retirement and $29,900 paid in cash in lieu of receiving restricted units in 1995.
(4) As noted above, Mr. Leva is Chairman and Chief Executive Officer of General Public Utilities Corporation and its Subsidiaries. Mr. Leva is compensated by GPUSC for his overall service on behalf of the GPU System and accordingly is not compensated directly by the other subsidiary companies for his services. Information with respect to Mr. Leva's compensation is included on pages 11 through 13 in GPU's 1996 Proxy Statement, which is incorporated herein by reference.
(5) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($7,480), the benefit of interest-free use of the non- term portion of employer paid premiums for split-dollar life insurance ($5,851) and above-market interest accrued on the retirement portion of deferred compensation ($94).
(6) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($1,160) and above-market interest accrued on the retirement portion of deferred compensation ($2).
(7) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($8) and above-market interest accrued on the retirement portion of deferred compensation ($66).
(8) Consists of employer matching contributions under the Savings Plan ($5,280).
(9) Consists of employer matching contributions under the Savings Plan ($5,136), matching contributions under the non-qualified deferred compensation plan ($48) and above-market interest accrued on the retirement portion of deferred compensation ($275).
(10) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($8,280), the benefit of interest-free use of the non- term portion of employer paid premiums for split-dollar life insurance ($8,548) and above-market interest accrued on the retirement portion of deferred compensation ($248).
(11) Mr. Herbein retired as Vice President - Generation of Penelec effective December 31, 1995.
(12) Consists of employer matching contributions under the Savings Plan ($4,600), matching contributions under the non-qualified deferred compensation plan ($1,340) and above-market interest accrued on the retirement portion of deferred compensation ($5,241).
(13) Consists of employer matching contributions under the Savings Plan ($5,740), matching contributions under the non-qualified deferred compensation plan ($944) and above-market interest accrued on the retirement portion of deferred compensation ($278).
(14) Consists of employer matching contributions under the Savings Plan ($6,000) and above-market interest accrued on the retirement portion of deferred compensation ($66).
(15) Consists of employer matching contributions under the Savings Plan ($6,000).
Note: The split-dollar life insurance amounts reported in the "All Other Compensation" column are equal to the present value of the interest-free use of the current year employer paid premiums to the projected date the premiums will be refunded to the respective GPU System companies.
(1) The restricted units issued in 1995 under the 1990 Stock Plan provide for a performance adjustment to the aggregate number of units vesting for the recipient based on the annualized GPU Total Shareholder Return (TSR) percentile ranking against all companies in the Standard & Poor's Electric Utility Index for the period between the award and vesting dates. With a 55th percentile ranking, the performance adjustment would be 100% as reflected in the "Target" column. In the event that the percentile ranking is below the 55th percentile, the performance adjustment would be reduced in steps reaching 0% at the 39th percentile as reflected in the "Threshold" column. Should the TSR percentile ranking exceed the 59th percentile, then the performance adjustment would be increased in steps reaching 200% at the 90th percentile as reflected in the "Maximum" column. The estimated future payouts above are computed based on the number of restricted units awarded for 1995 multiplied by the 1995 year-end market value of $34 per share. Actual payouts under the Plan would be based on the actual number of shares issued and the market value of those shares at the time the restrictions lapse and may be different from those indicated above.
(2) The $29,900 in cash received by Mr. Herbein in lieu of receiving restricted units in 1995 is included in the Summary Compensation Table under LTIP Payouts.
Proposed Remuneration of Executive Officers
None of the named executive officers in the Summary Compensation Table has an employment contract. The compensation of executive officers is determined from time to time by the Personnel & Compensation Committee of the GPU Board of Directors.
Retirement Plans
The GPU System pension plans provide for pension benefits, payable for life after retirement, based upon years of creditable service with the GPU System and the employee's career average compensation as defined below. Under federal law, an employee's pension benefits that may be paid from a qualified trust under a qualified pension plan such as the GPU System plans are subject to certain maximum amounts. The GPU System companies also have adopted non- qualified plans providing that the portion of a participant's pension benefits which, by reason of such limitations or source, cannot be paid from such a qualified trust shall be paid directly on an unfunded basis by the participant's employer.
The following table illustrates the amount of aggregate annual pension benefits from funded and unfunded sources resulting from employer contributions to the qualified trust and direct payments payable upon retirement in 1996 (computed on a single life annuity basis) to persons in specified salary and years of service classifications:
(1) Career Average Compensation is the average annual compensation received from January 1, 1984 to retirement and includes Salary and Bonus. The Career Average Compensation amounts for the following named executive officers differ by more than 10% from the three year average annual compensation set forth in the Summary Compensation Table and are as follows: JCP&L: Messrs. Baldassari - $175,136; Morrell - $128,798; McCarthy - $125,601; Myers - $145,654; Cohen - $111,397 and Met-Ed/Penelec: Messrs. Hafer - $249,444; Herbein - $140,854; Toole - $127,434; Repko - $127,376; Zechman - $110,388.
(2) Years of Creditable Service at December 31, 1995: JCP&L: Messrs. Baldassari - 26 years; Morrell - 24 years; McCarthy - 35 years; Myers - 15 years; Cohen - 27 years and Met-Ed/Penelec: Messrs. Hafer - 33 years; Herbein - 35 years; Toole - 29 years; Repko - 29 years; Zechman - 26 years.
(3) Based on an assumed retirement at age 65 in 1996. To reduce the above amounts to reflect a retirement benefit assuming a continual annuity to a surviving spouse equal to 50% of the annuity payable at retirement, multiply the above benefits by 90%. The estimated annual benefits are not subject to any reduction for Social Security benefits or other offset amounts.
(4) Annual retirement benefits under the basic pension per the above table cannot exceed 55% of the average compensation during the highest paid thirty-six calendar months.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item for GPU is incorporated by reference to page 6 of the GPU Proxy Statement for the 1996 Annual Meeting of Stockholders.
All of the outstanding shares of JCP&L (15,371,270), Met-Ed (859,500) and Penelec (5,290,596) common stock are owned beneficially and of record by the Company's parent, General Public Utilities Corporation, 100 Interpace Parkway, Parsippany, NJ 07054.
The following table sets forth, as of February 1, 1996, the beneficial ownership of equity securities of each of the directors and each of the executive officers named in the Summary Compensation Tables, and of all directors and executive officers of each of the respective GPU System companies as a group. The shares owned by all directors and executive officers as a group constitute less than 1% of the total shares outstanding.
Title of Amount and Nature of Name Security Beneficial Ownership (1) JCP&L: J. R. Leva GPU Common Stock 4,376 Shares - Direct GPU Common Stock 100 Shares - Indirect J. G. Graham GPU Common Stock 4,321 Shares - Direct GPU Common Stock 1,180 Shares - Indirect R. C. Arnold GPU Common Stock 2,231 Shares - Direct GPU Common Stock 3,943 Shares - Indirect D. Baldassari GPU Common Stock 1,061 Shares - Direct R. S. Cohen GPU Common Stock 882 Shares - Direct E. J. McCarthy GPU Common Stock 869 Shares - Direct M. P. Morrell GPU Common Stock 1,126 Shares - Direct D. W. Myers GPU Common Stock 1,008 Shares - Direct G. E. Persson GPU Common Stock None S. C. Van Ness GPU Common Stock None S. B. Wiley GPU Common Stock None
All Directors and GPU Common Stock 19,831 Shares - Direct Officers as a Group GPU Common Stock 5,223 Shares - Indirect
Met-Ed/Penelec: J. R. Leva GPU Common Stock 4,376 Shares - Direct GPU Common Stock 100 Shares - Indirect J. G. Graham GPU Common Stock 4,321 Shares - Direct GPU Common Stock 1,180 Shares - Indirect R. C. Arnold GPU Common Stock 2,231 Shares - Direct GPU Common Stock 3,943 Shares - Indirect J. F. Furst GPU Common Stock 670 Shares - Direct F. D. Hafer GPU Common Stock 4,756 Shares - Direct GPU Common Stock 124 Shares - Indirect G. R. Repko GPU Common Stock 643 Shares - Direct R. J. Toole GPU Common Stock 1,072 Shares - Direct R. S. Zechman GPU Common Stock 947 Shares - Direct
All Directors and GPU Common Stock 22,317 Shares - Direct Officers as a Group GPU Common Stock 5,347 Shares - Indirect
(1) The number of shares owned and the nature of such ownership, not being within the knowledge of the Company, have been furnished by each individual.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) See pages and for references to Financial Statements and Financial Statement Schedules required by this item.
1. Exhibits:
3-A Articles of Incorporation of GPU, as amended through March 27, 1990 - Incorporated by reference to Exhibit 3-A, 1989 Annual Report on Form 10-K, SEC File No. 1-6047.
3-A-1 Articles of Amendment to Articles of Incorporation of GPU dated May 5, 1995 - Incorporated by reference to Exhibit A- 4, Certificate Pursuant to Rule 24, SEC File No. 70-8569.
3-B By-Laws of GPU, as amended June 7, 1990 - Incorporated by reference to Exhibit 3-A, 1990 Annual Report on Form 10-K, SEC File No. 1-6047.
3-C Restated Certificate of Incorporation of JCP&L, as amended - Incorporated by reference to Exhibit 3-A, 1990 Annual Report on Form 10-K, SEC File No. 1-3141.
3-C-1 Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a), Certificate Pursuant to Rule 24, SEC File No. 70-7949.
3-C-2 Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7949.
3-D By-Laws of JCP&L, as amended - Incorporated by reference to Exhibit 3-B, 1993 Annual Report on Form 10-K, SEC File No. 1-3141.
3-E Restated Articles of Incorporation of Met-Ed - Incorporated by reference to Exhibit B-18, 1991 Annual Report of GPU on Form U5S, SEC File No. 30-126.
3-F By-Laws of Met-Ed dated July 27, 1995, as amended.
3-G Restated Articles of Incorporation of Penelec as amended through March 10, 1992 - Incorporated by reference to Exhibit 3A, 1991 Annual Report on Form 10-K, SEC File No. 1- 3522.
3-H By-Laws of Penelec dated July 27, 1995, as amended.
4-A Indenture of JCP&L, dated March 1, 1946, between JCP&L and United States Trust Company of New York, Successor Trustee, as amended and supplemented by eight supplemental indentures dated December 1, 1948 through June 1, 1960 - Incorporated by reference to JCP&L's Instruments of Indebtedness Nos. 1 to 7, inclusive, and 9 and 10 filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-A-1 Ninth Supplemental Indenture of JCP&L, dated November 1, 1962 - Incorporated by reference to Exhibit 2-C, Registration No. 2-20732.
4-A-2 Tenth Supplemental Indenture of JCP&L, dated October 1, 1963 - Incorporated by reference to Exhibit 2-C, Registration No. 2-21645.
4-A-3 Eleventh Supplemental Indenture of JCP&L, dated October 1, 1964 - Incorporated by reference to Exhibit 5-A-3, Registration No. 2-59785.
4-A-4 Twelfth Supplemental Indenture of JCP&L, dated November 1, 1965 - Incorporated by reference to Exhibit 5-A-4, Registration No. 2-59785.
4-A-5 Thirteenth Supplemental Indenture of JCP&L, dated August 1, 1966 - Incorporated by reference to Exhibit 4-C, Registration No. 2-25124.
4-A-6 Fourteenth Supplemental Indenture of JCP&L, dated September 1, 1967 - Incorporated by reference to Exhibit 5-A-6, Registration No. 2-59785.
4-A-7 Fifteenth Supplemental Indenture of JCP&L, dated October 1, 1968 - Incorporated by reference to Exhibit 5-A-7, Registration No. 2-59785.
4-A-8 Sixteenth Supplemental Indenture of JCP&L, dated October 1, 1969 - Incorporated by reference to Exhibit 5-A-8, Registration No. 2-59785.
4-A-9 Seventeenth Supplemental Indenture of JCP&L, dated June 1, 1970 - Incorporated by reference to Exhibit 5-A-9, Registration No. 2-59785.
4-A-10 Eighteenth Supplemental Indenture of JCP&L, dated December 1, 1970 - Incorporated by reference to Exhibit 5-A-10, Registration No. 2-59785.
4-A-11 Nineteenth Supplemental Indenture of JCP&L, dated February 1, 1971 - Incorporated by reference to Exhibit 5-A-11, Registration No. 2-59785.
4-A-12 Twentieth Supplemental Indenture of JCP&L, dated November 1, 1971 - Incorporated by reference to Exhibit 5-A-12, Registration No. 2-59875.
4-A-13 Twenty-first Supplemental Indenture of JCP&L, dated August 1, 1972 - Incorporated by reference to Exhibit 5-A-13, Registration No. 2-59785.
4-A-14 Twenty-second Supplemental Indenture of JCP&L, dated August 1, 1973 - Incorporated by reference to Exhibit 5-A-14, Registration No. 2-59785.
4-A-15 Twenty-third Supplemental Indenture of JCP&L, dated October 1, 1973 - Incorporated by reference to Exhibit 5-A-15, Registration No. 2-59785.
4-A-16 Twenty-fourth Supplemental Indenture of JCP&L, dated December 1, 1973 - Incorporated by reference to Exhibit 5-A- 16, Registration No. 2-59785.
4-A-17 Twenty-fifth Supplemental Indenture of JCP&L, dated November 1, 1974 - Incorporated by reference to Exhibit 5-A-17, Registration No. 2-59785.
4-A-18 Twenty-sixth Supplemental Indenture of JCP&L, dated March 1, 1975 - Incorporated by reference to Exhibit 5-A-18, Registration No. 2-59785.
4-A-19 Twenty-seventh Supplemental Indenture of JCP&L, dated July 1, 1975 - Incorporated by reference to Exhibit 5-A-19, Registration No. 2-59785.
4-A-20 Twenty-eighth Supplemental Indenture of JCP&L, dated October 1, 1975 - Incorporated by reference to Exhibit 5-A-20, Registration No. 2-59785.
4-A-21 Twenty-ninth Supplemental Indenture of JCP&L, dated February 1, 1976 - Incorporated by reference to Exhibit 5-A-21, Registration No. 2-59785.
4-A-22 Supplemental Indenture No. 29A of JCP&L, dated May 31, 1976 - Incorporated by reference to Exhibit 5-A-22, Registration No. 2-59785.
4-A-23 Thirtieth Supplemental Indenture of JCP&L, dated June 1, 1976 - Incorporated by reference to Exhibit 5-A-23, Registration No. 2-59785.
4-A-24 Thirty-first Supplemental Indenture of JCP&L, dated May 1, 1977 - Incorporated by reference to Exhibit 5-A-24, Registration No. 2-59785.
4-A-25 Thirty-second Supplemental Indenture of JCP&L, dated January 20, 1978 - Incorporated by reference to Exhibit 5-A-25, Registration No. 2-60438.
4-A-26 Thirty-third Supplemental Indenture of JCP&L, dated January 1, 1979 - Incorporated by reference to Exhibit A-20(b), Certificate Pursuant to Rule 24, SEC File No. 70-6242.
4-A-27 Thirty-fourth Supplemental Indenture of JCP&L, dated June 1, 1979 - Incorporated by reference to Exhibit A-28, Certificate Pursuant to Rule 24, SEC File No. 70-6290.
4-A-28 Thirty-sixth Supplemental Indenture of JCP&L, dated October 1, 1979 - Incorporated by reference to Exhibit A-30, Certificate Pursuant to Rule 24, SEC File No. 70-6354.
4-A-29 Thirty-seventh Supplemental Indenture of JCP&L, dated September 1, 1984 - Incorporated by reference to Exhibit A- 1(cc), Certificate Pursuant to Rule 24, SEC File No. 70- 7001.
4-A-30 Thirty-eighth Supplemental Indenture of JCP&L, dated July 1, 1985 - Incorporated by reference to Exhibit A-1(dd), Certificate Pursuant to Rule 24, SEC File No. 70-7109.
4-A-31 Thirty-ninth Supplemental Indenture of JCP&L, dated April 1, 1988 - Incorporated by reference to Exhibit A-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-7263.
4-A-32 Fortieth Supplemental Indenture of JCP&L, dated June 14, 1988 - Incorporated by reference to Exhibit A-1(ff), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-33 Forty-first Supplemental Indenture of JCP&L, dated April 1, 1989 - Incorporated by reference to Exhibit A-1(gg), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-34 Forty-second Supplemental Indenture of JCP&L, dated July 1, 1989 - Incorporated by reference to Exhibit A-1(hh), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-35 Forty-third Supplemental Indenture of JCP&L, dated March 1, 1991 - Incorporated by reference to Exhibit 4-A-35, Registration No. 33-45314.
4-A-36 Forty-fourth Supplemental Indenture of JCP&L, dated March 1, 1992 - Incorporated by reference to Exhibit 4-A-36, Registration No. 33-49405.
4-A-37 Forty-fifth Supplemental Indenture of JCP&L, dated October 1, 1992 - Incorporated by reference to Exhibit 4-A-37, Registration No. 33-49405.
4-A-38 Forty-sixth Supplemental Indenture of JCP&L, dated April 1, 1993 - Incorporated by reference to Exhibit C-15, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-39 Forty-seventh Supplemental Indenture of JCP&L, dated April 10, 1993 - Incorporated by reference to Exhibit C-16, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-40 Forty-eighth Supplemental Indenture of JCP&L, dated April 15, 1993 - Incorporated by reference to Exhibit C-17, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-41 Forty-ninth Supplemental Indenture of JCP&L, dated October 1, 1993 - Incorporated by reference to Exhibit C-18, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-42 Fiftieth Supplemental Indenture of JCP&L, dated August 1, 1994 - Incorporated by reference to Exhibit C-19, 1994 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-B Indenture of Met-Ed, dated November 1, 1944 with United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through June 1, 1957 - Incorporated by reference to Met-Ed's Instruments of Indebtedness Nos. 1 to 14, inclusive and 16, filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-B-1 Supplemental Indenture of Met-Ed, dated May 1, 1960 - Incorporated by reference to Exhibit 2-C, Registration No. 2-16192.
4-B-2 Supplemental Indenture of Met-Ed, dated December 1, 1962 - Incorporated by reference to Exhibit 2-E(1), Registration No. 2-59678.
4-B-3 Supplemental Indenture of Met-Ed, dated March 20, 1964 - Incorporated by reference to Exhibit 2-E(2), Registration No. 2-59678.
4-B-4 Supplemental Indenture of Met-Ed, dated July 1, 1965 - Incorporated by reference to Exhibit 2-E(3), Registration No. 2-59678.
4-B-5 Supplemental Indenture of Met-Ed, dated June 1, 1966 - Incorporated by reference to Exhibit 2-B-4, Registration No. 2-24883.
4-B-6 Supplemental Indenture of Met-Ed, dated March 22, 1968 - Incorporated by reference to Exhibit 4-C-5, Registration No. 2-29644.
4-B-7 Supplemental Indenture of Met-Ed, dated September 1, 1968 - Incorporated by reference to Exhibit 2-E(6), Registration No. 2-59678.
4-B-8 Supplemental Indenture of Met-Ed, dated August 1, 1969 - Incorporated by reference to Exhibit 2-E(7), Registration No. 2-59678.
4-B-9 Supplemental Indenture of Met-Ed, dated November 1, 1971 - Incorporated by reference to Exhibit 2-E(8), Registration No. 2-59678.
4-B-10 Supplemental Indenture of Met-Ed, dated May 1, 1972 - Incorporated by reference to Exhibit 2-E(9), Registration No. 2-59678.
4-B-11 Supplemental Indenture of Met-Ed, dated December 1, 1973 - Incorporated by reference to Exhibit 2-E(10), Registration No. 2-59678.
4-B-12 Supplemental Indenture of Met-Ed, dated October 30, 1974 - Incorporated by reference to Exhibit 2-E(11), Registration No. 2-59678.
4-B-13 Supplemental Indenture of Met-Ed, dated October 31, 1974 - Incorporated by reference to Exhibit 2-E(12), Registration No. 2-59678.
4-B-14 Supplemental Indenture of Met-Ed, dated March 20, 1975 - Incorporated by reference to Exhibit 2-E(13), Registration No. 2-59678.
4-B-15 Supplemental Indenture of Met-Ed, dated September 25, 1975 - Incorporated by reference to Exhibit 2-E(15), Registration No. 2-59678.
4-B-16 Supplemental Indenture of Met-Ed, dated January 12, 1976 - Incorporated by reference to Exhibit 2-E(16), Registration No. 2-59678.
4-B-17 Supplemental Indenture of Met-Ed, dated March 1, 1976 - Incorporated by reference to Exhibit 2-E(17), Registration No. 2-59678.
4-B-18 Supplemental Indenture of Met-Ed, dated September 28, 1977 - Incorporated by reference to Exhibit 2-E(18), Registration No. 2-62212.
4-B-19 Supplemental Indenture of Met-Ed, dated January 1, 1978 - Incorporated by reference to Exhibit 2-E(19), Registration No. 2-62212.
4-B-20 Supplemental Indenture of Met-Ed, dated September 1, 1978 - Incorporated by reference to Exhibit 4-A(19), Registration No. 33-48937.
4-B-21 Supplemental Indenture of Met-Ed, dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(20), Registration No. 33-48937.
4-B-22 Supplemental Indenture of Met-Ed, dated January 1, 1980 - Incorporated by reference to Exhibit 4-A(21), Registration No. 33-48937.
4-B-23 Supplemental Indenture of Met-Ed, dated September 1, 1981 - Incorporated by reference to Exhibit 4-A(22), Registration No. 33-48937.
4-B-24 Supplemental Indenture of Met-Ed, dated September 10, 1981 - Incorporated by reference to Exhibit 4-A(23), Registration No. 33-48937.
4-B-25 Supplemental Indenture of Met-Ed, dated December 1, 1982 - Incorporated by reference to Exhibit 4-A(24), Registration No. 33-48937.
4-B-26 Supplemental Indenture of Met-Ed, dated September 1, 1983 - Incorporated by reference to Exhibit 4-A(25), Registration No. 33-48937.
4-B-27 Supplemental Indenture of Met-Ed, dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(26), Registration No. 33-48937.
4-B-28 Supplemental Indenture of Met-Ed, dated March 1, 1985 - Incorporated by reference to Exhibit 4-A(27), Registration No. 33-48937.
4-B-29 Supplemental Indenture of Met-Ed, dated September 1, 1985 - Incorporated by reference to Exhibit 4-A(28), Registration No. 33-48937.
4-B-30 Supplemental Indenture of Met-Ed, dated June 1, 1988 - Incorporated by reference to Exhibit 4-A(29), Registration No. 33-48937.
4-B-31 Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(30), Registration No. 33-48937.
4-B-32 Amendment dated May 22, 1990 to Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(31), Registration No. 33-48937.
4-B-33 Supplemental Indenture of Met-Ed, dated September 1, 1992 - Incorporated by reference to Exhibit 4-A(32)(a), Registration No. 33-48937.
4-B-34 Supplemental Indenture of Met-Ed, dated December 1, 1993 - Incorporated by reference to Exhibit C-58, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-B-35 Supplemental Indenture of Met-Ed, dated July 15, 1995.
4-C Mortgage and Deed of Trust of Penelec dated January 1, 1942 between Penelec and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 - Incorporated by reference to Penelec's Instruments of Indebtedness Nos. 1- 20, inclusive, filed as a part of Amendment No. 1 to 1959
Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-C-1 Supplemental Indentures to Mortgage and Deed of Trust of Penelec dated May 1, 1961 through December 1, 1977 - Incorporated by reference to Exhibit 2-D(1) to 2-D(19), Registration No. 2-61502.
4-C-2 Supplemental Indenture of Penelec dated June 1, 1978 - Incorporated by reference to Exhibit 4-A(2), Registration No. 33-49669.
4-C-3 Supplemental Indenture of Penelec dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(3), Registration No. 33-49669.
4-C-4 Supplemental Indenture of Penelec dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(4), Registration No. 33-49669.
4-C-5 Supplemental Indenture of Penelec dated December 1, 1985 - Incorporated by reference to Exhibit 4-A(5), Registration No. 33-49669.
4-C-6 Supplemental Indenture of Penelec dated December 1, 1986 - Incorporated by reference to Exhibit 4-A(6), Registration No. 33-49669.
4-C-7 Supplemental Indenture of Penelec dated May 1, 1989 - Incorporated by reference to Exhibit 4-A(7), Registration No. 33-49669.
4-C-8 Supplemental Indenture of Penelec dated December 1, 1990- Incorporated by reference to Exhibit 4-A(8), Registration No. 33-45312
4-C-9 Supplemental Indenture of Penelec dated March 1, 1992 - Incorporated by reference to Exhibit 4-A(9), Registration No. 33-45312.
