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 GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and Energy Initiatives, Inc. (EI) and EI Power, Inc., which develop, own and operate nonutility generating facilities. Wholly owned subsidiaries of Met-Ed and Penelec are listed in Exhibit 21. The Subsidiaries own all of the common stock of the Saxton Nuclear Experimental Corporation (Saxton), which owns a small demonstration nuclear reactor that has been partially decommissioned. All of these companies 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, 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 (see Regulation).
INDUSTRY DEVELOPMENTS
The electric power markets have for more than the past fifty years generally been served by regulated monopolies. Over the last few years, however, market forces combined with state and federal, legislative and regulatory actions, have laid the foundation for the continued development of 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 of certain market segments. The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry of competitors into the electric generation business. Since then, more competition has been introduced through various state actions to encourage cogeneration and, more recently, the Energy Policy Act of 1992 (EPAct).
The EPAct is intended to promote competition among utility and nonutility generators in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. 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 several states.
The EPAct, coupled with increasing customer demands for lower-priced electricity, is generally expected to stimulate even greater competition in both the wholesale and retail electricity markets. These competitive pressures may create opportunities to compete for new customers and revenues, as well as increase risk which could lead to the loss of customers.
Operating in a competitive environment places new pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than 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, industrial customers have indicated their intention to pursue competitively priced electricity from other providers, and in some instances have leveraged price concessions from utilities. This prospect of increasing competition in the electric utility industry has already led the major credit rating agencies to address and apply more stringent guidelines in making credit rating determinations.
During 1994 and in early 1995, there have been a number of major federal and state initiatives in the area of competition within the electric utility industry:
- In June 1994, the FERC issued a Notice of Proposed Rulemaking regarding the recovery by utilities of legitimate and verifiable stranded costs. Costs incurred by a utility to provide integrated electric service to a franchise customer become stranded when that customer subsequently purchases power from another supplier using the utility's transmission services. Among other things, the FERC proposed that utilities be allowed under certain circumstances to recover such stranded costs associated with existing wholesale customer contracts, but not under new wholesale contracts unless expressly provided for in the contract. While it stated a "strong" policy preference that state regulatory agencies address recovery of stranded retail costs, the FERC also set forth alternative proposals for how it would address the matter if the states failed to do so. Subsequent to the FERC's Notice of Proposed Rulemaking, however, the U.S. Court of Appeals for the District