4-C-10 Supplemental Indenture of Penelec, dated June 1, 1993 - Incorporated by reference to Exhibit C-73, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-C-11 Supplemental Indenture of Penelec, dated November 1, 1995.
4-D Subordinated Debenture Indenture of JCP&L dated May 1, 1995 - Incorporated by reference to Exhibit A-8(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-E Subordinated Debenture Indenture of Met-Ed dated August 1, 1994 - Incorporated by reference to Exhibit A-8(a), Certificate Pursuant to Rule 24, SEC File No. 70-8401.
4-F Subordinated Debenture Indenture of Penelec dated July 1, 1994 - Incorporated by reference to Exhibit A-8(a), Certificate Pursuant to Rule 24, SEC File No. 70-8403.
4-G Amended and Restated Limited Partnership Agreement of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-5(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-H Action Creating Series A Preferred Securities of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-6(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-I Payment and Guarantee Agreement of JCP&L, dated May 18, 1995 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-J Amended and Restated Limited Partnership Agreement of Met-Ed Capital, L.P., dated August 16, 1994 - Incorporated by reference to Exhibit A-5(a), Certificate Pursuant to Rule 24, SEC File No. 70-8401.
4-K Action Creating Series A Preferred Securities of Met-Ed Capital, L.P., dated August 16, 1994 - Incorporated by reference to Exhibit A-6(a), Certificate Pursuant to Rule 24, SEC File No. 70-8401.
4-L Payment and Guarantee Agreement of Met-Ed, dated August 23, 1994 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-8401.
4-M Amended and Restated Limited Partnership Agreement of Penelec Capital, L.P., dated June 27, 1994 - Incorporated by reference to Exhibit A-5(a), Certificate Pursuant to Rule 24, SEC File No. 70-8403.
4-N Action Creating Series A Preferred Securities of Penelec Capital, L.P., dated June 27, 1994 - Incorporated by reference to Exhibit A-6(a), Certificate Pursuant to Rule 24, SEC File No. 70-8403.
4-O Payment and Guarantee Agreement of Penelec, dated July 5, 1994 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-8403.
10-A GPU System Companies Deferred Compensation Plan dated June 1, 1995.
10-B GPU System Companies Master Directors' Benefits Protection Trust dated September 1, 1995.
10-C GPU System Companies Master Executives' Benefits Protection Trust dated September 1, 1995.
10-D Employee Incentive Compensation Plan of JCP&L dated April 1, 1995.
10-E Employee Incentive Compensation Plan of Met-Ed dated April 1, 1995.
10-F Employee Incentive Compensation Plan of Penelec dated April 1, 1995.
10-G Incentive Compensation Plan for Elected Officers of JCP&L dated January 1, 1995.
10-H Incentive Compensation Plan for Elected Officers of Met-Ed dated January 1, 1995.
10-I Incentive Compensation Plan for Elected Officers of Penelec dated January 1, 1995.
10-J Deferred Remuneration Plan for Outside Directors of JCP&L dated September 1, 1995.
10-K JCP&L Supplemental and Excess Benefits Plan dated January 1, 1995.
10-L Met-Ed Supplemental and Excess Benefits Plan dated January 1, 1995.
10-M Penelec Supplemental and Excess Benefits Plan dated January 1, 1995.
10-N Letter agreement dated November 22, 1995 relating to supplemental pension benefits for J.R. Leva.
10-O Letter agreement dated September 18, 1995 relating to terms of employment and pension benefits for I.H. Jolles.
10-P Letter agreement dated November 22, 1995 relating to supplemental pension benefits for J.G. Graham.
10-Q GPU Restricted Stock Plan for Outside Directors - Incorporated by reference to Exhibit 10-A, 1994 Annual Report on Form 10-K, SEC File No. 1-6047.
10-R Retirement Plan for Outside Directors of GPU - Incorporated by reference to Exhibit 10-B, 1994 Annual Report on Form 10- K, SEC File No. 1-6047.
10-S Deferred Remuneration Plan for Outside Directors of GPU - Incorporated by reference to Exhibit 10-C, 1994 Annual Report on Form 10-K, SEC File No. 1-6047.
10-T Amended and Restated Nuclear Material Lease Agreement, dated November 17, 1995, between Oyster Creek Fuel Corp. and JCP&L - Incorporated by reference to Exhibit B-2(a)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-U Amended and Restated Nuclear Material Lease Agreement, dated November 17, 1995, between TMI-1 Fuel Corp. and JCP&L - Incorporated by reference to Exhibit B-2(a)(ii), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-V Letter Agreement, dated November 17, 1995, from JCP&L relating to Oyster Creek Nuclear Material Lease Agreement - Incorporated by reference to Exhibit B-2(b)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-W Letter Agreement, dated November 17, 1995, from JCP&L relating to JCP&L TMI-1 Nuclear Material Lease Agreement - Incorporated by reference to Exhibit B-2(b)(ii), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-X Amended and Restated Trust Agreement, dated November 17, 1995, between United States Trust Company of New York, as Owner Trustee, Lord Fuel Corp., as Trustor and Beneficiary, and JCP&L, Met-Ed and Penelec - Incorporated by reference to Exhibit B-3(i), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-Y Amended and Restated Nuclear Material Lease Agreement, dated November 17, 1995, between TMI-1 Fuel Corp. and Met-Ed - Incorporated by reference to Exhibit B-2(a)(iii), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-Z Letter Agreement, dated November 17, 1995, from Met-Ed relating to Met-Ed TMI-1 Nuclear Material Lease Agreement - Incorporated by reference to Exhibit B-2(b)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-AA Amended and Restated Nuclear Material Lease Agreement, dated November 17, 1995, between TMI-1 Fuel Corp. and Penelec - Incorporated by reference to Exhibit B-2(a)(iv), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
10-BB Letter Agreement, dated November 17, 1995, from Penelec relating to Penelec Nuclear Material Lease Agreement - Incorporated by reference to Exhibit B-2(b)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7862.
12 Statements Showing Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
A - JCP&L B - Met-Ed C - Penelec
21 Subsidiaries of the Registrant
A - JCP&L B - Met-Ed C - Penelec
23 Consent of Independent Accountants
A - GPU B - JCP&L C - Met-Ed D - Penelec
27 Financial Data Schedule
A - GPU B - JCP&L C - Met-Ed D - Penelec
(b) Reports on Form 8-K:
A - GPU B - JCP&L C - Met-Ed D - Penelec
For the month of October 1995, dated October 4, 1995, under Item 5 (Other Events).
For the month of October 1995, dated October 20, 1995, under Item 5 (Other Events), as amended by Form 8-K/A No. 1, dated October 27, 1995.
A - GPU
For the month of December 1995, dated December 13, 1995, under Item 5 (Other Events).
GENERAL PUBLIC UTILITIES CORPORATION
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 11, 1996 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 11, 1996 J. R. Leva, Chairman (Chief Executive Officer) President and Director
/s/ J. G. Graham March 11, 1996 J. G. Graham, Senior Vice President (Chief Financial Officer)
/s/ F. A. Donofrio March 11, 1996 F. A. Donofrio, Vice President and Comptroller (Chief Accounting Officer)
/s/ L. J. Appell, Jr. March 11, 1996 L. J. Appell, Jr., Director
/s/ T. H. Black March 11, 1996 T. H. Black, Director
/s/ H. F. Henderson, Jr. March 11, 1996 H. F. Henderson, Jr., Director
/s/ J. M. Pietruski March 11, 1996 J. M. Pietruski, Director
/s/ C. A. Rein March 11, 1996 C. A. Rein, Director
/s/ P. R. Roedel March 11, 1996 P. R. Roedel, Director
/s/ C. A. H. Trost March 11, 1996 C. A. H. Trost, Director
/s/ P. K. Woolf March 11, 1996 P. K. Woolf, Director
JERSEY CENTRAL POWER & LIGHT COMPANY
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. The Signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
JERSEY CENTRAL POWER & LIGHT COMPANY
Dated: March 11, 1996 BY: /s/ D. Baldassari D. Baldassari, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature and Title Date
/s/ J. R. Leva March 11, 1996 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ D. Baldassari March 11, 1996 D. Baldassari, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 11, 1996 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. W. Myers March 11, 1996 D. W. Myers, Vice President-Comptroller (Principal Accounting Officer) and Director
/s/ R. C. Arnold March 11, 1996 R. C. Arnold, Director
/s/ M. P. Morrell March 11, 1996 M. P. Morrell, Vice President and Director
/s/ G. E. Persson March 11, 1996 G. E. Persson, Director
/s/ S. C. Van Ness March 11, 1996 S. C. Van Ness, Director
/s/ S. B. Wiley March 11, 1996 S. B. Wiley, Director
METROPOLITAN EDISON COMPANY
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. The Signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
METROPOLITAN EDISON COMPANY
Dated: March 11, 1996 BY: /s/ F. D. Hafer F. D. Hafer, 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 11, 1996 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ F. D. Hafer March 11, 1996 F. D. Hafer, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 11, 1996 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. L. O'Brien March 11, 1996 D. L. O'Brien, Comptroller (Principal Accounting Officer)
/s/ J. F. Furst March 11, 1996 J. F. Furst, Vice President and Director
/s/ G. R. Repko March 11, 1996 G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 11, 1996 R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 11, 1996 R. C. Arnold, Director
PENNSYLVANIA ELECTRIC COMPANY
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. The Signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PENNSYLVANIA ELECTRIC COMPANY
Dated: March 11, 1996 BY: /s/ F. D. Hafer F. D. Hafer, 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 11, 1996 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ F. D. Hafer March 11, 1996 F. D. Hafer, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 11, 1996 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. L. O'Brien March 11, 1996 D. L. O'Brien, Comptroller (Principal Accounting Officer)
/s/ J. F. Furst March 11, 1996 J. F. Furst, Vice President and Director
/s/ G. R. Repko March 11, 1996 G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 11, 1996 R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 11, 1996 R. C. Arnold, Director
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
GENERAL PUBLIC UTILITIES CORPORATION
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, 1995, 1994 and 1993 Balance Sheets as of December 31, 1995 and 1994 Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1993-1995
JERSEY CENTRAL POWER & LIGHT COMPANY
Supplementary Data Page Company Statistics Selected Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Quarterly Financial Data
Financial Statements Report of Independent Accountants Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 Balance Sheets as of December 31, 1995 and 1994 Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 Statement of Capital Stock as of December 31, 1995 Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 Statement of Long-Term Debt as of December 31, 1995 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1993-1995
INDEX TO SUPPLEMENTARY DATA, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
METROPOLITAN EDISON COMPANY Supplementary Data Page Company Statistics Selected Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Quarterly Financial Data
Financial Statements Report of Independent Accountants Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 Balance Sheets as of December 31, 1995 and 1994 Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 Statement of Capital Stock and Preferred Securities as of December 31, 1995 Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 Statement of Long-Term Debt as of December 31, 1995 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1993-1995
PENNSYLVANIA ELECTRIC COMPANY Supplementary Data Page Company Statistics Selected Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Quarterly Financial Data
Financial Statements Report of Independent Accountants Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 Balance Sheets as of December 31, 1995 and 1994 Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 Statement of Capital Stock and Preferred Securities as of December 31, 1995 Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 Statement of Long-Term Debt as of December 31, 1995 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1993-1995
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 Net income in 1995 was $440.1 million, or $3.79 per share, compared to 1994 net income of $163.7 million, or $1.42 per share. The increase in net income was primarily due to the net effect of several 1995 and 1994 nonrecurring items. GPU's return on average common equity was 16.0% in 1995 compared to 6.3% in 1994.
Excluding these nonrecurring items, net income for 1995 would have been $343.6 million, or $2.95 per share, compared to 1994 net income of $328.4 million, or $2.85 per share. Return on average common equity for 1995 and 1994, on this basis, would have been 12.7% and 12.1%, respectively. Contributing to this increase were higher new customer sales, partially offset by higher depreciation and financing expenses.
The 1995 nonrecurring items consisted of a reversal of $104.9 million (after-tax), or $0.91 per share, of certain future Three Mile Island Unit 2 (TMI-2) retirement costs written off by Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec) in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 Pennsylvania Public Utility Commission (PaPUC) order allowing Met-Ed to recover such TMI-2 retirement costs from customers. Partially offsetting this increase was a charge to income of $8.4 million (after-tax), or $0.07 per share, for TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
The 1994 nonrecurring items included the above mentioned TMI-2 write-off of $104.9 million (after-tax), or $0.91 per share. Also in 1994, there was a charge to income of $76.1 million (after-tax), or $0.66 per share, for early retirement program costs; a write-off of $10.6 million (after-tax), or $0.09 per share, for certain postretirement benefit (OPEB) costs; and net interest income of $26.9 million (after-tax), or $0.23 per share, resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
Net income in 1994 was $163.7 million, or $1.42 per share, compared to net income in 1993 of $295.7 million, or $2.65 per share. The 1994 earnings reduction was attributable to the 1994 nonrecurring items mentioned above. Also, in 1993 there was a write-off of $15.4 million (after-tax), or $0.14 per share, for the cancellation of proposed power supply and transmission facilities agreements between the Subsidiaries and Duquesne Light Company. Excluding these nonrecurring items, net income for 1994 would have been $328.4 million, or $2.85 per share, compared to 1993 net income of $311.1 million, or $2.79 per share.
Earnings in 1994 were also positively affected by higher sales resulting from an increase in new customers and colder winter weather as compared to the
General Public Utilities Corporation and Subsidiary Companies
previous year, and higher revenues attributable to a February 1993 retail base rate increase at Jersey Central Power & Light Company (JCP&L). These increases were partially offset by increases in other operation and maintenance (O&M) expense.
OPERATING REVENUES: Operating revenues increased 4.3% to $3.8 billion in 1995 after increasing 1.5% to $3.65 billion in 1994. The components of these changes are as follows:
(In Millions) 1995 1994
Kilowatt-hour (KWH) revenues (excluding energy portion) $ 14.7 $ 30.6 Rate increases - 20.8 Energy revenues 141.6 (.9) Other revenues (1.2) 2.9 Increase in revenues $155.1 $ 53.4
Kilowatt-hour revenues
The increase in KWH revenues was due to an increase in new residential and commercial customer sales, partially offset by lower weather-related sales.
The increase in KWH revenues was due primarily to an increase in sales resulting from new customer additions in the residential and commercial sectors, and colder winter weather as compared to the previous year.
1995 MWH Customer Sales by Service Class
Residential 36% Commercial 32% Industrial/Other 32%
Energy revenues
1995 and 1994 Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues in 1995 increased primarily from additional sales to other utilities and higher energy cost rates.
General Public Utilities Corporation and Subsidiary Companies
Other revenues
1995 and 1994 Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes.
OPERATING EXPENSES: Power purchased and interchanged
1995 and 1994 Generally, changes in the energy component of power purchased and interchanged (PP&I) expense do not significantly affect earnings since these cost increases are substantially recovered through the Subsidiaries' energy adjustment clauses. However, earnings in 1994 benefitted from lower reserve capacity expense (which is a component of PP&I) resulting from the replacement of expiring utility purchase power contracts at lower rates.
Fuel and Deferral of energy costs, net
1995 and 1994 Generally, changes in fuel expense and deferral of energy costs do not affect earnings as they are offset by corresponding changes in energy revenues.
Other operation and maintenance
The decrease in other O&M expense was due to a $127 million (pre-tax) charge in 1994 related to the early retirement programs. Partially offsetting this decrease was a 1995 write-off of $14.7 million (pre-tax) for TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
The increase in other O&M expense was due primarily to a $127 million (pre-tax) charge for the early retirement programs. The increase was also due to higher emergency and winter storm repairs and the accrual of additional payroll expense under an expanded employee incentive compensation program designed to tie pay increases more closely to business results and enhance productivity.
Depreciation and amortization
The increase in depreciation and amortization expense was due primarily to additions to plant in service.
Taxes, other than income taxes
1995 and 1994 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
General Public Utilities Corporation and Subsidiary Companies
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
1995 and 1994 In the third quarter of 1995, Met-Ed and Penelec reversed $183.9 million (pre-tax) of certain future TMI-2 retirement costs written off in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 PaPUC order allowing Met-Ed to recover such costs from customers. The 1995 increase also included higher EI Group income of $14.3 million (pre-tax), which includes an $11.8 million (pre-tax) gain on the sale of securities.
In 1994, Penelec expensed $18.6 million (pre-tax) for certain OPEB costs believed not probable of recovery in rates. Of this amount, $14.6 million was written off as a result of a PaPUC order disallowing a nonaffiliated utility to collect such costs, and $4 million was charged to expense for OPEB costs related to employees who participated in the early retirement programs. Also, the Subsidiaries recorded interest income of $59.4 million (pre-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
INTEREST CHARGES AND PREFERRED DIVIDENDS: Other interest
1995 and 1994 In 1994, the Subsidiaries recognized interest expense related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $13.8 million (pre-tax) charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Dividends on subsidiary-obligated mandatorily redeemable preferred securities
1995 and 1994 Through special-purpose partnerships, Met-Ed and Penelec issued in 1994 $100 million and $105 million, respectively, and in May 1995, JCP&L issued $125 million, of mandatorily redeemable preferred securities.
LIQUIDITY AND CAPITAL RESOURCES Capital Needs:
The Subsidiaries' capital needs were $553 million in 1995, consisting of cash construction expenditures of $462 million and amounts for maturing obligations of $91 million. In addition, the EI Group made investments in 1995 totaling $165 million, consisting primarily of investments in generating facilities in South America and an electric distribution business in Australia (see EI GROUP).
General Public Utilities Corporation and Subsidiary Companies
During 1995, construction expenditures were used primarily to maintain and improve existing generation, transmission and distribution facilities, build a new generation facility, and for various clean air compliance projects. In 1996, construction expenditures for the Subsidiaries are estimated to be $491 million, consisting primarily of $418 million for ongoing system development, $26 million for upgrading JCP&L's communication system, and $15 million for the continued construction of new generation facilities. Expenditures for maturing obligations will total $131 million in 1996, and $158 million in 1997. In the late 1990s, construction expenditures are expected to include substantial amounts for additional clean air requirements and other System needs. Management estimates that approximately three-fourths of the GPU System's 1996 capital needs will be satisfied through internally generated funds.
Cash Construction Expenditures (In millions of dollars) 1991 1992 1993 1994 1995 1996 $467 $460 $496 $586 $462 $491*
* Estimate
The Subsidiaries' capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1995 totaled $152 million. In 1995, the Subsidiaries refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. These nuclear fuel leases have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of between $40 million and $45 million annually. In the event the needed nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
Financing:
In 1995, GPU sold five million shares of common stock. The net proceeds of $157.5 million were used to make cash capital contributions to the Subsidiaries and to repay GPU short-term debt, a portion of which had been incurred to acquire interests in a generating company in Bolivia and a distribution business in Australia.
The Subsidiaries have regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock through various periods into 1997. Under existing authorizations, JCP&L, Met-Ed and Penelec may issue these senior securities in aggregate amounts of $225 million, $190 million and $160 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
In 1995, the Subsidiaries issued an aggregate of $338 million principal amount of FMBs. The proceeds from these issuances were used to refinance $128 million principal amount of higher cost FMBs, to redeem at maturity $59 million principal amount of FMBs, to moderate short-term debt levels and to fund growth in capitalization. In addition, the EI Group has borrowed $68 million under a credit agreement, the proceeds of which were used primarily to finance the acquisition of an electric distribution business in Australia (see EI GROUP). JCP&L Capital L.P., a special-purpose partnership in which a subsidiary of JCP&L is the sole general partner, issued $125 million stated value of mandatorily redeemable preferred securities (carried on the balance sheet as Subsidiary-obligated mandatorily redeemable preferred securities). The proceeds from the issuance were used to reduce JCP&L short-term debt and retire senior securities. Also in 1995, JCP&L repurchased, in the market, $6 million stated value of cumulative preferred stock. The repurchased shares may be used to satisfy future sinking fund requirements.
The Subsidiaries' bond indentures and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Subsidiaries may issue. The Subsidiaries' interest and preferred dividend coverage ratios are currently in excess of indenture and charter restrictions.
The GPU System's cost of capital and ability to obtain external financing are affected by the Subsidiaries' security ratings, which are periodically reviewed by the three major credit rating agencies. The GPU System's senior securities ratings have remained constant since August 1994. The Subsidiaries' FMBs are currently rated at an equivalent of BBB+ or higher by the three major credit rating agencies, while the preferred stock and mandatorily redeemable preferred securities issues have been assigned an equivalent of BBB or higher. In addition, the Subsidiaries' commercial paper is rated as having good to high credit quality.
In October 1995, the Standard & Poor's (S&P) rating outlook (which is used to assess the potential direction of an issuer's long-term debt rating over the intermediate to longer-term) for Met-Ed was revised to "positive" from "stable." According to S&P, this outlook reflects expectations of modest financial improvement based on gradual economic growth, the successful buyout of some expensive nonutility generation (NUG) contracts, and continued strong nuclear operations. It also reflects the Pennsylvania Supreme Court's reversal of a lower court order that had disallowed recovery of certain future TMI-2 retirement costs. The S&P rating outlook for JCP&L and Penelec remained as "stable," and reflects manageable construction programs, minimal rate relief requirements and expectations of modest strengthening in the service area economies. The S&P business positions assigned to the Subsidiaries remained unchanged throughout the year at "low average" to "average." The business position is a financial benchmarking standard for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry.
Present plans call for the Subsidiaries to issue long-term debt during the next three years to finance construction activities, fund the redemption of maturing senior securities, and depending on interest rates, refinance outstanding senior securities. In addition, significant further investments
General Public Utilities Corporation and Subsidiary Companies
by the EI Group, or otherwise, may require GPU to issue additional debt and/or new shares of common stock.
Capitalization:
The GPU System's target capitalization ratios are designed to provide credit quality ratings that permit capital market access at reasonable costs. The targets and actual capitalization ratios are as follows:
Target Range 1995 1994 1993 Common equity 46-49% 47% 44% 47% Preferred equity 8-10 9 8 5 Notes payable and long-term debt 46-41 44 48 48 100% 100% 100% 100%
In 1995, the quarterly dividend on GPU common stock was increased by 4.4% to an annualized rate of $1.88 per share. GPU's payout rate in 1995 was 63% of earnings (excluding the nonrecurring items). Management will continue to review its dividend policy to determine how to best serve the long-term interests of shareholders.
EI GROUP The EI Group (Energy Initiatives, EI Power, and EI Energy) is engaged in the development, ownership and operation of generation, transmission and distribution facilities in the United States and foreign countries. GPU has obtained SEC approval to finance investments in foreign utility companies and exempt wholesale generators (both domestically and internationally) up to an aggregate amount equal to 50% of GPU's average consolidated retained earnings. At December 31, 1995, GPU has investments, through the EI Group, in exempt wholesale generators and foreign utility companies totaling approximately $300 million. The $300 million includes investments made by the EI Group totaling $160 million, of which $81 million was contributed by GPU; and GPU guarantee obligations aggregating $140 million. In addition, GPU has investments, through the EI Group, in qualifying cogeneration facilities and project development activities aggregating $124 million. Selected financial data for the EI Group is as follows:
(In Millions) 1995* 1994 1993 Total assets $380 $130 $ 44
Capitalization: Common equity $209 $118 $ 39 Notes payable 2 - - Long-term debt 104 - - Total $315 $118 $ 39
Purchase of investments $165 $ 74 $ 16
Net income/(loss) $ 9 $ (3) $ (2)
* Total assets includes approximately $62 million held by a minority owner.
General Public Utilities Corporation and Subsidiary Companies
In 1995, EI Power acquired from the Bolivian government, for approximately $47 million, a 50% ownership interest in Empresa Guaracachi S.A., a Bolivian electric generating company having an aggregate capacity of 216 MW of gas-fired and oil-fired generation.
In 1995, EI Energy, together with the Australian Gas Light Company, acquired Solaris Power (Solaris), an electric distribution company based in Melbourne, Australia, for a total purchase price of approximately $712 million, of which EI Energy's 50% share was $356 million. EI Energy has made an equity investment in Solaris of approximately $112 million; the balance of the purchase price was provided through borrowings by Solaris from an Australian bank syndicate. Solaris, which provides electric service to more than 230,000 customers in and around Melbourne, was sold by the Government of Victoria through a competitive bid as part of that state's privatization of the electric industry.
In 1995, EI Power, along with its development partners, completed the financing for the acquisition of a 240 MW gas-fired generating plant in Barranquilla, Colombia and the construction of a new 750 MW gas-fired plant adjacent to the existing plant. Electricity generated by these plants will be sold to Corporacion Electrica de la Costa Atlantica under a 20-year contract. Total project costs, including the acquisition of the existing plant, are approximately $750 million, of which EI Power's equity contribution is expected to be approximately $65 million. EI Power has agreed to make additional equity contributions to the project of up to $58 million under certain circumstances.
At December 31, 1995, the EI Group had ownership interests in eleven operating combined-cycle cogeneration plants located in the United States (totaling 932 MW of capacity) and five operating generating facilities located in Canada and South America (totaling 480 MW of capacity). The EI Group also has a number of additional projects at various stages of development, including a 300 MW gas-fired project and a 180 MW gas-fired project for which long-term power purchase agreements have been executed with Georgia Power Company and Wisconsin Public Service Company, respectively.
Management expects that the EI Group will be a source of future earnings growth and intends to make additional investments in these types of business activities. The timing and amounts of these investments, however, will depend upon appropriate opportunities.
The following remaining sections of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS are being presented for GPU and for each of the Subsidiaries on a combined basis.
General Public Utilities Corporation and Subsidiary Companies
COMPETITIVE ENVIRONMENT Recent Regulatory Actions:
The electric power markets have traditionally been served by integrated regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the development of increased competition in the electric utility industry.
In 1995, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on open access nondiscriminatory transmission services by utilities and a supplemental NOPR on recovery of stranded costs. The new rules, if adopted, would in essence provide open access to the interstate electric transmission network and thereby encourage a fully competitive wholesale electric power market.
Among other things, the FERC's proposal would (1) require electric utilities to file nondiscriminatory open access transmission tariffs which would be available to all wholesale sellers and buyers of electricity; (2) require utilities to accept service under these new tariffs for their own wholesale transactions; and (3) permit utilities to recover their legitimate and verifiable "stranded costs" incurred when a franchise customer elects to purchase power from another supplier using the utility's transmission system.
In addition, while the proposed rule does not provide for "corporate unbundling", which the FERC defines as the disposing of ancillary services or creating separate affiliates to manage transmission services, it does call for "functional unbundling" of transmission and ancillary services.
With respect to stranded costs, the FERC proposed to provide recovery mechanisms where stranded costs result from municipalization or other instances where former retail customers become wholesale customers, as well as for wholesale stranded costs. The state regulatory agencies would be expected to provide for recovery of stranded costs attributable to retail wheeling or direct access programs, and the FERC would intervene only when such agencies lacked necessary authority.
In September 1995, the FERC accepted for filing, subject to possible rate refunds, the Subsidiaries' proposed open access transmission tariffs. The FERC has ordered that hearings be held on a number of aspects of these tariffs, including whether they are consistent in certain respects with FERC policy on open access and comparability of service. The tariffs provide for both firm and interruptible service on a point-to-point basis. Network service, where requested, will be negotiated on a case by case basis.
In November 1995, the Subsidiaries, along with six other electric utility members of the Pennsylvania-New Jersey-Maryland Interconnection (PJM Power Pool), filed with the FERC a detailed plan to increase competition in the Mid- Atlantic region. This comprehensive plan offers to all generators and wholesale buyers of electricity, a regional energy market and open access to high-voltage transmission lines which will result in greater availability of economic energy for wholesale electricity buyers and sellers. The Subsidiaries believe the plan will satisfy the goals of the FERC's NOPR on
General Public Utilities Corporation and Subsidiary Companies
open access nondiscriminatory transmission services, and if approved by the FERC, open access transmission tariffs filed with the FERC under this plan would supersede the Subsidiaries' open access transmission tariffs.
The sponsoring PJM companies intend to make a comprehensive filing with the FERC consistent with this detailed plan by May 1996, and expect to implement the new structure by year-end 1996. The Subsidiaries have been advised that the Justice Department is reviewing possible antitrust implications of merger activity among PJM members.
In April 1995, legislation was introduced in the U.S. Senate that would repeal Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA). Under that section of PURPA, certain qualifying NUGs can "lock-in" long-term rates that may result in electric utilities being required to purchase power at costs higher than available alternative sources of energy. Similar legislation has been introduced in the House of Representatives.
In October 1995, legislation was introduced in the U.S. Senate that largely reflects a 1995 Securities and Exchange Commission (SEC) Staff report recommending a series of legislative and administrative reforms to the Public Utility Holding Company Act of 1935 (Holding Company Act). The SEC Staff recommended that the SEC support repeal of the Holding Company Act with a minimum one year transition period, and a transfer of audit, reporting and certain other responsibilities to the FERC while giving state agencies access to holding company books and records. In the interim, the SEC Staff recommended that the SEC adopt a series of administrative reforms that would streamline such things as the issuance of securities for routine financings and permit a wide range of energy-related diversification activities. The SEC Staff also recommended that the SEC more flexibly interpret the Holding Company Act's integrated system requirements by allowing utility acquisitions and specifically, combination electric and gas systems, where the affected state commissions concur.
In response to the SEC Staff report, the SEC has adopted certain changes which will streamline routine financings, and has proposed a number of others. GPU and other registered holding companies believe that repeal of the Holding Company Act is necessary to remove a significant impediment to a registered holding company's ability to be competitive.
In May 1995, the New Jersey Board of Public Utilities (NJBPU) issued Phase I of the New Jersey Energy Master Plan (NJEMP) promoting regulatory policy changes intended to move New Jersey's electric and gas utilities into a competitive marketplace. In the Phase I Report, the NJBPU recommended, among other things, (1) rate-flexibility legislation to allow utilities to compete in order to retain and attract customers in a changing regulatory environment; (2) alternative regulation as an interim and possibly a long-term measure to allow market forces to stimulate efficiency, productivity and innovation; (3) consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities and to ensure that all ratepayers benefit from the transition to greater competition; and (4) an integrated resource planning and competitive supply-side procurement process to streamline the regulatory review process, lower costs for all ratepayers, and ensure that New Jersey's environmental and energy conservation goals are met in a competitive
General Public Utilities Corporation and Subsidiary Companies
marketplace. The Phase I Report also emphasized that regulation must continue to guarantee access to safe, adequate and reliable service at a reasonable cost; protect the public interest; meet environmental and energy efficiency goals; assure system reliability; and protect the financial integrity of utilities which have an obligation to serve the public.
In August 1995, the NJBPU initiated Phase II of the NJEMP. Four working groups have been established to develop draft proposals and models by March 1996. The subjects for each of the groups are as follows: (1) competition issues; (2) stranded assets; (3) regional issues such as the environment and emissions standards; and (4) public policy issues, including social programs and conservation. The NJEMP is being developed in three phases, with Phase III expected to be completed by the end of 1996.
In July 1995, New Jersey adopted energy rate-flexibility legislation that will enable electric utilities to offer rate discounts to certain customers and allow these customers access to competitive markets. If certain conditions are met, utilities may be permitted to recover from customers 50% of revenue lost as a result of rate discounts. The legislation also provides utilities with the opportunity to propose to the NJBPU alternative ways to set rates. JCP&L has submitted its initial compliance filing which sets forth JCP&L's minimum price for off-tariff rate agreements applicable to commercial and industrial customers.
In 1994, the PaPUC initiated an investigation into the role of competition in Pennsylvania's electric utility industry and solicited comments on various issues. Met-Ed and Penelec jointly filed responses suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investments, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on Pennsylvania utilities as compared with unregulated or out- of-state suppliers. In August 1995, the PaPUC released a Staff report in which the Staff decided not to recommend retail wheeling at this time. Evidentiary hearings on this matter began in December 1995 and the PaPUC is expected to present recommendations in the spring of 1996.
In response to these state proceedings, the Subsidiaries have proposed the formation of a wholesale market regional power pool managed by an independent system operator. The power pool would function as a spot market, with generators of electricity allowed to sell into the pool and purchasers of electricity allowed to buy from the pool. It would also accommodate contracts between specific buyers and sellers of power. The power pool operator would be responsible for supporting regional transmission planning and directing the operation of generation and transmission facilities to assure the reliability and integrity of the regional electric grid.
The Subsidiaries have also proposed the use of a competitive transition charge (CTC) as an equitable approach to recover stranded costs. The CTC would be applied to all customers who depend on the electric system for delivery of their electric supply. Efforts by utilities to mitigate their
General Public Utilities Corporation and Subsidiary Companies
stranded commitments could be required as part of the CTC. The Subsidiaries also support in their proposals retail customer choice for such things as energy supplier, products and services.
With the expectation that a segment of the industry will continue to be regulated by the states, the proposals advocate the use of performance-based rates to encourage utilities to reduce costs while maintaining service reliability.
And in keeping with the public policy objectives associated with the electric utility industry, including such things as access to basic service for low income consumers, the proposals endorse the creation of a "public purpose charge" that would be collected from all consumers.
Managing the Transition:
GPU has identified five strategic objectives to guide the GPU System over the next several years: (1) strengthen and increase the distribution business; (2) maximize existing generation asset values consistent with competitive market economics; (3) internally and externally position GPU for industry deregulation and restructuring; (4) seek earnings growth outside the traditional regulated businesses, including making investments in the EI Group; and (5) develop a culture that will prepare the GPU System for competition.
On January 26, 1996, GPU received regulatory approval from the SEC to form a new subsidiary, GPU Generation Corporation (Genco), to operate, maintain and repair the nonnuclear generation facilities owned by the Subsidiaries as well as construct any new nonnuclear generation facilities which the Subsidiaries may need in the future. In 1994, the Subsidiaries received regulatory approval from the PaPUC and NJBPU to enter into an operating agreement with Genco.
The Subsidiaries entered into a three-year fuel management agreement with New Jersey Natural Energy Corporation, an affiliate of New Jersey Natural Gas Company, to manage the Subsidiaries' natural gas purchases and interstate pipeline capacity. The Subsidiaries' gas-fired facilities, as well as up to approximately 1,100 MW (JCP&L 885 MW; Met-Ed 200 MW; Penelec 15 MW) of NUG capacity, will be pooled and managed under this agreement, allowing the Subsidiaries to reduce their power purchase expenses. The Subsidiaries have conditional or final agreements with four NUGs (JCP&L three NUGs; Met-Ed one NUG), having an aggregate capacity of approximately 430 MW (JCP&L 385 MW; Met- Ed 45 MW), to supply natural gas from the pool. Also, because the gas pool will help to reduce fuel costs, some of the Subsidiaries' gas-fired generating stations may at times be more economical in the PJM Power Pool's dispatching order. As a result, the Subsidiaries may be able to reduce their dependence upon more expensive purchased power and increase their energy sales to the PJM Power Pool and other utilities.
In response to competitive forces and regulatory changes, the GPU System has from time to time considered, and expects to continue to consider, various strategies designed to enhance its competitive position and to increase its ability to adapt to, and anticipate changes in, its business.
General Public Utilities Corporation and Subsidiary Companies
These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of its wholesale and retail businesses, acquisitions of other businesses, and additions to or dispositions of all or portions of its generation, transmission or distribution businesses. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to the ultimate effect thereof on the financial condition or competitive position of the GPU System.
Nonutility Generation Agreements:
As competition in the electric utility industry increases as a result of regulatory actions, and customers are given a choice for their electric supplier, the price of the GPU System's electricity will be critical. GPU is attempting to assess the impact that these and other changes will have on its financial condition and results of operations. For additional information regarding the other changes that may have an adverse effect on the Subsidiaries, see the COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT section of Note 1 to GPU's Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from generation facilities now in service is currently and is expected to continue to be priced below the costs of new supply sources, at least for some time. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Subsidiaries' NUG agreements are substantially in excess of current and projected prices from alternative sources.
Pursuant to the requirements of PURPA and state regulatory directives, the Subsidiaries have entered into power purchase agreements with NUGs for the purchase of energy and capacity. While the Subsidiaries thus far have been granted recovery of their NUG costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to be able to recover these costs throughout the terms of the related agreements. The GPU System currently estimates that for 1998, when substantially all of these NUG projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined- cycle facility) will range from $240 million to $350 million (JCP&L $100 million to $150 million; Met-Ed $50 million to $80 million; Penelec $90 million to $120 million). The amount of these estimated above-market payments may increase or decrease substantially based upon, among other things, payment escalations in the contract terms, changes in fuel prices and changes in the capital and operating cost of new generating equipment.
The Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new NUG agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. The Subsidiaries are also attempting to renegotiate, and in some cases buyout, existing high cost long-term NUG agreements (see Managing Nonutility Generation).
General Public Utilities Corporation and Subsidiary Companies
THE GPU SUPPLY PLAN The GPU supply plan is prepared on a GPU System basis. Under existing retail regulation, supply planning in the electric utility industry is directly related to projected growth in the franchise service territory. At this time, management cannot estimate the timing and extent to which retail electric competition will affect the GPU supply plan. As GPU prepares to operate in a competitive environment, its supply plan currently focuses on maintaining the Subsidiaries' existing customer base by offering competitively priced electricity.
Over the next five years, assuming the continuation of existing retail electric regulation, each of the Subsidiaries is projected to experience an average growth in sales to customers of about 2% annually, principally due to continued economic growth in the service territories and a slight increase in customers. To meet this growth, actual and projected capacity and sources of energy are as follows:
Capacity 1995 2000 MW % MW % Coal 3,024 29 3,024 27 Nuclear 1,405 13 1,405 13 Gas, Hydro & Oil 2,163 21 2,079 19 Contracted Purchases 3,832 37 3,287 30 Uncommitted Sources - - 1,239 11 Total 10,424 100 11,034 100
Sources of Energy 1995 2000 GWH % GWH % Coal 17,500 34 18,631 35 Nuclear 11,582 23 9,930 19 Gas, Hydro & Oil 1,018 2 1,405 3 Contracted Purchases 16,598 32 17,183 33 Spot Market & Interchange Purchases 4,411 9 5,127 10 Total 51,109 100 52,276 100
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" market purchases, and avoidance of long-term firm commitments. GPU's present strategy includes minimizing the financial exposure associated with new long-term purchase commitments and the construction of new facilities by evaluating these options in terms of an unregulated power market. As part of this strategy, GPU is also evaluating the future financial viability of its generating assets, including possible plant retirements, on an ongoing basis. The GPU System will take necessary actions to avoid adding new capacity which would result in
General Public Utilities Corporation and Subsidiary Companies
costs that may exceed future market prices. In addition, GPU will continue to seek regulatory support to renegotiate or buy out contracts with NUGs where the pricing is in excess of projected market prices.
New Energy Supplies:
The GPU System's supply plan includes contracted capacity from NUGs, the replacement of expiring utility purchase contracts at lower costs, the construction of new peaking units, the repowering of existing generation facilities, and the continued promotion of economic energy-conservation and load-management programs. The supply plan also includes the addition of approximately 1,239 MW (primarily related to JCP&L) of currently uncommitted capacity. Additional capacity needs are principally related to the expiration of existing commitments rather than new customer load.
The Subsidiaries have contracts and anticipated commitments with NUGs under which a total of 1,624 MW (JCP&L 892 MW; Met-Ed 335 MW; Penelec 397 MW) of capacity are currently in service and about an additional 438 MW (JCP&L 110 MW; Met-Ed 150 MW; Penelec 178 MW) are currently scheduled to be in service by 2000.
In January 1996, JCP&L issued an all-supply source solicitation for the short-term supply of energy and capacity to meet its minimum forecasted needs through 2002. The solicitation will seek contracts to purchase about 600 MW of capacity beginning in 1999, increasing to approximately 800 MW by 2002. JCP&L plans to meet any energy and capacity needs, over and above its short- term supply minimum forecast, by purchasing energy options which could be exercised as needed. JCP&L will continue to evaluate additional economic purchase opportunities as both demand and supply market conditions evolve and conduct further solicitations to fulfill, if warranted, a significant part of the uncommitted sources identified in GPU's supply plan.
JCP&L is constructing a 141 MW gas-fired combustion turbine at its Gilbert generating station. This estimated $50 million project, of which $34 million has been spent, is expected to be in-service by mid-1996. An industry trade group representing the NUGs has appealed the issuance of an air permit by the New Jersey Department of Environmental Protection, and the NJBPU's order to the Appellate Division of New Jersey Superior Court. There can be no assurance as to the outcome of this proceeding.
Penelec has determined that it will not continue funding a proposed $146 million research and development project with the U.S. Department of Energy to repower its 82 MW Warren generating station. In 1995, Penelec wrote off approximately $2 million of costs related to this project.
Managing Nonutility Generation:
The Subsidiaries are seeking to reduce the above market costs of NUG agreements, by (1) attempting to convert must-run agreements to dispatchable agreements; (2) attempting to renegotiate prices of the agreements; (3) offering contract buyouts while seeking to recover the costs through their
General Public Utilities Corporation and Subsidiary Companies
energy adjustment clauses; and (4) initiating proceedings before federal and state agencies, and in the courts, where appropriate. In addition, the Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new NUG agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. These efforts may result in claims against the GPU System for substantial damages. There can, however, be no assurance as to what extent the Subsidiaries' efforts will be successful in whole or in part.
During 1995, JCP&L and Met-Ed bought out a total of five NUG (JCP&L two NUGs; Met-Ed three NUGs) power purchase contracts aggregating 540 MW (JCP&L 200 MW; Met-Ed 340 MW) of capacity, which is expected to save ratepayers more than $2 billion (JCP&L $0.7 billion; Met-Ed $1.3 billion) based on the projected cost of alternative sources of energy over the terms of these agreements. JCP&L and Met-Ed have agreed to pay the project developers up to a total of $84 million (JCP&L $17 million; Met-Ed $67 million) to cancel the contracts. The Subsidiaries have deferred the costs of these buyouts and are seeking to recover these costs through their energy adjustment clauses.
In 1995, Met-Ed and Penelec filed a petition for enforcement and declaratory order with the FERC requesting that the FERC effectively invalidate four contracts (Met-Ed two contracts; Penelec two contracts) with NUGs, aggregating 487 MW (Met-Ed 327 MW; Penelec 160 MW) of capacity, on the grounds that the PaPUC's implementation of PURPA directing Met-Ed and Penelec to enter into these agreements was unlawful. The FERC has denied the petition, and Met-Ed and Penelec have not determined whether they will seek judicial review of the FERC's action. Subsequent to the FERC's decision, Met-Ed bought out the contracts for two of these projects, totaling 327 MW.
In 1994, Penelec requested the Pennsylvania Supreme Court to review a Commonwealth Court decision upholding a PaPUC order requiring Penelec to purchase a total of 160 MW from two NUGs. The PaPUC had ordered Penelec in 1993 to enter into power purchase agreements with the developers for 80 MW of power each under long-term contracts commencing in 1997 or later. The Commonwealth Court denied Penelec's appeal of the PaPUC order, but remanded the case back to the PaPUC to recalculate the avoided costs to be paid for the power. In May 1995, the PaPUC assigned the matter to an Administrative Law Judge (ALJ) for a recommended decision, and hearings have been scheduled by the ALJ. In August 1995, the Pennsylvania Supreme Court granted Penelec's petition for review of the Commonwealth Court's decision. Briefs have been filed and oral argument was held in January 1996.
In March 1995, the U.S. Court of Appeals denied petitions for rehearing filed by JCP&L, the NJBPU, and the New Jersey Division of Ratepayer Advocate, seeking reconsideration of the Court's earlier decision prohibiting the NJBPU from reexamining its order approving the rates payable to Freehold Cogeneration Associates (Freehold) under a long-term power purchase agreement entered into pursuant to PURPA. The U.S. Supreme Court has denied petitions for review filed by JCP&L and the Ratepayer Advocate. JCP&L also petitioned the FERC to invalidate the agreement as unlawful under PURPA. The FERC has denied JCP&L's petition and JCP&L intends to seek judicial review of the FERC's decision. JCP&L is also seeking to invalidate the Freehold power
General Public Utilities Corporation and Subsidiary Companies
purchase agreement in a separate action pending in a New Jersey Superior Court. Freehold has moved to dismiss JCP&L's claim, and the matter is pending.
In 1994, MidAtlantic Cogen Inc. requested the PaPUC to order Met-Ed to enter into a long-term agreement to buy capacity and energy from its Fairless Cogeneration Project. In 1994, the Pennsylvania Commonwealth Court granted the PaPUC's application to revise its order for the purpose of reevaluating MidAtlantic's right to sell power to Met-Ed. The PaPUC subsequently ordered that hearings be held and assigned the matter to an ALJ. Met-Ed has moved to dismiss MidAtlantic's petition. MidAtlantic has filed a cross-motion for summary judgment. The motions are pending before the PaPUC.
ENVIRONMENTAL ISSUES The federal Clean Air Act Amendments of 1990 (Clean Air Act) require substantial reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year 2000. The Subsidiaries' plan includes installing and operating emission control equipment at some of their coal-fired facilities as well as switching to lower sulfur coal at other coal-fired facilities.
To comply with the Clean Air Act, the Subsidiaries expect to spend up to $410 million (JCP&L $42 million; Met-Ed $158 million; Penelec $210 million) for air pollution control equipment by the year 2000. During 1994 and 1995, scrubbers were installed at the jointly owned Conemaugh station which are expected to reduce sulfur dioxide emissions by 95%. Met-Ed's share of the total project costs was approximately $57 million. Through December 31, 1995, the Subsidiaries have made capital expenditures of approximately $234 million (JCP&L $41 million; Met-Ed $95 million; Penelec $98 million) (including the Conemaugh scrubbers) to comply with the Clean Air Act requirements.
In 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia, proposed reductions in NOx emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Subsidiaries expect that the U.S. Environmental Protection Agency will approve the state implementation plans consistent with the proposal, and that as a result, they will spend an estimated $60 million (Met-Ed $14 million; Penelec $46 million) (included in the Clean Air Act total mentioned above), beginning in 1997, to meet the seasonal reductions agreed upon by the OTC. The OTC has stated that it anticipates that additional NOx reductions will be necessary to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met at that time have not been finalized. The Subsidiaries are unable to determine what additional costs, if any, will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the GPU System will continue to evaluate major capital investments compared to participation in the emission allowance market, and the use of low-sulfur fuel or the retirement of facilities. These and other compliance alternatives may result in the substitution of increased operating expenses for capital costs.
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At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected plants are expected to be recoverable through the current ratemaking process, but management recognizes that recovery is not assured.
For more information, see the ENVIRONMENTAL MATTERS section of Note 1 to GPU's 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. Approximately 2,100 of such claims are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. For more information, see the TMI-2 section of Note 1 to GPU's Consolidated Financial Statements.
EFFECTS OF INFLATION Under traditional ratemaking, 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. As competition and deregulation accelerate, there can be no assurance as to the recovery of increased operating expense or utility plant investments. The GPU System is committed to long-term cost control and continues to seek and implement measures to reduce or limit the growth of operating expenses and capital expenditures, including the associated effects of inflation.
Although currently operating in a regulated environment, the GPU System is focusing less on the ratemaking process, and is actively trying to find new ways to increase revenues, improve performance and reduce costs to facilitate the competitive pricing of its products and services.
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 schedule 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 schedule are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. These 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, 1995 and 1994 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
New York, New York January 31, 1996
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 Subsidiaries serve areas of New Jersey and Pennsylvania with a population of approximately five million, with revenues about equally divided between New Jersey and Pennsylvania customers. The Corporation also owns all the common stock of GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and Energy Initiatives, Inc., EI Power, Inc. and EI Energy, Inc., (collectively, the "EI Group") which develop, own and operate generation, transmission and distribution facilities in the United States and in foreign countries. All of these companies considered together with their subsidiaries are referred to as the "GPU System."
Note 1, "Commitments and Contingencies," and Note 2, "Summary of Significant Accounting Policies," are being presented on a combined basis; the separate disclosures relating to the Corporation and each of the Subsidiaries have been combined and are presented below. The remaining Notes continue to be presented separately for the Corporation and for each of the Subsidiaries.
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Subsidiaries have made investments in three major nuclear projects-- Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by JCP&L. At December 31, the Subsidiaries' net investment in TMI-1 and Oyster Creek, including nuclear fuel, was as follows:
Net Investment (Millions) TMI-1 Oyster Creek
JCP&L $166 $785 Met-Ed 318 - Penelec 156 - Total $640 $785
General Public Utilities Corporation and Subsidiary Companies
Net Investment (Millions) TMI-1 Oyster Creek
JCP&L $162 $817 Met-Ed 311 - Penelec 154 - Total $627 $817
The Subsidiaries' net investment in TMI-2 at December 31, 1995 was $95 million (JCP&L, Met-Ed and Penelec's shares are $85 million, $2 million, and $8 million, respectively). The Subsidiaries' net investment in TMI-2 at December 31, 1994 was $103 million (JCP&L, Met-Ed and Penelec's shares are $89 million, $6 million, and $8 million, respectively). JCP&L is collecting revenues for TMI-2 on a basis which provides for the recovery of its remaining investment in the plant by 2008. Met-Ed and Penelec are collecting revenues for TMI-2 related to their wholesale customers.
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. The GPU System may also incur costs and experience reduced output at its nuclear plants because of the prevailing design criteria at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now-assumed lives cannot be assured. Also, not all risks associated with the ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric utilities to obtain adequate and timely recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of each plant's useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT COSTS). Management intends, in general, to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured (see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT).
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and contamination of, the plant and a release of radioactivity to the environment. The cleanup program was completed in 1990, and after receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Corporation and the Subsidiaries. Approximately 2,100 of such claims are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident.
General Public Utilities Corporation and Subsidiary Companies
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Subsidiaries had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for up to an aggregate of $335 million in premium charges under such plan, and (c) an indemnity agreement with the NRC for up to $85 million, bringing their total primary, secondary and tertiary financial protection up to an aggregate of $560 million. Under the secondary level, the Subsidiaries are subject to a retrospective premium charge of up to $5 million per reactor, or a total of $15 million (JCP&L, Met-Ed and Penelec's shares are $7.5 million, $5 million and $2.5 million, respectively).
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against the Corporation and the Subsidiaries and their suppliers (the defendants) under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights with respect to any award of punitive damages. A trial of ten allegedly representative cases is scheduled to begin in June 1996.
In October 1995, the U.S. Court of Appeals for the Third Circuit ruled that the Price-Anderson Act provides coverage under its primary and secondary levels for punitive as well as compensatory damages, but that punitive damages could not be recovered against the Federal Government under the third level of financial protection. In so doing, the Court of Appeals referred to the "finite fund" (the $560 million of financial protection under the Price- Anderson Act) to which plaintiffs must resort to get compensatory as well as punitive damages. The Corporation and its Subsidiaries have asked the U.S. Supreme Court to review that portion of the Court of Appeals' decision that punitive damages may be recovered in public liability actions under the Price- Anderson Act. The Corporation and its Subsidiaries do not know whether plaintiffs will appeal any aspect of the Court of Appeals' decision.
Based upon the Court of Appeals' decision, the Corporation and its Subsidiaries believe that any liability to which they might be subject by reason of the TMI-2 accident will not exceed their financial protection under the Price-Anderson Act.
The Court of Appeals also found that the standard of care owed by the defendants to a plaintiff was determined by the specific level of radiation which was released into the environment, as measured at the site boundary, rather than as measured at the specific site where the plaintiff was located at the time of the accident (as the Corporation and its Subsidiaries proposed). The Court of Appeals had also held that each plaintiff still must demonstrate exposure to radiation released during the TMI-2 accident and that such exposure had resulted in injuries. The Corporation and its Subsidiaries have requested that the U.S. Supreme Court review this issue. They do not know if whether plaintiffs will do so as well.
General Public Utilities Corporation and Subsidiary Companies
There can be no assurance as to the outcome of this litigation.
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's remaining in long- term storage and being decommissioned at the same time as TMI-1. Based on NRC studies, a comparable funding target has been developed for TMI-2 which takes the accident into account. Under the NRC regulations, the funding targets (in 1995 dollars) are as follows:
(Millions) Oyster Creek TMI-1 TMI-2
JCP&L $189 $ 39 $ 63 Met-Ed - 79 125 Penelec - 39 62 Total $189 $157 $250
The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
The Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, JCP&L has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990, and Met-Ed and Penelec have contributed amounts written off for TMI-2 nuclear plant decommissioning in 1991, to TMI-2's external trust (see TMI-2 Future Costs). Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the Balance Sheet.
General Public Utilities Corporation and Subsidiary Companies
In 1995, a consultant to GPUN performed site-specific studies of the TMI site, including both Units 1 and 2, and of Oyster Creek, that considered various decommissioning methods and estimated the cost of decommissioning the radiological portions and the cost of removal of the nonradiological portions of each plant, using the prompt removal/dismantlement method. GPUN management has reviewed the methodology and assumptions used in the site-specific studies, is in agreement with them, and believes the results are reasonable as follows: (Millions) Oyster GPU Creek TMI-1 TMI-2
Radiological decommissioning $347 $295 $358 Nonradiological cost of removal 33 73 37* Total $380 $368 $395
* Net of $3 million spent as of December 31, 1995.
(Millions) Oyster JCP&L Creek TMI-1 TMI-2
Radiological decommissioning $347 $74 $90 Nonradiological cost of removal 33 18 9* Total $380 $92 $99
* Net of $.75 million spent as of December 31, 1995.
(Millions) Met-Ed TMI-1 TMI-2
Radiological decommissioning $147 $179 Nonradiological cost of removal 37 19* Total $184 $198
* Net of $1.5 million spent as of December 31, 1995.
(Millions) Penelec TMI-1 TMI-2
Radiological decommissioning $74 $89 Nonradiological cost of removal 18 9* Total $92 $98
* Net of $.75 million spent as of December 31, 1995.
The ultimate cost of retiring the GPU System's nuclear facilities may be different from the cost estimates contained in these site-specific studies. Such costs are subject to (a) the escalation of various cost elements (including, but not limited to, general inflation), (b) the further development of regulatory requirements governing decommissioning, (c) the
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technology available at the time of decommissioning, and (d) the availability of nuclear waste disposal facilities.
The Financial Accounting Standards Board (FASB) is reviewing the utility industry's accounting practices for closure and removal of long-lived assets, including nuclear plant retirement costs. If the FASB's tentative conclusions are adopted, Oyster Creek and TMI-1 future retirement costs will have to be recognized as a liability currently, rather than recorded over the life of the plants (as is currently the practice), with an offsetting asset recorded for amounts collectible through rates. Any amounts not collectible through rates will have to be charged to expense. For TMI-2, a liability has already been recognized since the plant is no longer operating (see TMI-2 Future Costs). The FASB is expected to release an Exposure Draft in early 1996, and a final statement is expected to be effective for fiscal years beginning after December 15, 1996.
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 its share ($3.83 million) of an estimate of $15.3 million for TMI-1 and $31.6 million for Oyster Creek adopted in previous rate orders issued by the New Jersey Board of Public Utilities (NJBPU), for its share of the cost of removal of nonradiological structures and materials. The Pennsylvania Public Utility Commission (PaPUC) previously granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share ($37 million) of the NRC funding target and nonradiological cost of removal estimated in an earlier 1988 site-specific study to be $74 million (in 1995 dollars). The PaPUC also approved a rate change for Penelec which increased the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $73 million (JCP&L, Met-Ed and Penelec's shares are $23 million, $36 million and $14 million, respectively) for TMI-1 and $138 million for Oyster Creek at December 31, 1995. TMI-1 and Oyster Creek retirement costs are charged to depreciation expense over the expected service life of each nuclear plant, and amounted to $15 million (JCP&L, Met-Ed and Penelec's shares are $3 million, $8 million and $4 million, respectively) and $13 million, respectively, for 1995.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable under the current ratemaking process.
TMI-2 Future Costs:
The estimated liabilities for TMI-2 Future Costs (reflected as Three Mile Island Unit 2 Future Costs on the Balance Sheet) as of December 31, are as follows:
General Public Utilities Corporation and Subsidiary Companies
(Millions) GPU JCP&L Met-Ed Penelec
Radiological Decommissioning $358 $ 90 $179 $ 89 Nonradiological Cost of Removal 37* 9 19 9 Incremental Monitored Storage 18 4 9 5 Total $413 $103 $207 $103
* Net of $3 million (JCP&L, Met-Ed and Penelec's shares are $.75 million, $1.5 million and $.75 million, respectively) spent as of December 31, 1995.
(Millions) GPU JCP&L Met-Ed Penelec
Radiological Decommissioning $250 $63 $125 $62 Nonradiological Cost of Removal 72* 18 36 18 Incremental Monitored Storage 19 5 9 5 Total $341 $86 $170 $85
* Net of $2 million spent (JCP&L, Met-Ed and Penelec's shares are $.5 million, $1 million and $.5 million, respectively) as of December 31, 1994.
The 1995 liability recorded on the Balance Sheet for radiological decommissioning and nonradiological cost of removal is based on the 1995 site- specific study. The 1994 liability for radiological decommissioning was based on the NRC funding target, while the 1994 liability for nonradiological cost of removal was based on the 1988 site-specific study for TMI-1 ($74 million).
Offsetting the $413 million liability is $271 million (JCP&L, Met-Ed and Penelec's shares are $53 million, $147 million and $71 million, respectively) which is probable of recovery from customers and included in Three Mile Island Unit 2 Deferred Costs on the Balance Sheet, and $143 million (JCP&L, Met-Ed and Penelec's shares are $60 million, $57 million and $26 million, respectively) in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet. Of the $271 million still to be recovered from customers, $66 million (JCP&L, Met-Ed and Penelec's shares are $17 million, $33 million and $16 million, respectively) represents an increase from 1994 due to the 1995 site-specific study. Earnings on trust fund deposits collected from customers are included in amounts shown on the Balance Sheet under Three Mile Island Unit 2 Deferred Costs. TMI-2 decommissioning costs charged to expense in 1995 amounted to $14 million (JCP&L, Met-Ed and Penelec's shares are $3 million, $9 million and $2 million, respectively).
The NJBPU has granted JCP&L decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. In 1993, a PaPUC rate order permitted Met-Ed future recovery of certain TMI-2 retirement costs, based on the NRC funding target, and the cost of removal of nonradiological structures and materials, based on the 1988 site-specific study. The Pennsylvania Office
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of Consumer Advocate appealed that order to the Commonwealth Court, which reversed the PaPUC order in 1994. Consequently, Met-Ed recorded pre-tax charges totaling $127.6 million during 1994. Penelec, which is also subject to PaPUC regulation, recorded pre-tax charges of $56.3 million during 1994 for its share of such costs applicable to its retail customers. These charges appear in the Other Income and Deductions section of the 1994 Consolidated Statement of Income and are composed of $121 million (Met-Ed and Penelec's shares are $82.6 million and $38.4 million, respectively) for radiological decommissioning costs, $48.2 million (Met-Ed and Penelec's shares are $35 million and $13.2 million, respectively) for the nonradiological cost of removal and $14.7 million (Met-Ed and Penelec's shares are $10 million and $4.7 million, respectively) for incremental monitored storage costs. In September 1995, the Pennsylvania Supreme Court reversed the Commonwealth Court decision. Met-Ed and Penelec have therefore reversed the previous write-offs, resulting in pre-tax income of $127.6 million and $56.3 million, respectively, being credited to the Other Income and Deductions section of the 1995 Consolidated Statement of Income. However, notwithstanding the Supreme Court's decision, Met-Ed and Penelec have determined that the recovery of the incremental monitored storage costs is no longer probable, and have recorded pre-tax charges to operating income of $10 million and $4.7 million, respectively, during 1995.
At December 31, 1995 the accident-related portion of TMI-2 radiological decommissioning costs is considered to be $63 million (JCP&L, Met-Ed and Penelec's shares are $16 million, $32 million and $15 million, respectively), which is the difference between the 1995 TMI-1 and TMI-2 site-specific study estimates of $295 million and $358 million, respectively (JCP&L, Met-Ed and Penelec's shares are $74 million and $90 million, $147 million and $179 million, and $74 million and $89 million, respectively). In connection with rate case resolutions at the time, JCP&L, Met-Ed and Penelec made contributions to irrevocable external trusts relating to their shares of the accident-related portions of the decommissioning liability. In 1990, JCP&L contributed $15 million and in 1991, Met-Ed and Penelec contributed $40 million and $20 million respectively, to irrevocable external trusts. These contributions were not recovered from customers and have been expensed. The Subsidiaries will not pursue recovery from customers for any of these amounts contributed in excess of the $63 million accident-related portion referred to above.
JCP&L intends to seek recovery for any increases in TMI-2 retirement costs, and Met-Ed and Penelec intend to seek recovery for any increases in the nonaccident-related portion of such costs, but recognize that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage in late 1993, the Subsidiaries are incurring incremental storage costs of approximately $1 million (JCP&L, Met-Ed and Penelec's shares are $.25 million, $.5 million, and $.25 million, respectively) annually. The Subsidiaries estimate that the remaining storage costs will total $18 million through 2014, the expected retirement date of TMI-1. JCP&L's rates reflect its share of these costs.
General Public Utilities Corporation and Subsidiary Companies
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors, subject to an annual maximum payment of $10 million per incident per reactor. In addition to the retrospective premiums payable under Price-Anderson, the GPU System is also subject to retrospective premium assessments of up to $69 million (JCP&L, Met-Ed and Penelec's shares are $41 million, $19 million and $9 million, respectively) in any one year under insurance policies applicable to nuclear operations and facilities.
The GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing to 80 percent of such amounts for years two and three.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
Nonutility Generation Agreements:
Pursuant to the requirements of the federal Public Utility Regulatory Policies Act (PURPA) and state regulatory directives, the Subsidiaries have entered into power purchase agreements with nonutility generators (NUGs) for
General Public Utilities Corporation and Subsidiary Companies
the purchase of energy and capacity for periods up to 25 years for JCP&L, 26 years for Met-Ed, and 25 years for Penelec. The majority of these agreements contain certain contract limitations and subject the NUGs to penalties for nonperformance. While a few of these facilities are dispatchable, most are must-run and generally obligate the Subsidiaries to purchase, at the contract price, the net output up to the contract limits. As of December 31, 1995, facilities covered by these agreements having 1,624 MW (JCP&L, Met-Ed and Penelec's shares are 892 MW, 335 MW and 397 MW, respectively) of capacity were in service. Actual payments from 1993 through 1995, and estimated payments from 1996 through 2000 to NUGs, assuming that all facilities which have existing agreements, or which have obtained orders granting them agreements, enter service, are as follows:
Payments Under NUG Agreements (Millions)
Total JCP&L Met-Ed Penelec
1993 $ 491 $ 292 $ 95 $ 104 1994 528 304 101 123 1995 670 381 131 158 * 1996 696 369 151 176 * 1997 739 400 155 184 * 1998 837 430 210 197 * 1999 931 442 211 278 * 2000 987 463 216 308
* Estimate
Of these amounts, payments to the projects which are not in service at December 31, 1995 are estimated as follows:
Payments Under NUG Agreements Not In Service (Millions)
Total JCP&L Met-Ed Penelec
1997 $ 40 $ 25 $ 15 $ - 1998 123 53 65 5 1999 202 58 68 76 2000 231 62 71 98
In the year 2000 these agreements, in the aggregate, will provide approximately 2,062 MW (JCP&L 1,002 MW, Met-Ed 485 MW and Penelec 575 MW) of capacity and energy to the GPU System, at varying prices.
The emerging competitive generation market has created uncertainty regarding the forecasting of the System's energy supply needs which has caused the Subsidiaries to change their supply strategy to seek shorter-term agreements offering more flexibility. Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from generation facilities now in service is currently and is expected to continue to be priced below the costs
General Public Utilities Corporation and Subsidiary Companies
of new supply sources, at least for some time. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Subsidiaries' NUG agreements are substantially in excess of current and projected prices from alternative sources.
The Subsidiaries are seeking to reduce the above market costs of these NUG agreements by (1) attempting to convert must-run agreements to dispatchable agreements; (2) attempting to renegotiate prices of the agreements; (3) offering contract buyouts while seeking to recover the costs through their energy adjustment clauses (see Managing Nonutility Generation, in Management's Discussion and Analysis of Financial Condition and Results of Operations) and (4) initiating proceedings before federal and state agencies, and in the courts, where appropriate. In addition, the Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new NUG agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. These efforts may result in claims against the GPU System for substantial damages. There can, however, be no assurance as to the extent to which the Subsidiaries' efforts will be successful in whole or in part.
While the Subsidiaries thus far have been granted recovery of their NUG costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that for 1998, when substantially all of these NUG projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $240 million to $350 million (JCP&L $100 to $150 million; Met-Ed $50 million to $80 million; and Penelec $90 million to $120 million). The amount of these estimated above-market payments may increase or decrease substantially based upon, among other things, payment escalations in the contract terms, changes in fuel prices and changes in the capital and operating cost of new generating equipment.
Regulatory Assets and Liabilities:
In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the GPU System's financial statements reflect assets and costs based on current cost- based ratemaking regulation. 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
General Public Utilities Corporation and Subsidiary Companies
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.
In accordance with the provisions of FAS 71, the Subsidiaries have deferred certain costs pursuant to actions of the NJBPU, PaPUC and Federal Energy Regulatory Commission (FERC) and are recovering or expect to recover such costs in electric rates charged to customers. Regulatory assets are reflected in the Deferred Debits and Other Assets section of the Consolidated Balance Sheet, and regulatory liabilities are reflected in the Deferred Credits and Other Liabilities section of the Consolidated Balance Sheet. Regulatory assets and liabilities, as reflected in the December 31, 1995 Consolidated Balance Sheet, were as follows:
GPU (In Thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $ 527,584 $94,931 TMI-2 deferred costs 368,712 - Unamortized property losses 105,729 - NUG contract termination costs 84,132 - Other postretirement benefits 58,362 - N.J. unit tax 51,518 - Unamortized loss on reacquired debt 50,198 - Load and demand-side management programs 48,071 - DOE enrichment facility decommissioning 38,519 - Manufactured gas plant remediation 29,608 - Nuclear fuel disposal fee 21,946 - N.J. low-level radwaste disposal 21,778 - Storm damage 18,294 - Oyster Creek deferred costs 4,830 - Other 10,427 3,068 Total $1,439,708 $97,999
General Public Utilities Corporation and Subsidiary Companies
JCP&L (In Thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $134,787 $36,343 TMI-2 deferred costs 138,472 - Unamortized property losses 100,176 - NUG contract termination costs 17,482 - Other postretirement benefits 32,390 - N.J. unit tax 51,518 - Unamortized loss on reacquired debt 34,285 - Load and demand side management programs 48,071 - DOE enrichment facility decommissioning 24,503 - Manufactured gas plant remediation 29,608 - Nuclear fuel disposal fee 23,165 - N.J. low-level radwaste disposal 21,778 - Storm damage 18,294 - Oyster Creek deferred costs 4,830 - Other 5,369 1,254 Total $684,728 $37,597
Met-Ed (In Thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $178,513 $24,765 TMI-2 deferred costs 149,004 - Unamortized property losses 3,273 - NUG contract termination costs 66,650 - Other postretirement benefits 25,972 - Unamortized loss on reacquired debt 6,945 - DOE enrichment facility decommissioning 9,344 - Nuclear fuel disposal fee (1,025) - Other 1,299 1,696 Total $439,975 $26,461
Penelec (In Thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $214,284 $33,823 TMI-2 deferred costs 81,236 - Unamortized property losses 2,280 - Unamortized loss on reacquired debt 8,968 - DOE enrichment facility decommissioning 4,672 - Nuclear fuel disposal fee (194) - Other 3,759 118 Total $315,005 $33,941
Income taxes recoverable/refundable through future rates: Represents amounts deferred due to the implementation of FAS 109, "Accounting for Income Taxes," in 1993.
General Public Utilities Corporation and Subsidiary Companies
TMI-2 deferred costs: Represents costs that are recoverable through rates for the Subsidiaries' remaining investment in the plant and fuel core, radiological decommissioning and the cost of removal of nonradiological structures and materials in accordance with the 1995 site-specific study, and JCP&L's share of long-term monitored storage costs. For additional information, see TMI-2 Future Costs.
Unamortized property losses: Consists mainly of costs associated with JCP&L's Forked River Project, which are included in rates.
NUG contract termination costs: Represents one-time costs incurred for terminating power purchase contracts with NUGs, for which rate recovery has been granted or is probable (see Managing Nonutility Generation, in Management's Discussion and Analysis of Financial Condition and Results of Operations).
Other postretirement benefits: Includes costs associated with the adoption of FAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which are deferred in accordance with Emerging Issues Task Force Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises."
N.J. unit tax: JCP&L received NJBPU approval in 1993 to recover, with interest, over a ten-year period on an annuity basis, $71.8 million of Gross Receipts and Franchise Tax not previously recovered from customers.
Unamortized loss on reacquired debt: Represents premiums and expenses incurred in the early redemption of long-term debt. In accordance with FERC regulations, reacquired debt costs are amortized over the remaining original life of the retired debt.
Load and demand-side management (DSM) programs: Consists of load management costs that are currently being recovered, with interest, through JCP&L's retail base rates pursuant to a 1993 NJBPU order, and other DSM program expenditures that are recovered annually. Also includes provisions for lost revenues between base rate cases and performance incentives.
DOE enrichment facility decommissioning: These costs, representing payments to the DOE over a 15-year period beginning in 1994, are currently being collected through the Subsidiaries' energy adjustment clauses.
Manufactured gas plant remediation: Consists of costs being recovered associated with the investigation and remediation of several gas manufacturing plants. For additional information, see ENVIRONMENTAL MATTERS.
Nuclear fuel disposal fee: Represents amounts recoverable through rates for estimated future disposal costs for spent nuclear fuel at Oyster Creek and TMI-1 in accordance with the Nuclear Waste Policy Act of 1982.
N.J. low-level radwaste disposal: Represents the accrual of the estimated assessment for the siting of a disposal facility for low-level waste from Oyster Creek, less amortization as allowed in JCP&L's rates.
General Public Utilities Corporation and Subsidiary Companies
Storm damage: Relates to incremental noncapital costs associated with various storms in the JCP&L service territory that are not recoverable through insurance. These amounts were deferred based upon past rate recovery precedent. An annual amount for recovery of storm damage expense is included in JCP&L's retail base rates.
Oyster Creek deferred costs: Consists of replacement power and operation and maintenance (O&M) costs deferred in accordance with orders from the NJBPU. JCP&L has been granted recovery of these costs through rates at an annual amount until fully amortized.
Amounts related to the decommissioning of TMI-1 and Oyster Creek, which are not included in Regulatory Assets on the Balance Sheet, are separately disclosed in NUCLEAR PLANT RETIREMENT COSTS.
The Subsidiaries continue to be subject to cost-based ratemaking regulation. However, in the event that either all or a portion of their operations are no longer subject to these provisions, the related regulatory assets, net of regulatory liabilities, would have to be written off. In addition, any above market costs of purchased power commitments would have to be expensed (see Nonutility Generation Agreements), and increased depreciation expense would have to be recorded for any differences created by the use of a regulated depreciation method that is different from that which would have been used under generally accepted accounting principles for enterprises in general. The Corporation is unable to estimate when and to what extent FAS 71 may no longer be applicable.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the GPU System may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants, mine refuse piles and generating facilities, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material.
To comply with the federal Clean Air Act Amendments of 1990 (Clean Air Act), the Subsidiaries expect to spend up to $410 million (JCP&L, Met-Ed and Penelec's shares are $42 million, $163 million, and $205 million, respectively) for air pollution control equipment by the year 2000, of which approximately $234 million (JCP&L, Met-Ed and Penelec's shares are $41 million, $100 million, and $93 million, respectively) has already been spent. In developing its least-cost plan to comply with the Clean Air Act, the GPU System will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. In 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and
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Pennsylvania) and the District of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Subsidiaries expect that the U.S. Environmental Protection Agency (EPA) will approve state implementation plans consistent with the proposal, and that as a result, they will spend an estimated $60 million (Met-Ed and Penelec's shares are $14 million and $46 million, respectively) (included in the Clean Air Act total), beginning in 1997, to meet the seasonal reductions agreed upon by the OTC. The OTC has stated that it anticipates that additional NOx reductions will be necessary to meet the Clean Air Act's 2005 National Ambient Air Quality Standard for ozone. However, the specific requirements that will have to be met at that time have not been finalized. The Subsidiaries are unable to determine what additional costs, if any, will be incurred.
The GPU System companies have been notified by the EPA and state environmental authorities that they are among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 11 hazardous and/or toxic waste sites, broken down by company as follows:
JCP&L MET-ED PENELEC GPUN GPU TOTAL
PRPs 6 4 2 1 1 11*
* In some cases, the Subsidiaries are named separately for the same site.
In addition, the Subsidiaries have been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which they have not yet been named as PRPs. The Subsidiaries have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the GPU System companies.
JCP&L has entered into agreements with the New Jersey Department of Environmental Protection (NJDEP) for the investigation and remediation of 17 formerly owned manufactured gas plant sites. JCP&L has also entered into various cost-sharing agreements with other utilities for most of the sites. As of December 31, 1995, JCP&L has an estimated environmental liability of $29 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 future costs may range as high as $50 million. Estimates of these costs are subject to significant uncertainties because: JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $50 million.
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In 1993, the NJBPU approved a mechanism similar to JCP&L's Levelized Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas plant remediation costs when expenditures exceed prior collections. The NJBPU decision also provided for interest on any overrecovery to be credited to customers until the overrecovery is eliminated and for future costs to be amortized over seven years with interest. JCP&L is pursuing reimbursement of the remediation costs from its insurance carriers. In 1994, JCP&L filed a complaint with the Superior Court of New Jersey against several of its insurance carriers, relative to these manufactured gas plant sites. JCP&L requested the Court to order the insurance carriers to reimburse JCP&L for all amounts it has paid, or may be required to pay, in connection with the remediation of the sites. Pretrial discovery has begun in this case.
The GPU System companies are unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant.
OTHER COMMITMENTS AND CONTINGENCIES
The GPU System's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $491 million (JCP&L, Met-Ed, Penelec and GPUSC's shares are $256 million, $97 million, $124 million and $14 million, respectively) during 1996. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured.
The Subsidiaries have entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which they have ownership interests. The contracts, which expire at various dates between 1996 and 2004, require the purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal under the contracts is based on adjustments of indexed cost components. One of Penelec's contracts for the Homer City station also includes a provision for the payment of postretirement benefit costs. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $115 million (JCP&L, Met-Ed and Penelec's shares are $20 million, $18 million and $77 million, respectively) for 1996.
JCP&L has entered into agreements with other utilities to purchase capacity and energy for various periods through 2004. These agreements will provide for up to 1,085 MW in 1996, declining to 878 MW in 1999 and 696 MW in 2004. For the years 1996, 1997, 1998, 1999 and 2000, payments pursuant to these agreements are estimated to be $174 million, $164 million, $145 million, $124 million and $95 million, respectively.
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JCP&L is constructing a 141 MW gas-fired combustion turbine at its Gilbert generating station. This estimated $50 million project, of which $34 million has been spent, is expected to be in-service by mid-1996. In 1995, the NJDEP issued an air permit for the facility based, in part, on the NJBPU's 1994 order which found that New Jersey's Electric Facility Need Assessment Act is not applicable and that construction of this facility, without a market test, is consistent with New Jersey energy policies. An industry trade group representing NUGs has appealed the NJDEP's issuance of the air permit and the NJBPU's order to the Appellate Division of the New Jersey Superior Court. There can be no assurance as to the outcome of this proceeding.
The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from NUG projects. The proceeding was initiated, in part, to respond to contentions of the Division of the Ratepayer Advocate that by permitting utilities to recover such costs through the LEAC, an excess or "double" recovery may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1994, the NJBPU ruled that the LEAC periods prior to March 1991 were considered closed but subsequent LEAC periods remain open for further investigation. This matter is pending before a NJBPU Administrative Law Judge. JCP&L estimates that the potential refund liability for the LEAC periods from March 1991 through February 1996, the end of the current LEAC period, is $55 million. There can be no assurance as to the outcome of this proceeding.
JCP&L's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate annual generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect on net income of the performance standard charge at a 40% capacity factor would be approximately $10 million before tax. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBPU for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC.
As of December 31, 1995, approximately 52% of the GPU System's workforce was represented by unions for collective bargaining purposes. JCP&L employees' collective bargaining agreement is due to expire in 1996, representing 45% of the GPU System's union employees.
Niagara Mohawk Power Corporation (NIMO) has filed with the New York Public Service Commission a proposed restructuring plan that it claims may be needed to avoid seeking reorganization under Chapter XI of the Bankruptcy Code. Energy Initiatives has ownership interests, with an aggregate book value of approximately $35 million, in three NUG projects which have long-term purchase power agreements with NIMO. In the restructuring plan, NIMO has insisted on renegotiating all of its contracts with NUGs, and has claimed that it has the right to use eminent domain to condemn NUG facilities, if such negotiations are not successful. There can be no assurance as to the outcome of this matter.
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NIMO has also initiated actions in federal and state court seeking to invalidate numerous NUG contracts or limit the amount of annual generation produced by the NUG, and is withholding allegedly "excess" payments made in respect of "over generation" under these contracts, including the contracts for two of Energy Initiatives' projects. NIMO alleges to have overpaid Energy Initiatives approximately $10 million for the years 1993 through 1995. Energy Initiatives has filed motions to dismiss these complaints and is vigorously defending these actions. There can be no assurance as to the outcome of these proceedings.
At December 31, 1995, the EI Group had investments totalling $160 million in facilities located in four foreign countries. Although management attempts to mitigate the risk of investing in certain foreign countries by securing political risk insurance, the EI Group faces additional risks inherent to operating in such locations, including foreign currency fluctuations (see EI GROUP, in Management's Discussion and Analysis of Financial Condition and Results of Operations).
In March 1995, the FASB issued FAS 121, "Accounting for the Impairment of Long-Lived Assets," which is effective for fiscal years beginning after June 15, 1995. FAS 121 requires that long-lived assets, identifiable intangibles, capital leases and goodwill be reviewed for impairment whenever events occur or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In addition, FAS 121 requires that regulatory assets meet the recovery criteria of FAS 71, "Accounting for the Effects of Certain Types of Regulation," on an ongoing basis in order to avoid a writedown (see Regulatory Assets and Liabilities).
The implementation of FAS 121 by the GPU System in 1995 did not have an impact on results of operations because management believes the carrying amounts of all assets are probable of recovery from customers. However, as the Subsidiaries enter a more competitive environment, some assets could be subject to impairment, thereby necessitating writedowns, which could have a material adverse effect on the GPU System's results of operations and financial condition.
The FASB exposure draft relating to closure and removal of long-lived assets (see NUCLEAR PLANT RETIREMENT COSTS), applies to all long-lived assets, including fossil-fueled generating plants. For these assets, a liability will have to be recognized wherever a legal or constructive obligation exists to perform dismantlement or removal activities.
During the normal course of the operation of their businesses, in addition to the matters described above, the GPU System companies are from time to time involved in disputes, claims and, in some cases, as defendants in litigation in which compensatory and punitive damages are sought by the public, customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. While management does not expect that the outcome of these matters will have a material effect on the GPU System's financial position or results of operations, there can be no assurance that this will continue to be the case.
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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period. Actual results could differ from those estimates.
SYSTEM OF ACCOUNTS Certain reclassifications of prior years' data have been made to conform with the current presentation. The Subsidiaries' accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the PaPUC and NJBPU.
CONSOLIDATION The consolidated financial statements include the accounts of all subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation. The GPU System uses the equity method of accounting for investments in affiliates in which it has the ability to exercise significant influence (generally evidenced by a 20% to 50% ownership interest), and consolidates its wholly-owned subsidiaries, and any affiliates in which it has a controlling financial interest (generally evidenced by a greater than 50% ownership interest). All other investments are accounted for using the cost method.
CURRENCY TRANSLATION In accordance with Statement of Financial Accounting Standards No. 52 (FAS 52), "Foreign Currency Translation," balance sheet accounts of the GPU System's foreign operations are translated from foreign currencies into U.S. dollars at either year-end rates or historical rates, while income statement accounts are translated at the weighted average exchange rates for the period. The resulting translation adjustments are not material and are included in Retained Earnings. Any gains and losses resulting from foreign currency transactions would be included in net income.
REVENUES
The Subsidiaries recognize electric operating revenues for services rendered (including an estimate of unbilled revenues) 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.
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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 as follows:
GPU JCP&L Met-Ed Penelec
1995 3.22% 3.64% 3.07% 2.61% 1994 3.16% 3.62% 3.04% 2.49% 1993 3.19% 3.59% 2.91% 2.74%
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 pre-tax 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 as follows:
GPU JCP&L Met-Ed Penelec
1995 8.05% 8.04% 8.62% 7.78% 1994 6.45% 5.35% 7.31% 7.19% 1993 6.80% 7.80% 7.48% 4.91%
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. Met-Ed and Penelec have collected all of their
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TMI-2 investment attributable to retail customers. At December 31, 1995, $86 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/(Expense), Net on the Income Statement.
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 Policy Act of 1992) for the cleanup of enrichment plants operated by the Federal Government. The total liability at December 31, 1995 amounted to $36 million (JCP&L, Met-Ed and Penelec's shares are $23 million, $9 million and $4 million, respectively) and is primarily reflected in Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants will contribute annually, based on an assessment computed on prior enrichment purchases, over a 15-year period. The Subsidiaries made their initial payment to this fund in 1993, and they are recovering the remaining amounts through their fuel clauses. At December 31, 1995, $39 million (JCP&L, Met-Ed and Penelec's shares are $25 million, $9 million and $5 million, respectively) is recorded on the Balance Sheet in Regulatory 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 with the DOE for the disposal of spent nuclear fuel. The total liability under these contracts, including interest, at December 31, 1995, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $162 million (JCP&L, Met-Ed and Penelec's shares are $121 million, $27 million and $14 million, respectively), 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 $22 million (JCP&L, Met-Ed and Penelec's shares are $23 million, ($1) million and ($0.2) million, respectively) at December 31, 1995 in Regulatory Assets - Other. The rates
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presently charged to customers provide for the collection of these costs, plus interest, over remaining periods of 11 years for JCP&L and Met-Ed, and two years for Penelec.
The Subsidiaries are collecting one 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 companies file a consolidated federal income tax return. 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. Each subsidiary is allocated the tax reduction attributable to GPU expenses, in proportion to the average common stock equity investment of GPU in such subsidiary, during the year. In addition, each subsidiary will receive in current cash payments the benefit of its own net operating loss carrybacks to the extent that the other subsidiaries can utilize such net operating loss carrybacks to offset the tax liability they would otherwise have on a separate return basis (after taking into account any investment tax credits they could utilize on a separate return basis). This method of allocation does not allow any subsidiary to pay more than its separate return liability.
Deferred income taxes, which result primarily from 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 amounts 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, 1995 and 1994, the GPU System had $124 million and $347 million of short-term notes outstanding, respectively, of which $60 million in 1994 was commercial paper and the remainder was issued under bank lines of credit (credit facilities). The GPU System's weighted average interest rate
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on short term borrowings was 5.9% and 6.2% at December 31, 1995 and 1994, respectively.
The GPU System has $529 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total borrowings outstanding at any time and subject to various covenants and acceleration under certain conditions. The Credit Agreement borrowing rates and facility fee are dependent on the long-term debt ratings of the Subsidiaries.
4. LONG-TERM DEBT
At December 31, 1995, the GPU System had long-term debt outstanding, as follows:
Interest Rates
5.35% to 7% to 9% to Maturities 6.9% 8.85% 9.48% Total (In Thousands) First mortgage bonds: 1996-2005 $ 667,575 $ 514,191 $ 120,000 $1,301,766 2006-2015 177,120 118,500 - 295,620 2016-2025 253,500 645,000 50,000 948,500 Total $1,098,195 $1,277,691 $ 170,000 2,545,886
Amounts due within one year (115,701) Total 2,430,185
Other long-term debt (net of $5,545 due within one year) 141,429 Unamortized net discount (3,716) Total $2,567,898
For the years 1996, 1997, 1998, 1999 and 2000, the GPU System has long-term debt maturities of $121 million, $148 million, $140 million, $36 million and $126 million, respectively. Substantially all of the utility plant owned by the Subsidiaries is subject to the lien of their respective mortgages.
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The estimated fair value of the GPU System's long-term debt, as of December 31, 1995 and 1994 was as follows:
(In Thousands) Carrying Fair Amount Value
1995 $2,567,898 $2,712,102 1994 $2,345,417 $2,142,854
The fair value of 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 GPU System for debt of the same remaining maturities and credit qualities.
5. SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES
JCP&L Capital, L.P., Met-Ed Capital, L.P. and Penelec Capital, L.P., are special-purpose partnerships in which a subsidiary of JCP&L, Met-Ed and Penelec, respectively, is the sole general partner. The following issues of mandatorily redeemable preferred securities (Preferred Securities) were outstanding at December 31, 1995:
Issue Securities Total Company Series Price Outstanding (In Thousands)
JCP&L Capital 8.56% $25 5,000,000 $125,000 Met-Ed Capital 9.00% $25 4,000,000 100,000 Penelec Capital 8.75% $25 4,200,000 105,000 Total $330,000
The fair value of the Preferred Securities based on market price quotations at December 31, 1995 and 1994 is $106 million and $98 million, respectively, for Met-Ed Capital; $110 million and $101 million, respectively, for Penelec Capital; and $131 million for JCP&L Capital at December 31, 1995.
In 1995, JCP&L Capital, L.P. issued $125 million of Preferred Securities and in 1994, Met-Ed Capital, L.P. and Penelec Capital, L.P. issued $100 million and $105 million, respectively, of Preferred Securities. The proceeds from the sales of the Preferred Securities were then lent to JCP&L, Met-Ed and Penelec which, in turn, issued their deferrable interest subordinated debentures to the partnerships. JCP&L, Met-Ed and Penelec are taking tax deductions for the interest paid on the subordinated debentures.
The Preferred Securities of JCP&L Capital, L.P. mature in 2044, while those of Met-Ed Capital, L.P. and Penelec Capital, L.P. mature in 2043. The Preferred Securities are redeemable at the option of JCP&L beginning in 2000, and at the option of Met-Ed and Penelec beginning in 1999, at 100 percent of their principal amount, or earlier under certain limited circumstances, including the loss of the tax deduction for interest paid on the subordinated debentures. The partnerships' sole assets are the subordinated debentures. JCP&L, Met-Ed and Penelec have fully and unconditionally guaranteed payment of
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distributions, to the extent there is sufficient cash on hand to permit such payments and legally available funds, and payments on liquidation or redemption of their respective partnerships' Preferred Securities. Distributions on the Preferred Securities (and interest on the subordinated debentures) may be deferred for up to 60 months, but JCP&L, Met-Ed and Penelec may not pay dividends or redeem or acquire any of their preferred or common stock until deferred payments on their respective subordinated debentures are paid in full.
6. CAPITAL STOCK
COMMON STOCK The following table presents information relating to the common stock ($2.50 par value) of the Corporation:
1995 1994
Authorized shares 350,000,000 150,000,000 Issued shares 125,783,338 125,783,338 Reacquired shares 5,359,997 10,575,086 Outstanding shares 120,423,341 115,208,252 Restricted units 195,499 107,063
In 1995 and 1993, the Corporation sold five million and four million additional shares of common stock, respectively, for net proceeds of $157.5 million and $128.7 million, respectively. The issuances resulted in credits to capital surplus totaling $71.9 million and $60.2 million, in 1995 and 1993 respectively. In 1995, 1994 and 1993, under the Corporation's Dividend Reinvestment Plan, capital surplus was credited $2.7 million, $2.3 million and $2.1 million, respectively, for shares sold. No shares of common stock were reacquired in 1995 or 1994.
In 1995 and 1994, 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 vesting or restriction period. Beginning with units awarded in 1995, the units will be adjusted at the end of the vesting or restriction period based on the Corporation's performance over the restriction period. The shares issuable at the end of the vesting period could range from 0% to 200% of the originally issued units. 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 1995 and 1994, the Corporation awarded to plan participants 83,600 and 34,595 restricted units, respectively. In 1995 and 1994, the Corporation issued a total of 30,558 and 6,275 shares, respectively, from previously reacquired shares.
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PREFERRED STOCK At December 31, 1995, the Subsidiaries had the following issues of cumulative preferred stock outstanding:
Stated Value Shares Stated Value Series per Share Outstanding (In Thousands)
With mandatory redemption: 7.52% $100 440,000 $ 44,000 8.48% $100 500,000 50,000 8.65% $100 500,000 50,000 Total 1,440,000 144,000 Securities due within one year (10,000) Total $134,000
Without mandatory redemption: 3.70% - 4.70% $100 723,912 $ 72,391 7.88% $100 250,000 25,000 Total 973,912 97,391 Premium 725 Total $ 98,116
The fair value of the preferred stock with mandatory redemption, based on market price quotations at December 31, 1995 and 1994, is $146.6 million and $140.1 million, respectively.
The 7.52% and 8.65% Series are callable at various prices above their stated values beginning in 2002 and 2000, respectively. The 7.52% Series is to be redeemed ratably over twenty years beginning in 1998. The 8.65% Series is to be redeemed ratably over six years beginning in 2000. The 8.48% Series is not callable and is to be redeemed ratably over five years beginning in 1996. The outstanding shares with mandatory redemption have aggregate redemption requirements of $65 million for the years 1996 through 2000.
The outstanding shares of preferred stock without mandatory redemption are callable at various prices above their stated values. At December 31, 1995, the aggregate amount at which these shares could be called by the Subsidiaries was $102 million.
During 1995, JCP&L repurchased in the market 60,000 shares of its 7.52% cumulative preferred stock with mandatory redemption, with a stated value of $6 million. JCP&L's total cost of the redemption was $6.1 million, which resulted in a $.1 million charge to Retained Earnings.
During 1994, Met-Ed and Penelec redeemed their 7.68% (aggregate stated value of $35 million) and 8.36% (aggregate stated value of $25 million) cumulative preferred stock, respectively. Met-Ed's total cost of the redemption was $36 million, which resulted in a $1.2 million charge to Retained Earnings. Penelec's total cost of the redemption was $26 million, resulting in a $1.1 million charge to Retained Earnings.
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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 million. These redemptions resulted in a net $6.9 million charge to Retained Earnings.
At December 31, 1995 and 1994, 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.
7. INCOME TAXES
Effective January 1, 1993, the GPU System implemented FAS 109, "Accounting for Income Taxes." The cumulative effect of this accounting change on net income was immaterial. As of December 31, 1995 and 1994, the balance sheet reflected $528 million and $562 million, respectively, of income taxes recoverable through future rates (primarily related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $95 million and $106 million, respectively (related to unamortized ITC), substantially due to the recognition of amounts not previously recorded.
General Public Utilities Corporation and Subsidiary Companies
A summary of the components of deferred taxes as of December 31, 1995 and 1994 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1995 1994 1995 1994 Current: Current: Unbilled revenue $ 23 $ 16 Revenue taxes $ 16 $ 18 Other 4 2 Deferred energy 7 4 Total $ 27 $ 18 Total $ 23 $ 22
Noncurrent: Noncurrent: Unamortized ITC $ 95 $106 Liberalized Decommissioning 62 131 depreciation: Contribution in aid previously flowed of construction 23 25 through $ 301 $ 333 Other 150 167 future revenue Total $330 $429 requirements 209 229 Subtotal 510 562 Liberalized depreciation 817 767 Forked River 11 54 Other 128 56 Total $1,466 $1,439
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) 1995 1994 1993
Net income $440 $164 $296 Preferred stock dividends 17 21 29 Income tax expense 265 86 197 Book income subject to tax $722 $271 $522
Federal statutory rate 35% 35% 35% State tax, net of federal benefit 4 - 4 Other (2) (3) (1) Effective income tax rate 37% 32% 38%
General Public Utilities Corporation and Subsidiary Companies
Federal and state income tax expense is comprised of the following:
(In Millions) 1995 1994 1993 Provisions for taxes currently payable $154 $162 $127
Deferred income taxes: Liberalized depreciation 31 31 32 New Jersey revenue tax (2) 32 32 Deferral of energy costs 1 12 6 Accretion income 5 11 7 Decommissioning 71 (76) - VERP 24 (51) - Other (8) (21) 5 Deferred income taxes, net 122 (62) 82 Amortization of ITC, net (11) (14) (12) Income tax expense $265 $ 86 $197
In 1994, the GPU System and the Internal Revenue Service (IRS) reached an agreement to settle the Corporation's claim for 1986 that TMI-2 has been retired for tax purposes. The Corporation's Subsidiaries have received net refunds totaling $17 million, which have been credited to their customers. Also in 1994, the GPU System received net interest from the IRS totaling $46 million (before income taxes), associated with the refund settlement, which was credited to income. The IRS has completed its examinations of the GPU System's federal income tax returns through 1989. The years 1990 through 1992 are currently being audited.
8. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following:
(In Millions) 1995 1994 1993
Maintenance $253 $271 $275 Other taxes: New Jersey unit tax $209 $204 $202 Pennsylvania state gross receipts 74 70 68 Real estate and personal property 23 21 21 Other 43 54 53 Total $349 $349 $344
General Public Utilities Corporation and Subsidiary Companies
9. EMPLOYEE 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) 1995 1994 1993 Service cost-benefits earned during the period $ 30.0 $ 34.8 $ 28.6 Interest cost on projected benefit obligation 109.8 95.4 91.8 Less: Expected return on plan assets (112.9) (104.4) (96.6) Amortization (1.4) (1.4) (2.2) Net periodic pension cost $ 25.5 $ 24.4 $ 21.6
The above 1994 amounts do not include a pre-tax charge to earnings of $97 million resulting from the Voluntary Enhanced Retirement Programs (VERP).
The actual return on the plans' assets for the years 1995, 1994 and 1993 were gains of $322.0 million, $13.8 million and $145.9 million, respectively.
The funded status of the plans and related assumptions at December 31, 1995 and 1994 were as follows: (In Millions) 1995 1994 Accumulated benefit obligation (ABO): Vested benefits $ 1,172.8 $ 1,118.2 Nonvested benefits 133.7 120.5 Total ABO 1,306.5 1,238.7 Effect of future compensation levels 237.7 182.6 Projected benefit obligation (PBO) $ 1,544.2 $ 1,421.3
Plan assets at fair value $ 1,596.1 $ 1,279.9 PBO (1,544.2) (1,421.3) Plan assets in excess of (less than) PBO 51.9 (141.4) Less: Unrecognized net (gain) loss (64.9) 72.5 Unrecognized prior service cost (credit) 5.2 (0.6) Unrecognized net transition asset (5.8) (6.6) Adjustment required to recognize minimum liability (0.2) (1.2)
Accrued pension liability $ (13.8) $ (77.3)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0 Annual increase in compensation levels 5.5 6.0
General Public Utilities Corporation and Subsidiary Companies
In 1995, changes in assumptions, primarily the decrease in the discount rate assumption from 8% to 7.5%, resulted in a $67 million increase in the PBO as of December 31, 1995. The assets of the plans are held in a Master Trust and generally invested in common stocks and fixed income securities. The unrecognized net loss 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, "Employers' Accounting for Pensions," are being amortized to pension cost over the average remaining service periods for covered employees.
At December 31, 1995 and 1994, GPUSC had accumulated pension obligations in excess of amounts accrued; as a result, additional minimum liabilities in the amounts of $.1 million and $.7 million, net of deferred income taxes of $.1 million and $.5 million, respectively, are reflected as reductions in 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 1995, 1994 and 1993 were $13.4 million, $12.7 million and $12.2 million, respectively.
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. 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. The unrecognized net loss represents actual experience different from that assumed, which is deferred and not included in the determination of postretirement benefit cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits is being amortized to postretirement benefit cost over the average remaining service periods for covered employees.
General Public Utilities Corporation and Subsidiary Companies
A summary of the components of the net periodic postretirement benefit cost for 1995, 1994 and 1993 follows:
(In Millions) 1995 1994 1993 Service cost-benefits attributed to service during the period $ 13.4 $ 14.6 $ 12.5 Interest cost on the accumulated postretirement benefit obligation 43.4 37.0 34.3 Expected return on plan assets (11.0) (7.0) (3.4) Amortization of transition obligation 17.4 18.1 18.1 Other amortization, net 1.3 2.1 - Net periodic postretirement benefit cost 64.5 64.8 61.5 Less, deferred for future recovery (15.0) (15.8) (27.5) Postretirement benefit cost, net of deferrals $ 49.5 $ 49.0 $ 34.0
The above 1994 amounts do not include a pre-tax charge to earnings of $30 million relating to the VERP.
The actual return on the plans' assets for the years 1995, 1994 and 1993 was a gain of $27.9 million, $2.3 million and $3.9 million, respectively.
The funded status of the plans at December 31, 1995 and 1994, was as follows:
(In Millions) 1995 1994 Accumulated Postretirement Benefit Obligation: Retirees $ 361.6 $ 291.7 Fully eligible active plan participants 32.4 67.2 Other active plan participants 232.4 197.6 Total accumulated postretirement benefit obligation (APBO) $ 626.4 $ 556.5
APBO $(626.4) $(556.5) Plan assets at fair value 191.3 129.0 APBO in excess of plan assets (435.1) (427.5) Less: Unrecognized net loss 65.0 46.9 Unrecognized prior service cost 2.3 2.5 Unrecognized transition obligation 295.9 313.3 Accrued postretirement benefit liability $ (71.9) $ (64.8)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0
The GPU System intends to continue funding amounts for postretirement benefits with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
General Public Utilities Corporation and Subsidiary Companies
In 1995, the decrease in the health-care cost trend rate assumptions resulted in a $51 million decrease in the APBO, which was partially offset by an increase of $42 million in the APBO caused by the decrease in the discount rate assumption from 8% to 7.5%. 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 12% for those not eligible for Medicare and 9% for those eligible for Medicare, then decreasing gradually to 6% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995 and reach age 65. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $65 million as of December 31, 1995 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $8 million.
In JCP&L's 1993 base rate proceeding, the NJBPU 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 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," JCP&L is deferring the amounts above that level. Met-Ed is deferring the incremental postretirement benefit costs, charged to expense, associated with the adoption of FAS 106 and in accordance with EITF Issue 92-12, as authorized by the PaPUC in its 1993 base rate order.
In 1994, the Pennsylvania Commonwealth Court reversed a PaPUC order that allowed a nonaffiliated utility, outside a base rate proceeding, to defer certain incremental postretirement benefit costs for future recovery from customers. As a result of the Court's decision, in 1994, Penelec determined that its FAS 106 costs, including costs deferred since January 1993, were not likely to be recovered and charged $18.8 million to expense. In addition, $4 million of Penelec's unrecognized transition obligation resulting from employees who elected to participate in the VERP was also written off in 1994. In 1995, Penelec recorded a charge to income of approximately $9 million, which represents continued amortization of the transition obligation along with current accruals of FAS 106 expense for active employees.
10. 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, 1995:
General Public Utilities Corporation and Subsidiary Companies
Balance (In Millions) % Accumulated Station Owner Ownership Investment Depreciation
Homer City Penelec 50 $458.2 $161.6 Conemaugh Met-Ed 16.45 144.3 34.3 Keystone JCP&L 16.67 91.4 21.9 Yards Creek JCP&L 50 28.9 7.4 Seneca Penelec 20 16.4 4.8
11. LEASES
The GPU System's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1995 and 1994 totaled $152 million and $148 million, respectively (net of amortization of $189 million and $112 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. In 1995, the Subsidiaries refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. Reductions in nuclear fuel financing costs are expected through the new credit facilities. 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 have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. 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. 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, 1995, 1994 and 1993, these amounts were $57 million, $50 million and $66 million, respectively.
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 37 years, average approximately $3 million annually for each company.
Jersey Central Power & Light Company and Subsidiary Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS The Company's earnings in 1995 were $184.6 million, compared to 1994 earnings of $148 million. Contributing to this earnings increase were higher new customer sales, partially offset by lower weather-related sales; and lower other operation and maintenance expenses (O&M) due primarily to a $30.4 million (after-tax) charge in 1994 for early retirement programs. Also in 1994, the Company recognized net interest income of $7.4 million (after-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of Three Mile Island Unit 2 (TMI-2).
The Company's return on average common equity was 13.1% in 1995 compared to 11.2% in 1994.
Earnings in 1994 were $148 million, compared to 1993 earnings of $141.5 million. This earnings increase was due principally to higher new customer sales, colder winter weather in 1994, and an increase in revenues resulting from a February 1993 retail base rate case. Also contributing to this earnings increase were reduced reserve capacity expense, net interest income of $7.4 million (after-tax) related to the TMI-2 tax refunds, and a performance award for the operation of the Company's nuclear generating stations. Partially offsetting these increases were a charge of $30.4 million (after-tax) related to the 1994 early retirement programs and increased O&M expenses, which included higher emergency and winter storm repairs.
OPERATING REVENUES: Operating revenues increased 4.3% to $2.04 billion in 1995 after increasing 0.9% to $1.95 billion in 1994. The components of these changes are as follows:
(In Millions) 1995 1994
Kilowatt-hour (KWH) revenues (excluding energy portion) $ 11.4 $ 21.5 Rate increase - 20.8 Energy revenues 72.3 (31.0) Other revenues (0.2) 5.2 Increase in revenues $ 83.5 $ 16.5
Kilowatt-hour revenues
The increase in KWH revenues was due to increases in new residential and commercial customer sales, partially offset by lower weather-related sales.
Jersey Central Power & Light Company and Subsidiary Company
The increase in KWH revenues was due to increases in new residential and commercial customer sales, and colder winter weather as compared to the previous year.
1995 MWH Customer Sales by Service Class
Residential 41% Commercial 38% Industrial/Other 21%
Energy revenues
1995 and 1994 Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues in 1995 increased primarily from additional sales to other utilities and higher energy cost rates.
Other revenues
1995 and 1994 Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes.
OPERATING EXPENSES: Power purchased and interchanged
1995 and 1994 The increase in power purchased and interchanged (PP&I) expense was due largely to higher nonutility generation purchases.
Generally, changes in the energy component of PP&I expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy adjustment clause. However, 1995 earnings were negatively affected by higher reserve capacity expense (which is a component of PP&I) resulting primarily from a Pennsylvania-New Jersey- Maryland (PJM Power Pool) prior year adjustment and one-time net charges of $3.6 million (pre-tax) from another utility. Earnings in 1994 benefitted from lower reserve capacity expense resulting primarily from the expiration of a power purchase contract with another utility and a reduction in purchases from affiliated companies.
Fuel and Deferral of energy and capacity costs, net
1995 and 1994 Generally, changes in fuel expense and deferral of energy costs do not affect earnings as they are offset by corresponding changes in energy revenues.
Jersey Central Power & Light Company and Subsidiary Company
Other operation and maintenance
1995 and 1994 The decrease in other O&M expense was due primarily to a $46.9 million (pre-tax) charge in 1994 related to the early retirement programs and lower 1995 winter storm repairs.
The increase in other O&M expense was primarily attributable to a $46.9 million (pre-tax) charge for the early retirement programs. Also contributing to the increase were higher emergency and winter storm repairs and the accrual of additional payroll expense under an expanded employee incentive compensation program designed to tie pay increases more closely to business results and enhance productivity.
Depreciation and amortization
The increase in depreciation and amortization expense was due to additions to plant in service, partially offset by lower regulatory asset amortizations.
Depreciation and amortization expense increased due to additions to plant in service and higher regulatory asset amortizations.
Taxes, other than income taxes
1995 and 1994 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income, net
1995 and 1994 In 1994, the Company recorded interest income of $14.7 million (pre-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2. Also in 1994, there was a write-off of $4.2 million (pre-tax) for a cancelled project.
INTEREST CHARGES AND PREFERRED DIVIDENDS: Other interest
1995 and 1994 In 1994, the Company recognized interest expense related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $3.3 million (pre-tax) charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Jersey Central Power & Light Company and Subsidiary Company
Dividends on company-obligated mandatorily redeemable preferred securities
Through a special-purpose partnership, the Company issued $125 million stated value of mandatorily redeemable preferred securities.
LIQUIDITY AND CAPITAL RESOURCES Capital Needs:
The Company's capital needs were $265 million in 1995, consisting of cash construction expenditures of $218 million and amounts for maturing obligations of $47 million.
During 1995, construction expenditures were used primarily to maintain and improve existing generation, transmission and distribution facilities, continue with the construction of a new generation facility, and for various clean air compliance projects. In 1996, construction expenditures for the Company are estimated to be $256 million, consisting primarily of $202 million for ongoing system development, $26 million for upgrading the communication system, and $15 million for the continued construction of a new generation facility. Expenditures for maturing obligations will total $36 million in 1996, and $86 million in 1997. Management estimates that approximately three- fourths of the Company's 1996 capital needs will be satisfied through internally generated funds.
Cash Construction Expenditures (In millions of dollars) 1991 1992 1993 1994 1995 1996 $242 $219 $197 $244 $218 $256*
* Estimate
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. The Company's share of nuclear fuel capital leases at December 31, 1995 totaled $88 million. In 1995, the Company and its affiliates refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. These nuclear fuel leases have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of between $20 million and $25 million annually. In the event the needed nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
Financing:
In 1995, GPU sold five million shares of common stock. The net proceeds of $157.5 million were used to make cash capital contributions to the GPU
Jersey Central Power & Light Company and Subsidiary Company
System, of which the Company's share was $75 million, and to repay GPU short- term debt.
The Company has regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock through June 1997. Under existing authorizations, the Company may issue these senior securities in the amount of up to $225 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
In 1995, the Company issued $50 million principal amount of FMBs, the proceeds of which were used to moderate short-term debt levels. JCP&L Capital L.P., a special-purpose partnership in which a subsidiary of the Company is the sole general partner, issued $125 million stated value of mandatorily redeemable preferred securities (carried on the balance sheet as Company- obligated mandatorily redeemable preferred securities). The proceeds from the issuance were used to reduce short-term debt and retire senior securities. Also in 1995, the Company repurchased, in the market, $6 million stated value of cumulative preferred stock. The repurchased shares may be used to satisfy future sinking fund requirements.
The Company's FMB indenture and certificate of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Company may issue. The Company's interest and preferred dividend coverage ratios are currently in excess of indenture and charter restrictions.
The Company's cost of capital and ability to obtain external financing are affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. The Company's senior securities ratings have remained constant since August 1994. The Company's FMBs are currently rated at an equivalent of BBB+ by the three major credit rating agencies, while the preferred stock and mandatorily redeemable preferred securities issues have been assigned an equivalent of BBB. In addition, the Company's commercial paper is rated as having good credit quality.
The Standard & Poor's (S&P) rating outlook for the Company has remained at "stable," and reflects a manageable construction program, minimal rate relief requirements and expectations of modest strengthening in the service area economy. The rating outlook is used to assess the potential direction of an issuer's long-term debt rating over the intermediate to longer-term. The S&P business position assigned to the Company has remained unchanged throughout the year at "low average". The business position is a financial benchmarking standard for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry.
The Company may issue long-term debt during the next three years to finance construction activities, fund the redemption of maturing senior securities, and depending on interest rates, refinance outstanding senior securities.
Jersey Central Power & Light Company and Subsidiary Company
Capitalization:
The Company's target capitalization ratios are designed to provide credit quality ratings that permit capital market access at reasonable costs. The targets and actual capitalization ratios are as follows:
Target Range 1995 1994 1993 Common equity 48-51% 49% 47% 47% Preferred equity 8-10 10 7 7 Notes payable and long-term debt 44-39 41 46 46 100% 100% 100% 100%
The following remaining sections of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS are being presented on a combined basis, and are included in the GPU section of this Form 10-K.
COMPETITIVE ENVIRONMENT: See GPU page.
Recent Regulatory Actions: See GPU page.
Managing the Transition: See GPU pages.
Nonutility Generation Agreements: See GPU page.
THE GPU SUPPLY PLAN: See GPU page.
New Energy Supplies: See GPU page.
Managing Nonutility Generation: See GPU page.
ENVIRONMENTAL ISSUES: See GPU pages.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS: See GPU page.
EFFECTS OF INFLATION: See GPU page.
Jersey Central Power & Light Company and Subsidiary Company
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter 1995 1994* 1995 1994**
Operating revenues $468,034 $486,910 $453,081 $458,897
Operating income 57,227 71,521 61,834 29,270
Net income 36,211 53,097 36,796 5,175
Earnings available for common stock 32,512 49,398 33,210 1,476
In Thousands
Third Quarter Fourth Quarter 1995 1994 1995 1994
Operating revenues $625,479 $567,827 $489,334 $438,791
Operating income 119,457 99,304 52,702 54,183
Net income 95,447 74,573 30,635 29,996
Earnings available for common stock 91,861 70,875 27,049 26,297
* Results for the first quarter of 1994 reflect an increase in earnings of $7.4 million (after-tax) resulting from net interest income on refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter of 1994 reflect a decrease in earnings of $30.4 million (after-tax) for costs related to early retirement programs.
Jersey Central Power & Light Company and Subsidiary Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors Jersey Central Power & Light Company Morristown, New Jersey
We have audited the consolidated financial statements and financial statement schedule of Jersey Central Power & Light Company and Subsidiary Company as listed in the index on page of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. These 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 Jersey Central Power & Light Company and Subsidiary Company as of December 31, 1995 and 1994 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
New York, New York January 31, 1996
Jersey Central Power & Light Company and Subsidiary Company
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands) For the Years Ended December 31, 1995 1994 1993
Operating Revenues $2,035,928 $1,952,425 $1,935,909
Operating Expenses: Fuel 101,110 94,503 98,683 Power purchased and interchanged: Affiliates 17,950 18,661 23,681 Others 642,858 579,948 578,131 Deferral of energy and capacity costs, net (5,949) (19,448) 28,726 Other operation and maintenance 475,448 526,623 460,128 Depreciation and amortization 194,976 191,042 182,945 Taxes, other than income taxes 226,994 231,070 228,690 Total operating expenses 1,653,387 1,622,399 1,600,984
Operating Income Before Income Taxes 382,541 330,026 334,925 Income taxes 91,321 75,748 77,995 Operating Income 291,220 254,278 256,930
Other Income and Deductions: Allowance for other funds used during construction 1,803 893 2,471 Other income, net 14,889 21,995 6,281 Income taxes (5,905) (9,372) (2,847) Total other income and deductions 10,787 13,516 5,905
Income Before Interest Charges and Dividends on Preferred Securities 302,007 267,794 262,835
Interest Charges and Dividends on Preferred Securities: Interest on long-term debt 92,602 93,477 100,246 Other interest 9,709 14,726 6,530 Allowance for borrowed funds used during construction (6,021) (3,250) (2,285) Dividends on company-obligated mandatorily redeemable preferred securities 6,628 - - Total interest charges and dividends on preferred securities 102,918 104,953 104,491
Net Income 199,089 162,841 158,344 Preferred stock dividends 14,457 14,795 16,810 Earnings Available for Common Stock $ 184,632 $ 148,046 $ 141,534
The accompanying notes are an integral part of the consolidated financial statements.
Jersey Central Power & Light Company and Subsidiary Company
CONSOLIDATED BALANCE SHEETS
(In Thousands) December 31, 1995 1994
ASSETS Utility Plant: In service, at original cost $4,311,458 $4,119,617 Less, accumulated depreciation 1,669,893 1,499,405 Net utility plant in service 2,641,565 2,620,212 Construction work in progress 157,885 136,884 Other, net 111,023 123,349 Net utility plant 2,910,473 2,880,445
Other Property and Investments: Nuclear decommissioning trusts 225,200 165,511 Nuclear fuel disposal fund 95,393 82,920 Other, net 7,218 6,906 Total other property and investments 327,811 255,337
Current Assets: Cash and temporary cash investments 922 1,041 Special deposits 7,358 4,608 Accounts receivable: Customers, net 150,002 126,760 Other 21,912 16,936 Unbilled revenues 66,389 59,288 Materials and supplies, at average cost or less: Construction and maintenance 95,949 95,937 Fuel 18,693 18,563 Deferred energy costs 5,290 (148) Deferred income taxes 12,142 10,454 Prepayments 20,869 45,880 Total current assets 399,526 379,319
Deferred Debits and Other Assets: Regulatory assets: Three Mile Island Unit 2 deferred costs 138,472 138,294 Unamortized property losses 100,176 104,451 Income taxes recoverable through future rates 134,787 132,642 Other 311,293 309,230 Total regulatory assets 684,728 684,617 Deferred income taxes 122,082 122,944 Other 20,359 13,978 Total deferred debits and other assets 827,169 821,539
Total Assets $4,464,979 $4,336,640
The accompanying notes are an integral part of the consolidated financial statements.
Jersey Central Power & Light Company and Subsidiary Company
CONSOLIDATED BALANCE SHEETS
(In Thousands) December 31, 1995 1994
LIABILITIES AND CAPITAL Capitalization: Common stock $ 153,713 $ 153,713 Capital surplus 510,769 435,715 Retained earnings 816,770 772,240 Total common stockholder's equity 1,481,252 1,361,668 Cumulative preferred stock: With mandatory redemption 134,000 150,000 Without mandatory redemption 37,741 37,741 Company-obligated mandatorily redeemable preferred securities 125,000 - Long-term debt 1,192,945 1,168,444 Total capitalization 2,970,938 2,717,853
Current Liabilities: Securities due within one year 35,710 47,439 Notes payable 800 110,356 Obligations under capital leases 90,329 102,059 Accounts payable: Affiliates 31,885 34,283 Other 111,225 118,369 Taxes accrued 10,516 22,561 Interest accrued 28,718 29,765 Other 75,069 75,159 Total current liabilities 384,252 539,991
Deferred Credits and Other Liabilities: Deferred income taxes 607,188 598,843 Unamortized investment tax credits 66,874 72,928 Three Mile Island Unit 2 future costs 103,271 85,273 Nuclear Fuel Disposal Fee 121,121 114,374 Regulatory liabilities 37,597 41,732 Other 173,738 165,646 Total deferred credits and other liabilities 1,109,789 1,078,796
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4,464,979 $4,336,640
The accompanying notes are an integral part of the consolidated financial statements.
Jersey Central Power & Light Company and Subsidiary Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was incorporated under the laws of New Jersey in 1925, is a wholly-owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company's business is the generation, transmission, distribution and sale of electricity. The Company owns all of the common stock of JCP&L Preferred Capital, Inc., which is the sole general partner of JCP&L Capital L.P., a special-purpose partnership. The Company is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to herein as the "Company and its affiliates." The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and Energy Initiatives, Inc., EI Power, Inc., and EI Energy, Inc. (collectively, the "EI Group"), which develop, own and operate generation, transmission and distribution facilities in the United States and in foreign countries. All of the Company's affiliates are wholly-owned subsidiaries of GPU. The Company and its affiliates, as well as GPUSC, GPUN and the EI Group, are referred to herein as the "GPU System."
Note 1, "Commitments and Contingencies," and Note 2, "Summary of Significant Accounting Policies," are being presented for GPU, the Company and its affiliates on a combined basis and are included in the GPU section of this Form 10-K.
Note 1 - Commitments and Contingencies: See GPU page.
Nuclear Facilities: See GPU page.
Nuclear Plant Retirement Costs: See GPU page.
Insurance: See GPU page.
Competition and the Changing Regulatory Environment: See GPU page.
Environmental Matters: See GPU page.
Other Commitments and Contingencies: See GPU page.
Note 2 - Summary of Significant Accounting Policies: See GPU page.
Jersey Central Power & Light Company and Subsidiary Company
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1995 and 1994, the Company had $1 million and $110 million of short-term notes outstanding, respectively, of which $33 million in 1994 was commercial paper and the remainder was issued under bank lines of credit (credit facilities). The Company's weighted average interest rate on short term borrowings was 6% and 6.2% at December 31, 1995 and 1994, respectively.
GPU and the Company and its affiliates have $529 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total borrowings outstanding at any time and subject to various covenants and acceleration under certain conditions. The Credit Agreement borrowing rates and facility fee are dependent on the long-term debt ratings of the Company and its affiliates.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of December 31, 1995 and 1994, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1995: Cumulative preferred stock with mandatory redemption $ 134 $ 147 Company-obligated mandatorily redeemable preferred securities 125 131 Long-term debt 1,193 1,261
December 31, 1994: Cumulative preferred stock with mandatory redemption $ 150 $ 140 Long-term debt 1,168 1,051
The fair values of the Company's financial instruments are estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments of the same remaining maturities and credit qualities.
5. INCOME TAXES
Effective January 1, 1993, the Company implemented FAS 109, "Accounting for Income Taxes." The cumulative effect of this accounting change on net
Jersey Central Power & Light Company and Subsidiary Company
income was immaterial. As of December 31, 1995 and 1994, the balance sheet reflected $135 million and $132 million, respectively, of income taxes recoverable through future rates (primarily related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $36 million and $40 million, respectively (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, 1995 and 1994 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1995 1994 1995 1994 Current: Current: Unbilled revenue $ 12 $ 10 Revenue taxes $ 16 $ 18 Deferred energy 3 - Total $ 12 $ 10 Total $ 19 $ 18
Noncurrent: Noncurrent: Unamortized ITC $ 36 $ 40 Liberalized Decommissioning 26 25 depreciation: Contribution in aid previously flowed of construction 19 20 through $ 77 $ 86 Other 41 38 future revenue Total $122 $123 requirements 42 46 Subtotal 119 132 Liberalized depreciation 393 383 Forked River 11 54 Other 84 29 Total $607 $598
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) 1995 1994 1993
Net income $199 $163 $158 Income tax expense 97 85 81 Book income subject to tax $296 $248 $239
Federal statutory rate 35% 35% 35% Other (2) (1) (1) Effective income tax rate 33% 34% 34%
Jersey Central Power & Light Company and Subsidiary Company
Federal and state income tax expense is comprised of the following:
(In Millions) 1995 1994 1993 Provisions for taxes currently payable $100 $ 50 $ 42
Deferred income taxes: Liberalized depreciation 8 13 19 NUG buyout costs 6 - - Gain/Loss on reacquired debt - 6 9 New Jersey revenue tax (2) 32 32 Deferral of energy costs 1 9 (8) Abandonment loss - Forked River (4) (5) (4) Nuclear outage maintenance costs (6) 6 - Accretion income 5 6 6 Unbilled revenue (2) 2 5 VERP 3 (15) - Other (6) (12) (14) Deferred income taxes, net 3 42 45 Amortization of ITC, net ( 6) ( 7) ( 6) Income tax expense $ 97 $ 85 $ 81
In 1994, the GPU System and the Internal Revenue Service (IRS) reached an agreement to settle the claim for 1986 that TMI-2 has been retired for tax purposes. The Company and its affiliates have received net refunds totaling $17 million, of which the Company's share is $4 million, which have been credited to their customers. Also in 1994, the GPU System received net interest from the IRS totaling $46 million, of which the Company's share is $11.5 million (before income taxes), associated with the refund settlement, which was credited to income. The IRS has completed its examinations of the GPU System's federal income tax returns through 1989. The years 1990 through 1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following: (In Millions) 1995 1994 1993
Maintenance $128 $132 $135 Other taxes: New Jersey unit tax $209 $204 $202 Real estate and personal property 8 7 6 Other 10 20 21 Total $227 $231 $229
Jersey Central Power & Light Company and Subsidiary Company
For the years 1995, 1994 and 1993, the cost to the Company of services rendered to it by GPUSC amounted to approximately $43 million, $48 million and $39 million, respectively, of which approximately $35 million, $37 million and $29 million, respectively, was charged to income. For the years 1995, 1994 and 1993, the cost to the Company of services rendered to it by GPUN amounted to approximately $186 million, $268 million and $227 million, respectively of which approximately $148 million, $205 million and $184 million, respectively was charged to income. For the years 1995, 1994 and 1993, the Company purchased $23 million, $22 million and $23 million, respectively, in energy from a cogeneration project in which an affiliate has a 50 percent partnership interest.
7. EMPLOYEE BENEFITS
Pension Plans:
The Company maintains defined benefit pension plans covering substantially all employees. The Company's policy is to currently fund net pension costs within the deduction limits permitted by the Internal Revenue Code.
A summary of the components of net periodic pension cost follows:
(In Millions) 1995 1994 1993 Service cost-benefits earned during the period $ 7.3 $ 8.8 $ 8.7 Interest cost on projected benefit obligation 32.9 29.0 29.4 Less: Expected return on plan assets (35.2) (33.3) (32.1) Amortization (0.3) (0.5) (0.4) Net periodic pension cost $ 4.7 $ 4.0 $ 5.6
The above 1994 amounts do not include a pre-tax charge to earnings of $38 million resulting from the Voluntary Enhanced Retirement Programs (VERP).
The actual return on the plans' assets for the years 1995, 1994 and 1993 were gains of $101.3 million, $4.4 million and $48.0 million, respectively.
The funded status of the plans and related assumptions at December 31, 1995 and 1994 were as follows:
Jersey Central Power & Light Company and Subsidiary Company
(In Millions) 1995 1994 Accumulated benefit obligation (ABO): Vested benefits $ 359.8 $ 335.9 Nonvested benefits 30.4 34.3 Total ABO 390.2 370.2 Effect of future compensation levels 69.9 55.9 Projected benefit obligation (PBO) $ 460.1 $ 426.1
Plan assets at fair value $ 494.4 $ 403.7 PBO (460.1) (426.1) Plan assets in excess of (less than) PBO 34.3 (22.4) Less: Unrecognized net (gain) loss (32.2) 13.3 Unrecognized prior service cost 2.4 3.5 Unrecognized net transition asset (2.1) (2.5) Prepaid (accrued) pension cost $ 2.4 $ (8.1)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0 Annual increase in compensation levels 5.5 6.0
In 1995, changes in assumptions, primarily the decrease in the discount rate assumption from 8% to 7.5%, resulted in a $19 million increase in the PBO as of December 31, 1995. The assets of the plans are held in a Master Trust and generally invested in common stocks and fixed income securities. The unrecognized net (gain) loss 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, "Employers' Accounting for Pensions," are being amortized to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1995, 1994 and 1993 were $3.2 million, $2.4 million and $2.4 million, respectively.
Postretirement Benefits Other Than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants.
Jersey Central Power & Light Company and Subsidiary Company
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years. The unrecognized net loss represents actual experience different from that assumed, which is deferred and not included in the determination of postretirement benefit cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits is being amortized to postretirement benefit cost over the average remaining service periods for covered employees.
A summary of the components of the net periodic postretirement benefit cost for 1995, 1994 and 1993 follows:
(In Millions) 1995 1994 1993 Service cost-benefits attributed to service during the period $ 3.0 $ 3.3 $ 3.4 Interest cost on the accumulated postretirement benefit obligation 11.2 9.4 10.4 Expected return on plan assets (2.3) (1.7) (0.7) Amortization of transition obligation 5.0 5.2 5.7 Other amortization, net 0.5 0.4 - Net periodic postretirement benefit cost 17.4 16.6 18.8 Less, deferred for future recovery (4.0) (7.8) (9.6) Postretirement benefit cost, net of deferrals $ 13.4 $ 8.8 $ 9.2
The above 1994 amounts do not include a pre-tax charge to earnings of $9 million relating to the VERP. The amount deferred for future recovery does not include $5.0 million of allocated postretirement benefit costs from the Company's affiliates for 1995.
The actual return on the plans' assets for the years 1995, 1994 and 1993 was a gain of $5.7 million, $0.6 million and $0.9 million, respectively.
The funded status of the plans at December 31, 1995 and 1994, was as follows:
Jersey Central Power & Light Company and Subsidiary Company
(In Millions) 1995 1994 Accumulated Postretirement Benefit Obligation: Retirees $ 89.2 $ 72.0 Fully eligible active plan participants 18.9 24.7 Other active plan participants 53.4 47.1 Total accumulated postretirement benefit obligation (APBO) $ 161.5 $ 143.8
APBO $(161.5) $(143.8) Plan assets at fair value 39.7 26.0 APBO in excess of plan assets (121.8) (117.8) Less: Unrecognized net loss 12.9 7.5 Unrecognized transition obligation 85.3 90.0 Accrued postretirement benefit liability $ (23.6) $ (20.3)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0
The Company intends to continue funding amounts for postretirement benefits with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
In 1995, the decrease in the health-care cost trend rate assumptions resulted in a $13 million decrease in the APBO, which was partially offset by an increase of $11 million in the APBO caused by the decrease in the discount rate assumption from 8% to 7.5%. 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 12% for those not eligible for Medicare and 9% for those eligible for Medicare, then decreasing gradually to 6% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995 and reach age 65. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $17 million as of December 31, 1995 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $2 million.
In the Company's 1993 base rate proceeding, the NJBPU allowed the Company to collect $3 million annually of the incremental postretirement benefit costs, charged to expense, recognized as a result of FAS 106. Based on the final order and in accordance with Emerging Issues Task Force Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," the Company is deferring the amounts above that level.
Jersey Central Power & Light Company and Subsidiary Company
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the investment and charges its share of operating expenses to the appropriate expense accounts. The Company participated with affiliated and nonaffiliated utilities in the following jointly owned stations at December 31, 1995:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation Three Mile Island Unit 1 25 $214.4 $ 70.1 Keystone 16.67 91.4 21.9 Yards Creek 50 28.9 7.4
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1995 and 1994 totaled $88 million and $99 million, respectively (net of amortization of $127 million and $68 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. In 1995, the Company and its affiliates refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. Reductions in nuclear fuel financing costs are expected through the new credit facilities. It is contemplated that when consumed, portions of the presently leased material will be replaced by additional leased material. The Company and its affiliates are responsible for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment. 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, 1995, 1994 and 1993, these amounts were $35 million, $28 million and $34 million, respectively.
The Company has sold and leased back substantially all of its ownership interest in the Merrill Creek Reservoir Project. The minimum lease payments under this operating lease, which has a remaining term of 37 years, average approximately $3 million annually.
Metropolitan Edison Company and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS The Company's 1995 earnings were $147.6 million, compared to a net loss of $2.2 million for 1994. The increase in earnings was primarily due to the net effect of several 1995 and 1994 nonrecurring items. The Company's return on average common equity was 23.5% in 1995 compared to (0.4)% in 1994.
Excluding these nonrecurring items, earnings for 1995 would have been $80.5 million, compared to 1994 earnings of $77.7 million. Return on average common equity for 1995 and 1994, on this basis, would have been 13.4% and 11.6%, respectively. Contributing to this increase were higher customer sales and lower operation and maintenance (O&M) expenses, partially offset by higher depreciation and financing expenses.
The 1995 nonrecurring items consisted of a reversal of $72.8 million (after-tax) of certain future Three Mile Island Unit 2 (TMI-2) retirement costs written off in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 Pennsylvania Public Utility Commission (PaPUC) order allowing the Company to recover its share of such costs from customers. Partially offsetting this increase was a $5.7 million (after-tax) charge to income for the Company's share of TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
The 1994 nonrecurring items included the above mentioned TMI-2 write-off of $72.8 million (after-tax). Also in 1994, there was a charge to income of $20.1 million (after-tax) for early retirement program costs; and net interest income of $13 million (after-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
In 1994, the Company had a net loss of $2.2 million, compared to earnings in 1993 of $70.9 million. The 1994 earnings reduction was attributable to the 1994 nonrecurring items mentioned above. Also, in 1993 there was a write-off of $4.8 million (after-tax) for the cancellation of proposed power supply and transmission facilities agreements. Excluding these nonrecurring items, earnings for 1994 would have been $77.7 million, compared to 1993 earnings of $75.7 million.
OPERATING REVENUES: Operating revenues increased 6.7% to $854.7 million in 1995 after decreasing slightly to $801.3 million in 1994. The components of these changes are as follows:
Metropolitan Edison Company and Subsidiary Companies
(In Millions) 1995 1994
Kilowatt-hour (KWH) revenues (excluding energy portion) $ 4.8 $ 0.4 Energy revenues 46.4 (2.2) Other revenues 2.2 1.6 Increase/(decrease) in revenues $ 53.4 $ (0.2)
Kilowatt-hour revenues
The increase in KWH revenues was due to an increase in new residential and commercial customer sales and higher industrial customer usage, partially offset by lower weather-related sales.
The increase in KWH revenues was due principally to an increase in customer usage and an increase in new residential customer sales, partially offset by lower sales to other utilities.
1995 MWH Customer Sales by Service Class
Residential 35% Commercial 27% Industrial/Other 38%
Energy revenues
1995 and 1994 Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues in 1995 increased primarily from higher energy cost rates and additional sales to other utilities. The 1994 decrease was due primarily to lower electric sales to other utilities, partially offset by higher sales to customers.
Other revenues
1995 and 1994 Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes.
OPERATING EXPENSES: Power purchased and interchanged
1995 and 1994 Generally, changes in the energy component of power purchased and interchanged (PP&I) expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy adjustment clause. However, 1995 and 1994 earnings benefitted from lower
Metropolitan Edison Company and Subsidiary Companies
reserve capacity expense (which is a component of PP&I). Contributing to the 1995 increase in PP&I were higher nonutility generation (NUG) purchases and higher interchange purchases from affiliated companies.
Fuel and Deferral of energy costs, net
1995 and 1994 Generally, changes in fuel expense and deferral of energy costs do not affect earnings as they are offset by corresponding changes in energy revenues.
Other operation and maintenance
The decrease in other O&M expense was due primarily to a $35.2 million (pre-tax) charge in 1994 related to the early retirement programs. Partially offsetting this decrease was a 1995 write-off of $10 million (pre-tax) for TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
The increase in other O&M expense was due primarily to a $35.2 million (pre-tax) charge for the early retirement programs. The increase was also due to higher emergency and winter storm repairs and the accrual of additional payroll expense under an expanded employee incentive compensation program designed to tie pay increases more closely to business results and enhance productivity.
Depreciation and amortization
The increase in depreciation and amortization expense was due primarily to additions to plant in service and adjustments for TMI-2 decommissioning.
Taxes, other than income taxes
1995 and 1994 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
1995 and 1994 In the third quarter of 1995, the Company reversed $127.6 million (pre- tax) of certain future TMI-2 retirement costs written off in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 PaPUC order allowing the Company to recover its share of such costs from customers.
Metropolitan Edison Company and Subsidiary Companies
Also, in 1994 the Company recorded interest income of $29.8 million (pre- tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
INTEREST CHARGES AND PREFERRED DIVIDENDS: Other interest
1995 and 1994 In 1994, the Company recognized interest expense related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $7 million (pre-tax) charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Dividends on company-obligated mandatorily redeemable preferred securities
1995 and 1994 In 1994, through a special-purpose partnership, the Company issued $100 million stated value of mandatorily redeemable preferred securities.
Preferred stock dividends
1995 and 1994 In 1994 and 1993, the Company redeemed $35 million and $81 million stated value of preferred stock, respectively.
LIQUIDITY AND CAPITAL RESOURCES Capital Needs:
The Company's capital needs were $154 million in 1995, consisting of cash construction expenditures of $113 million and amounts for maturing obligations of $41 million.
During 1995, construction expenditures were used primarily to maintain and improve existing generation, transmission and distribution facilities, and for various clean air compliance projects. In 1996, construction expenditures for the Company are estimated to be $97 million, consisting primarily of ongoing system development. Expenditures for maturing obligations will total $15 million in 1996, and $40 million in 1997. In the late 1990s, construction expenditures are expected to include substantial amounts for additional clean air requirements and other Company needs. Management estimates that a significant portion of the Company's 1996 capital needs will be satisfied through internally generated funds.
Cash Construction Expenditures (In millions of dollars) 1991 1992 1993 1994 1995 1996 $122 $131 $142 $160 $113 $ 97*
* Estimate
Metropolitan Edison Company and Subsidiary Companies
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. The Company's share of the TMI-1 nuclear fuel capital lease at December 31, 1995 was $43 million. In 1995, the Company and its affiliates refinanced the TMI-1 nuclear fuel lease to provide for aggregate borrowings of up to $110 million outstanding at any one time. The nuclear fuel lease has an initial term of three years expiring in November 1998, and is renewable annually thereafter at the lender's option for a period up to 20 years. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of $13 million annually. In the event the needed nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
Financing:
In 1995, GPU sold five million shares of common stock. The net proceeds of $157.5 million were used to make cash capital contributions to the GPU System, of which the Company's share was $25 million, and to repay GPU short- term debt.
The Company has regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock through December 1997. Under existing authorizations, the Company may issue these senior securities in the amount of up to $190 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
In 1995, the Company issued $89 million principal amount of FMBs. The proceeds from these issuances were used to refinance $29 million principal amount of maturing higher cost FMBs, to redeem at maturity $12 million principal amount of FMBs, to moderate short-term debt levels and to fund growth in capitalization.
The Company's FMB indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Company may issue. The Company's interest and preferred dividend coverage ratios are currently in excess of indenture and charter restrictions.
The Company's cost of capital and ability to obtain external financing are affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. The Company's senior securities ratings have remained constant since August 1994. The Company's FMBs are currently rated at an equivalent of BBB+ or higher by the three major credit rating agencies, while the preferred stock and mandatorily redeemable preferred securities issues have been assigned an equivalent of BBB or higher. In addition, the Company's commercial paper is rated as having good to very good credit quality.
In October 1995, the Standard & Poor's (S&P) rating outlook (which is used to assess the potential direction of an issuer's long-term debt rating over the intermediate to longer-term) for Met-Ed was revised to "positive" from "stable". According to S&P, this outlook reflects expectations of modest
Metropolitan Edison Company and Subsidiary Companies
financial improvement based on gradual economic growth, the successful buyout of some expensive NUG contracts, and continued strong nuclear operations. It also reflects the Pennsylvania Supreme Court's reversal of a lower court order that had disallowed recovery of certain future TMI-2 retirement costs. The S&P business position assigned to the Company remained unchanged throughout the year at "low average". The business position is a financial benchmarking standard for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry.
Present plans call for the Company to issue long-term debt during the next three years to finance construction activities, fund the redemption of maturing senior securities, and depending on interest rates, refinance outstanding senior securities.
Capitalization:
The Company's target capitalization ratios are designed to provide credit quality ratings that permit capital market access at reasonable costs. The targets and actual capitalization ratios are as follows:
Target Range 1995 1994 1993 Common equity 46-49% 47% 46% 48% Preferred equity 8-10 9 10 5 Notes payable and long-term debt 46-41 44 44 47 100% 100% 100% 100%
Metropolitan Edison Company and Subsidiary Companies
The following remaining sections of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS are being presented on a combined basis, and are included in the GPU section of this Form 10-K.
COMPETITIVE ENVIRONMENT: See GPU page.
Recent Regulatory Actions: See GPU page.
Managing the Transition: See GPU page.
Nonutility Generation Agreements: See GPU page.
THE GPU SUPPLY PLAN: See GPU page.
New Energy Supplies: See GPU page.
Managing Nonutility Generation: See GPU page.
ENVIRONMENTAL ISSUES: See GPU page.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS: See GPU page.
EFFECTS OF INFLATION: See GPU page.
Metropolitan Edison Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1995 1994* 1995 1994**
Operating revenues $205,749 213,159 $190,342 $196,674
Operating income 31,155 39,914 28,335 8,808
Net income 16,384 37,802 12,617 (75,109)
Earnings available for common stock 16,148 36,894 12,381 (76,017)
In Thousands
Third Quarter Fourth Quarter
1995*** 1994 1995 1994
Operating revenues $241,664 $204,903 $216,919 $186,567
Operating income 35,121 32,258 37,194 30,516
Net income 97,391 20,453 22,148 17,585
Earnings available for common stock 97,155 19,545 21,912 17,349
* Results for the first quarter of 1994 reflect an increase in earnings of $13.0 million (after-tax) resulting from net interest income on refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter of 1994 reflect the write-off of $72.8 million (after-tax) of certain future TMI-2 retirement costs; and charges of $20.1 million (after-tax) for costs related to early retirement programs.
*** Results for the third quarter of 1995 reflect the reversal of $72.8 million (after-tax) of certain future TMI-2 retirement costs written off in the second quarter of 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 lower court order, and restored a 1993 PaPUC order allowing for the recovery of such costs. Partially offsetting this increase was a charge to income of $5.7 million (after-tax) of TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
Metropolitan Edison Company and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors Metropolitan Edison Company Reading, Pennsylvania
We have audited the consolidated financial statements and financial statement schedule of Metropolitan Edison Company and Subsidiary Companies as listed in the index on page of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. These 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 Metropolitan Edison Company and Subsidiary Companies as of December 31, 1995 and 1994 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
New York, New York January 31, 1996
Metropolitan Edison Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Metropolitan Edison Company (the Company), a Pennsylvania corporation, incorporated in 1922, is a wholly-owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company's business is the generation, transmission, distribution and sale of electricity. The Company owns all of the common stock of York Haven Power Company, the owner of a small hydroelectric generating station, and Met-Ed Preferred Capital, Inc., which is the sole general partner of Met-Ed Capital, L.P., a special-purpose partnership. The Company is affiliated with Jersey Central Power & Light Company (JCP&L) and Pennsylvania Electric Company (Penelec). The Company, JCP&L and Penelec are referred to herein as the "Company and its affiliates." The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and Energy Initiatives, Inc., EI Power, Inc., and EI Energy Inc. (collectively, the "EI Group"), which develop, own and operate generation, transmission and distribution facilities in the United States and foreign countries. All of the Company's affiliates are wholly-owned subsidiaries of GPU. The Company and its affiliates, as well as GPUSC, GPUN and the EI Group, are referred to herein as the "GPU System."
Note 1, "Commitments and Contingencies," and Note 2, "Summary of Significant Accounting Policies," are being presented for GPU, the Company and its affiliates on a combined basis and are included in the GPU section of this Form 10-K.
Note 1 - Commitments and Contingencies: See GPU page.
Nuclear Facilities: See GPU page.
Nuclear Plant Retirement Costs: See GPU page.
Insurance: See GPU page.
Competition and the Changing Regulatory Environment: See GPU page.
Environmental Matters: See GPU page.
Other Commitments and Contingencies: See GPU page.
Note 2 - Summary of Significant Accounting Policies: See GPU page.
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1995, the Company had $22 million of short-term notes outstanding which was issued under bank lines of credit (credit facilities). The Company's weighted average interest rate on short-term borrowings was 5.6% at December 31, 1995. The Company had no short-term notes outstanding at December 31, 1994.
Metropolitan Edison Company and Subsidiary Companies
GPU and the Company and its affiliates have $529 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total borrowings outstanding at any time and subject to various covenants and acceleration under certain conditions. The Credit Agreement borrowing rates and facility fee are dependent on the long-term debt ratings of the Company and its affiliates.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of December 31, 1995 and 1994, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1995: Company-obligated mandatorily redeemable preferred securities $100 $106 Long-term debt 603 645
December 31, 1994: Company-obligated mandatorily redeemable preferred securities $100 $ 98 Long-term debt 530 485
The fair values of the Company's financial instruments are estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments of the same remaining maturities and credit qualities.
5. INCOME TAXES
Effective January 1, 1993, the Company implemented FAS 109, "Accounting for Income Taxes." The cumulative effect of this accounting change on net income was immaterial. As of December 31, 1995 and 1994, the balance sheet reflected $179 million and $202 million, respectively, of income taxes recoverable through future rates (primarily related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $25 million and $30 million, respectively (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, 1995 and 1994 is as follows:
Metropolitan Edison Company and Subsidiary Companies
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities 1995 1994 1995 1994 Noncurrent: Current: Liberalized Unbilled revenue $ 6 $ 3 depreciation: Other 2 2 previously flowed Total $ 8 $ 5 through $100 $116 future revenue Noncurrent: requirements 76 86 Unamortized ITC $25 $ 30 Decommissioning 23 71 Subtotal 176 202 Contribution in aid Liberalized of construction 2 2 depreciation 182 163 Other 41 47 Other 22 7 Total $91 $150 Total $380 $372
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) 1995 1994 1993
Net income $149 $ 1 $ 78 Income tax expense 92 (9) 47 Book income subject to tax $241 $ (8) $125
Federal statutory rate 35% 35% 35% State tax, net of federal benefit 6 32 6 Amortization of ITC (1) 22 (2) Other (2) 20 (1) Effective income tax rate 38% 109% 38%
Federal and state income tax expense is comprised of the following:
(In Millions) 1995 1994 1993 Provisions for taxes currently payable $23 $ 45 $35
Deferred income taxes: Liberalized depreciation 10 6 8 Deferral of energy costs - 6 4 Decommissioning 46 (52) - VERP 8 (15) - Unbilled revenue (4) 2 - NUG buyout costs 8 - - Other 3 2 3 Deferred income taxes, net 71 (51) 15 Amortization of ITC, net (2) (3) (3) Income tax expense $92 $ (9) $47
Metropolitan Edison Company and Subsidiary Companies
In 1994, the GPU System and the Internal Revenue Service (IRS) reached an agreement to settle the claim for 1986 that TMI-2 has been retired for tax purposes. The Company and its affiliates have received net refunds totaling $17 million, of which the Company's share is $9 million, which have been credited to their customers. Also in 1994, the GPU System received net interest from the IRS totaling $46 million, of which the Company's share is $23 million (before income taxes), associated with the refund settlement, which was credited to income. The IRS has completed its examinations of the GPU System's federal income tax returns through 1989. The years 1990 through 1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following: (In Millions) 1995 1994 1993 Maintenance $54 $59 $59 Other taxes: Pennsylvania state gross receipts $35 $32 $32 Real estate and personal property 7 6 7 Capital stock 7 7 8 Other 6 7 6 Total $55 $52 $53
For the years 1995, 1994 and 1993, the cost to the Company of services rendered to it by GPUSC amounted to approximately $27 million, $27 million and $23 million, respectively, of which approximately $23 million, $22 million and $19 million, respectively, were charged to income. For the years 1995, 1994, and 1993, the cost to the Company of services rendered to it by GPUN amounted to approximately $81 million, $77 million and $88 million, respectively, of which approximately $69 million, $65 million and $74 million, respectively, were charged to income.
7. EMPLOYEE BENEFITS
Pension Plans:
The Company maintains defined benefit pension plans covering substantially all employees. The Company's policy is to currently fund net pension costs within the deduction limits permitted by the Internal Revenue Code.
A summary of the components of net periodic pension cost follows:
Metropolitan Edison Company and Subsidiary Companies
(In Millions) 1995 1994 1993 Service cost-benefits earned during the period $ 4.4 $ 4.7 $ 4.9 Interest cost on projected benefit obligation 20.2 17.7 18.8 Less: Expected return on plan assets (20.3) (19.1) (19.3) Amortization (0.1) (0.3) (0.3) Net periodic pension cost $ 4.2 $ 3.0 $ 4.1
The above 1994 amounts do not include a pre-tax charge to earnings of $26 million resulting from the Voluntary Enhanced Retirement Programs (VERP).
The actual return on the plans' assets for the years 1995, 1994 and 1993 were gains of $59.4 million, $2.5 million and $29.2 million, respectively.
The funded status of the plans and related assumptions at December 31, 1995 and 1994 were as follows:
(In Millions) 1995 1994 Accumulated benefit obligation (ABO): Vested benefits $ 220.9 $ 212.4 Nonvested benefits 24.0 19.7 Total ABO 244.9 232.1 Effect of future compensation levels 42.4 30.9 Projected benefit obligation (PBO) $ 287.3 $ 263.0
Plan assets at fair value $ 293.1 $ 234.6 PBO (287.3) (263.0) Plan assets in excess of (less than) PBO 5.8 (28.4) Less: Unrecognized net (gain) loss (7.6) 15.9 Unrecognized prior service cost 3.5 2.3 Unrecognized net transition asset (1.3) (1.4) Prepaid (accrued) pension cost $ 0.4 $ (11.6)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0 Annual increase in compensation levels 5.5 6.0
In 1995, changes in assumptions, primarily the decrease in the discount rate assumption from 8% to 7.5%, resulted in a $12 million increase in the PBO as of December 31, 1995. The assets of the plans are held in a Master Trust and generally invested in common stocks and fixed income securities. The unrecognized net (gain) loss 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
Metropolitan Edison Company and Subsidiary Companies
Accounting Standards No. 87, "Employers' Accounting for Pensions," are being amortized to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1995, 1994 and 1993 were $2.7 million, $2.2 million and $1.8 million, respectively.
Postretirement Benefits Other Than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years. The unrecognized net loss represents actual experience different from that assumed, which is deferred and not included in the determination of postretirement benefit cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits is being amortized to postretirement benefit cost over the average remaining service periods for covered employees.
A summary of the components of the net periodic postretirement benefit cost for 1995, 1994 and 1993 follows:
(In Millions) 1995 1994 1993 Service cost-benefits attributed to service during the period $ 2.0 $ 2.3 $ 2.2 Interest cost on the accumulated postretirement benefit obligation 8.3 7.1 7.4 Expected return on plan assets (1.4) (1.2) (0.7) Amortization of transition obligation 3.4 3.4 3.9 Other amortization, net 0.3 0.5 - Net periodic postretirement benefit cost 12.6 12.1 12.8 Less, deferred for future recovery (5.6) (8.3) (7.8) Postretirement benefit cost, net of deferrals $ 7.0 $ 3.8 $ 5.0
The above 1994 amounts do not include a pre-tax charge to earnings of $9 million relating to the VERP. The amount deferred for future recovery does not include $1.8 million of allocated postretirement benefit costs from the Company's affiliates for 1995.
Metropolitan Edison Company and Subsidiary Companies
The actual return on the plans' assets for the years 1995, 1994 and 1993 was a gain of $3.3 million, $0.4 million and $0.7 million, respectively.
The funded status of the plans at December 31, 1995 and 1994, was as follows:
(In Millions) 1995 1994 Accumulated Postretirement Benefit Obligation: Retirees $ 80.2 $ 65.0 Fully eligible active plan participants 3.5 11.3 Other active plan participants 39.2 30.9 Total accumulated postretirement benefit obligation (APBO) $ 122.9 $ 107.2
APBO $(122.9) $(107.2) Plan assets at fair value 21.9 14.1 APBO in excess of plan assets (101.0) ( 93.1) Less: Unrecognized net loss 17.7 11.7 Unrecognized transition obligation 57.4 59.6 Accrued postretirement benefit liability $ (25.9) $ (21.8)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0
The Company intends to continue funding amounts for postretirement benefits with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
In 1995, the decrease in the health-care cost trend rate assumptions resulted in a $9 million decrease in the APBO, which was partially offset by an increase of $8 million in the APBO caused by the decrease in the discount rate assumption from 8% to 7.5%. 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 12% for those not eligible for Medicare and 9% for those eligible for Medicare, then decreasing gradually to 6% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995 and reach age 65. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $12 million as of December 31, 1995 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $1 million.
The Company is deferring the incremental postretirement benefit costs, charged to expense, associated with the adoption of FAS 106 and in accordance with Emerging Issues Task Force Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," as authorized by the PaPUC in its 1993 base rate order.
Metropolitan Edison Company and Subsidiary Companies
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the investment and charges its share of operating expenses to the appropriate expense accounts. The Company participated with affiliated and nonaffiliated utilities in the following jointly owned stations at December 31, 1995:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation
Conemaugh 16.45 $144.3 $ 34.3 Three Mile Island Unit 1 50 425.8 150.5
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1995 and 1994 totaled $43 million and $33 million, respectively (net of amortization of $41 million and $29 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. In 1995, the Company and its affiliates refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. Reductions in nuclear fuel financing costs are expected through the new credit facilities. It is contemplated that when consumed, portions of the presently leased material will be replaced by additional leased material. The Company and its affiliates are responsible for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment. 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, 1995, 1994 and 1993, these amounts were $15 million, $15 million and $25 million, respectively.
The Company has sold and leased back substantially all of its ownership interest in the Merrill Creek Reservoir Project. The minimum lease payments under this operating lease, which has a remaining term of 37 years, average approximately $3 million annually.
Pennsylvania Electric Company and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS The Company's 1995 earnings were $109.5 million, compared to 1994 earnings of $28.9 million. The increase in earnings was primarily due to the net effect of several 1995 and 1994 nonrecurring items. The Company's return on average common equity was 15.8% in 1995 compared to 4.2% in 1994.
Excluding these nonrecurring items, earnings for 1995 would have been $80.1 million, compared to 1994 earnings of $90.7 million. Return on average common equity for 1995 and 1994, on this basis, would have been 11.8% and 12.5%, respectively. Contributing to this earnings decrease were higher other operation and maintenance (O&M) expenses and increased financing expenses.
The 1995 nonrecurring items consisted of a reversal of $32.1 million (after-tax) of certain future Three Mile Island Unit 2 (TMI-2) retirement costs written off in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 Pennsylvania Public Utility Commission (PaPUC) order allowing an affiliate (Met-Ed) to recover its share of such costs from customers. Partially offsetting this increase was a $2.7 million (after-tax) charge to income for the Company's share of TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
The 1994 nonrecurring items included the above mentioned TMI-2 write-off of $32.1 million (after-tax). Also in 1994, there was a charge to income of $25.6 million (after-tax) for early retirement program costs; a write-off of $10.6 million (after-tax) for certain postretirement benefit (OPEB) costs; and net interest income of $6.5 million (after-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
Earnings in 1994 were $28.9 million, compared to earnings in 1993 of $90.7 million. This earnings reduction was attributable to the 1994 nonrecurring items mentioned above and increased other O&M expenses. Also, in 1993 there was a write-off of $4.4 million (after-tax) for the cancellation of proposed power supply and transmission facilities agreements.
OPERATING REVENUES: Operating revenues increased 3.9% to $981.3 million in 1995 after increasing 4.0% to $944.7 million in 1994. The components of these changes are as follows:
Pennsylvania Electric Company and Subsidiary Companies
(In Millions) 1995 1994
Kilowatt-hour (KWH) revenues (excluding energy portion) $ 1.7 $ 1.6 Energy revenues 32.3 39.7 Other revenues 2.6 (4.9) Increase in revenues $ 36.6 $ 36.4
Kilowatt-hour revenues
The increase in KWH revenues was due to increases in new commercial and residential customer sales.
The increase in KWH revenues was due principally to increases in new commercial and wholesale customer sales, and higher usage by wholesale customers. In 1993, the Company successfully negotiated power supply agreements at lower rates with some wholesale customers previously served by the Company's affiliates. This was in response to offers made by other utilities seeking to provide electric service to these customers. These increases were mostly offset by decreased industrial customer usage and decreased capacity sales to affiliated companies.
1995 MWH Customer Sales by Service Class
Residential 29% Commercial 30% Industrial 34% Other 7%
Energy revenues
1995 and 1994 Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues in 1995 increased from additional sales to other utilities and higher energy cost rates. The 1994 increase was due primarily to higher energy cost rates and the reclassification in 1993 of certain transmission service revenues.
Other revenues
1995 and 1994 Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes.
Pennsylvania Electric Company and Subsidiary Companies
OPERATING EXPENSES: Power purchased and interchanged
1995 and 1994 Generally, changes in the energy component of power purchased and interchanged (PP&I) expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy adjustment clause. The increase in PP&I expense was due largely to higher nonutility generation purchases.
Fuel and Deferral of energy costs, net
1995 and 1994 Generally, changes in fuel expense and deferral of energy costs do not affect earnings as they are offset by corresponding changes in energy revenues.
Other operation and maintenance
The decrease in other O&M expense was due to a $44.9 million (pre-tax) charge in 1994 related to the early retirement programs. Partially offsetting this decrease were a 1995 write-off of $4.7 million (pre-tax) for TMI-2 monitored storage costs deemed not probable of recovery through ratemaking and severance payments in 1995 resulting from the management combination of the Company and Met-Ed.
The increase in other O&M expense was due primarily to a $44.9 million (pre-tax) charge for the early retirement programs. The increase was also due to higher emergency and winter storm repairs and the accrual of additional payroll expense under an expanded employee incentive compensation program designed to tie pay increases more closely to business results and enhance productivity.
Depreciation and amortization
The increase in depreciation and amortization expense was due primarily to additions to plant in service.
The decrease in depreciation and amortization expense was due largely to lower TMI-2 amortization and the recognition in 1993 of TMI-2 nonradiological retirement costs. The lower TMI-2 amortization was attributable to the Company completing, in 1993, its recovery of the TMI-2 investment from retail customers.
Pennsylvania Electric Company and Subsidiary Companies
Taxes, other than income taxes
1995 and 1994 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
1995 and 1994 In the third quarter of 1995, the Company reversed $56.3 million (pre- tax) of certain future TMI-2 retirement costs written off in 1994. The reversal of this write-off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 Pennsylvania Commonwealth Court order, and restored a 1993 PaPUC order allowing Met-Ed to recover its share of such costs from customers.
In 1994, the Company expensed $18.6 million (pre-tax) for certain OPEB costs believed not probable of recovery in rates. Of this amount, $14.6 million was written off as a result of a PaPUC order disallowing a nonaffiliated utility to collect such costs, and $4 million was charged to expense for OPEB costs related to employees who participated in the early retirement programs. Also, the Company recorded interest income of $14.9 million (pre-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
INTEREST CHARGES AND PREFERRED DIVIDENDS: Other interest
1995 and 1994 In 1994, the Company recognized interest expense related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $3.5 million (pre-tax) charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken. Also contributing to the 1995 increase were higher average short-term debt levels and increased interest rates.
Dividends on company-obligated mandatorily redeemable preferred securities
1995 and 1994 In 1994, through a special-purpose partnership, the Company issued $105 million stated value of mandatorily redeemable preferred securities.
Preferred stock dividends
1995 and 1994 In 1994 and 1993, the Company redeemed in each year $25 million stated value of preferred stock.
Pennsylvania Electric Company and Subsidiary Companies
LIQUIDITY AND CAPITAL RESOURCES Capital Needs:
The Company's capital needs were $131 million in 1995, consisting of cash construction expenditures. During 1995, construction expenditures were used primarily to maintain and improve existing generation, transmission and distribution facilities, and for various clean air compliance projects. In 1996, construction expenditures for the Company are estimated to be $124 million, consisting primarily of $117 million for ongoing system development. Expenditures for maturing obligations will total $75 million in 1996, and $26 million in 1997. In the late 1990s, construction expenditures are expected to include substantial amounts for additional clean air requirements and other Company needs. Management estimates that approximately three-fourths of the Company's 1996 capital needs will be satisfied through internally generated funds.
Cash Construction Expenditures (In millions of dollars) 1991 1992 1993 1994 1995 1996 $101 $111 $150 $174 $131 $124*
* Estimate
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. The Company's share of the TMI-1 nuclear fuel capital lease at December 31, 1995 was $21 million. In 1995, the Company and its affiliates refinanced the TMI-1 nuclear fuel lease to provide for aggregate borrowings of up to $110 million outstanding at any one time. The nuclear fuel lease has an initial term of three years expiring in November 1998, and is renewable annually thereafter at the lender's option for a period up to 20 years. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of $7 million annually. In the event the needed nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
Financing:
In 1995, GPU sold five million shares of common stock. The net proceeds of $157.5 million were used to make cash capital contributions to the GPU System, of which the Company's share was $20 million, and to repay GPU short- term debt.
The Company has regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock through June 1997. Under existing authorizations, the Company may issue these senior securities in the amount of up to $160 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
In 1995, the Company issued $199 million principal amount of FMBs. The proceeds from these issuances were used to refinance $99 million principal
Pennsylvania Electric Company and Subsidiary Companies
amount of higher cost FMBs, to moderate short-term debt levels and to fund growth in capitalization.
The Company's FMB indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Company may issue. The Company's interest and preferred dividend coverage ratios are currently in excess of indenture and charter restrictions.
The Company's cost of capital and ability to obtain external financing are affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. The Company's senior securities ratings have remained constant since August 1994. The Company's FMBs are currently rated at an equivalent A- or higher by the three major credit rating agencies, while the preferred stock and mandatorily redeemable preferred securities issues have been assigned an equivalent of BBB+ or higher. In addition, the Company's commercial paper is rated as having good to high credit quality.
The Standard & Poor's (S&P) rating outlook for the Company has remained at "stable" and reflects a manageable construction program, minimal rate relief requirements and expectations of modest strengthening in the service area economy. The rating outlook is used to assess the potential direction of an issuer's long-term debt rating over the intermediate to longer-term. The S&P business position assigned to the Company remained unchanged throughout the year at "average". The business position is a financial benchmarking standard for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry.
Present plans call for the Company to issue long-term debt during the next three years to finance construction activities, fund the redemption of maturing senior securities, and depending on interest rates, refinance outstanding senior securities.
Capitalization:
The Company's target capitalization ratios are designed to provide credit quality ratings that permit capital market access at reasonable costs. The targets and actual capitalization ratios are as follows:
Target Range 1995 1994 1993 Common equity 45-48% 45% 43% 48% Preferred equity 8-10 9 9 4 Notes payable and long-term debt 47-42 46 48 48 100% 100% 100% 100%
Pennsylvania Electric Company and Subsidiary Companies
The following remaining sections of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS are being presented on a combined basis, and are included in the GPU section of this Form 10-K.
COMPETITIVE ENVIRONMENT: See GPU page.
Recent Regulatory Actions: See GPU page.
Managing the Transition: See GPU page.
Nonutility Generation Agreements: See GPU page.
THE GPU SUPPLY PLAN See GPU page.
New Energy Supplies: See GPU page.
Managing Nonutility Generation: See GPU page.
ENVIRONMENTAL ISSUES See GPU page.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS See GPU page.
EFFECTS OF INFLATION See GPU page.
Pennsylvania Electric Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1995 1994* 1995 1994**
Operating revenues $253,412 $247,180 $238,451 $227,122
Operating income 46,110 46,017 37,218 8,749
Net income 30,566 38,965 20,276 (46,671)
Earnings available for common stock 30,180 38,057 19,890 (47,580)
In Thousands
Third Quarter Fourth Quarter
1995*** 1994 1995 1994
Operating revenues $249,234 $240,267 $240,232 $230,175
Operating income 30,911 38,238 27,822 33,228
Net income 50,015 24,351 10,153 15,154
Earnings available for common stock 49,629 23,617 9,767 14,768
* Results for the first quarter of 1994 reflect an increase in earnings of $6.5 million (after-tax) resulting from net interest income on refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter of 1994 reflect the write-off of $32.1 million (after-tax) of certain future TMI-2 retirement costs; charges of $25.6 million (after-tax) for costs related to early retirement programs; and a write-off $10.6 million (after-tax) for postretirement benefit costs believed not probable of recovery in rates.
*** Results for the third quarter of 1995 reflect the reversal of $32.1 million (after-tax) of certain future TMI-2 retirement costs written off in the second quarter of 1994. The reversal of this write- off resulted from a 1995 Pennsylvania Supreme Court decision that overturned a 1994 lower court order, and restored a 1993 PaPUC order allowing for the recovery of such costs. Partially offsetting this increase was a charge to income of $2.7 million (after-tax) of TMI-2 monitored storage costs deemed not probable of recovery through ratemaking.
Pennsylvania Electric Company and Subsidiary Companies
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors Pennsylvania Electric Company Reading, Pennsylvania
We have audited the consolidated financial statements and financial statement schedule of Pennsylvania Electric Company and Subsidiary Companies as listed in the index on page of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. These 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 Pennsylvania Electric Company and Subsidiary Companies as of December 31, 1995 and 1994 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
New York, New York January 31, 1996
Pennsylvania Electric Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pennsylvania Electric Company (the Company), a Pennsylvania corporation incorporated in 1919, is a wholly-owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company's business is the generation, transmission, distribution and sale of electricity. The Company owns all of the common stock of Penelec Preferred Capital, Inc., which is the sole general partner of Penelec Capital, L.P., a special-purpose partnership. The Company also has two minor wholly-owned subsidiaries. The Company is affiliated with Jersey Central Power & Light Company (JCP&L) and Metropolitan Edison Company (Met-Ed). The Company, JCP&L and Met-Ed are referred to herein as the "Company and its affiliates." The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and Energy Initiatives, Inc., EI Power, Inc., and EI Energy, Inc. (collectively, the "EI Group"), which develop, own and operate generation, transmission and distribution facilities in the United States and foreign countries. All of the Company's affiliates are wholly-owned subsidiaries of GPU. The Company and its affiliates are referred to herein as the "GPU System."
Note 1, "Commitments and Contingencies," and Note 2, "Summary of Significant Accounting Policies," are being presented for GPU, the Company and its affiliates on a combined basis and are included in the GPU section of this Form 10-K.
Note 1 - Commitments and Contingencies: See GPU page.
Nuclear Facilities: See GPU page.
Nuclear Plant Retirement Costs: See GPU page.
Insurance: See GPU page.
Competition and the Changing Regulatory Environment: See GPU page.
Environmental Matters: See GPU page.
Other Commitments and Contingencies: See GPU page.
Note 2 - Summary of Significant Accounting Policies: See GPU page.
Pennsylvania Electric Company and Subsidiary Companies
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1995 and 1994, the Company had $27 million and $111 million of short-term notes outstanding, respectively, of which $27 million in 1994 was commerical paper and the remainder was issued under bank lines of credit (credit facilities). The Company's weighted average interest rate on short- term borrowings was 5.9% and 6.2% at December 31, 1995 and 1994, respectively.
GPU and the Company and its affiliates have $529 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks. 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 November 1, 1999, are limited to $250 million in total borrowings outstanding at any time and subject to various covenants and acceleration under certain conditions. The Credit Agreement borrowing rates and facility fee are dependent on the long-term debt ratings of the Company and its affiliates.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of December 31, 1995 and 1994, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1995: Company-obligated mandatorily redeemable preferred securities $ 105 $ 110 Long-term debt 642 678
December 31, 1994: Company-obligated mandatorily redeemable preferred securities $ 105 $ 101 Long-term debt 616 577
The fair values of the Company's financial instruments are estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments of the same remaining maturities and credit qualities.
5. INCOME TAXES
Effective January 1, 1993, the Company implemented FAS 109, "Accounting for Income Taxes." The cumulative effect of this accounting change on net income was immaterial. As of December 31, 1995 and 1994, the balance sheet reflected $214 million and $228 million, respectively, of income taxes recoverable through future rates (primarily related to liberalized depreciation), and a regulatory liability for income taxes refundable through
Pennsylvania Electric Company and Subsidiary Companies
future rates of $34 million and $36 million, respectively (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, 1995 and 1994 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1995 1994 1995 1994 Current: Current: Unbilled revenue $ 5 $ 3 Deferred energy $ 4 $ 4 Total $ 5 $ 3 Total $ 4 $ 4
Noncurrent: Noncurrent: Unamortized ITC $34 $ 36 Liberalized Decommissioning 13 35 depreciation: Contribution in aid previously flowed of construction 3 3 through $121 $131 Other 29 40 future revenue Total $79 $114 requirements 91 97 Subtotal 212 228 Liberalized depreciation 229 217 Other 21 9 Total $462 $454
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) 1995 1994 1993
Net income $111 $32 $ 96 Income tax expense 70 11 69 Book income subject to tax $181 $43 $165
Federal statutory rate 35% 35% 35% State tax, net of federal benefit 6 1 7 Other ( 2) (10) - Effective income tax rate 39% 26% 42%
Pennsylvania Electric Company and Subsidiary Companies
Federal and state income tax expense is comprised of the following:
(In Millions) 1995 1994 1993 Provisions for taxes currently payable $28 $ 61 $51
Deferred income taxes: Liberalized depreciation 12 12 8 Deferral of energy costs - (3) 11 Accretion income - 5 - Decommissioning 21 (24) - VERP 13 (21) - Other (1) (15) 3 Deferred income taxes, net 45 (46) 22 Amortization of ITC, net (3) (4) (4) Income tax expense $70 $ 11 $69
In 1994, the GPU System and the Internal Revenue Service (IRS) reached an agreement to settle the claim for 1986 that TMI-2 has been retired for tax purposes. The Company and its affiliates have received net refunds totaling $17 million, of which the Company's share is $4 million, which have been credited to their customers. Also in 1994, the GPU System received net interest from the IRS totaling $46 million, of which the Company's share is $11.5 million (before income taxes), associated with the refund settlement, which was credited to income. The IRS has completed its examinations of the GPU System's federal income tax returns through 1989. The years 1990 through 1992 are currently being audited.
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following: (In Millions) 1995 1994 1993
Maintenance $71 $80 $81 Other taxes: Pennsylvania state gross receipts $39 $38 $36 Real estate and personal property 8 8 8 Capital stock 9 9 9 Other 11 11 9 Total $67 $66 $62
For the years 1995, 1994 and 1993, the cost to the Company of services rendered to it by GPUSC amounted to approximately $38 million, $40 million and $37 million, respectively, of which approximately $31 million, $31 million and $25 million, respectively, were charged to income. For the years 1995, 1994
Pennsylvania Electric Company and Subsidiary Companies
and 1993, the cost to the Company of services rendered to it by GPUN amounted to approximately $41 million, $40 million and $46 million, respectively, of which approximately $36 million, $33 million and $38 million, respectively, were charged to income.
7. EMPLOYEE BENEFITS
Pension Plans:
The Company maintains defined benefit pension plans covering substantially all employees. The Company's policy is to currently fund net pension costs within the deduction limits permitted by the Internal Revenue Code.
A summary of the components of net periodic pension cost follows:
(In Millions) 1995 1994 1993 Service cost-benefits earned during the period $ 8.9 $ 10.2 $ 8.0 Interest cost on projected benefit obligation 34.9 30.6 29.9 Less: Expected return on plan assets (35.6) (32.4) (30.4) Amortization 0.3 0.5 0.1 Net periodic pension cost $ 8.5 $ 8.9 $ 7.6
The above 1994 amounts do not include a pre-tax charge to earnings of $33 million resulting from the Voluntary Enhanced Retirement Programs (VERP).
The actual return on the plans' assets for the years 1995, 1994 and 1993 were gains of $100.3 million, $4.2 million and $46.1 million, respectively.
The funded status of the plans and related assumptions at December 31, 1995 and 1994 were as follows:
(In Millions) 1995 1994 Accumulated benefit obligation (ABO): Vested benefits $ 364.4 $ 358.0 Nonvested benefits 44.1 38.6 Total ABO 408.5 396.6 Effect of future compensation levels 73.3 57.0 Projected benefit obligation (PBO) $ 481.8 $ 453.6
Plan assets at fair value $ 496.8 $ 401.3 PBO (481.8) (453.6) Plan assets in excess of (less than) PBO 15.0 (52.3) Less: Unrecognized net (gain) loss (18.8) 27.3 Unrecognized prior service cost 3.8 1.8 Unrecognized net transition obligation 3.0 3.5 Prepaid (accrued) pension cost $ 3.0 $ (19.7)
Pennsylvania Electric Company and Subsidiary Companies
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0 Annual increase in compensation levels 5.5 6.0
In 1995, changes in assumptions, primarily the decrease in the discount rate assumption from 8% to 7.5%, resulted in a $20 million increase in the PBO as of December 31, 1995. The assets of the plans are held in a Master Trust and generally invested in common stocks and fixed income securities. The unrecognized net (gain) loss 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 obligation arising out of the adoption of Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions," are being amortized to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1995, 1994 and 1993 were $2.5 million, $3.0 million and $3.0 million, respectively.
Postretirement Benefits Other Than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years. The unrecognized net loss represents actual experience different from that assumed, which is deferred and not included in the determination of postretirement benefit cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits is being amortized to postretirement benefit cost over the average remaining service periods for covered employees.
A summary of the components of the net periodic postretirement benefit cost for 1995, 1994 and 1993 follows:
Pennsylvania Electric Company and Subsidiary Companies
(In Millions) 1995 1994 1993 Service cost-benefits attributed to service during the period $ 4.3 $ 4.6 $ 3.6 Interest cost on the accumulated postretirement benefit obligation 15.6 13.4 12.2 Expected return on plan assets (4.3) (2.3) (1.2) Amortization of transition obligation 6.2 6.5 6.5 Other amortization, net 0.5 0.8 - Net periodic postretirement benefit cost 22.3 23.0 21.1 Net write-off (deferral) 1.3 9.0 (10.1) Postretirement benefit cost, net of deferrals $ 23.6 $ 32.0 $ 11.0
The above 1994 amounts do not include a pre-tax charge to earnings of $12 million relating to the VERP.
The actual return on the plans' assets for the years 1995, 1994 and 1993 was a gain of $11.1 million, $0.8 million and $1.3 million, respectively.
The funded status of the plans at December 31, 1995 and 1994, was as follows:
(In Millions) 1995 1994 Accumulated Postretirement Benefit Obligation: Retirees $ 139.7 $ 111.3 Fully eligible active plan participants 6.0 21.4 Other active plan participants 79.6 67.2 Total accumulated postretirement benefit obligation (APBO) $ 225.3 $ 199.9
APBO $(225.3) $(199.9) Plan assets at fair value 75.3 53.1 APBO in excess of plan assets (150.0) (146.8) Less: Unrecognized net loss 25.0 15.9 Unrecognized prior service cost 2.3 2.5 Unrecognized transition obligation 106.1 112.4 Accrued postretirement benefit liability $ (16.6) $ (16.0)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.0
The Company intends to continue funding amounts for postretirement benefits with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
In 1995, the decrease in the health-care cost trend rate assumptions resulted in an $18 million decrease in the APBO, which was partially offset by
Pennsylvania Electric Company and Subsidiary Companies
an increase of $15 million in the APBO caused by the decrease in the discount rate assumption from 8% to 7.5%. 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 12% for those not eligible for Medicare and 9% for those eligible for Medicare, then decreasing gradually to 6% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995 and reach age 65. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $23 million as of December 31, 1995 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $3 million.
In 1994, the Pennsylvania Commonwealth Court reversed a PaPUC order that allowed a nonaffiliated utility, outside a base rate proceeding, to defer certain incremental postretirement benefit costs for future recovery from customers. As a result of the Court's decision, in 1994, the Company determined that its FAS 106 costs, including costs deferred since January 1993, were not likely to be recovered and charged $18.8 million to expense. In addition, $4 million of the Company's unrecognized transition obligation resulting from employees who elected to participate in the VERP was also written off in 1994. In 1995, the Company recorded a charge to income of approximately $9 million, which represents continued amortization of the transition obligation along with current accruals of FAS 106 expense for active employees.
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the investment and charges its share of operating expenses to the appropriate expense accounts. The Company participated with affiliated and nonaffiliated utilities in the following jointly owned stations at December 31, 1995:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation
Homer City 50 $458.2 $161.6 Three Mile Island Unit 1 25 213.3 78.3 Seneca 20 16.4 4.8
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1995 and 1994 totaled $21 million and $16 million, respectively (net of amortization of $21 million and $15 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
Pennsylvania Electric Company and Subsidiary Companies
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. In 1995, the Company and its affiliates refinanced the Oyster Creek and TMI-1 nuclear fuel leases to provide for aggregate borrowings of up to $210 million ($100 million for Oyster Creek and $110 million for TMI-1) outstanding at any one time. Reductions in nuclear fuel financing costs are expected through the new credit facilities. It is contemplated that when consumed, portions of the presently leased material will be replaced by additional leased material. The Company and its affiliates are responsible for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases have initial terms of three years expiring in November 1998, and are renewable annually thereafter at the lender's option for a period up to 20 years. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. These amounts were $7 million for each of the years ended December 31, 1995, 1994 and 1993.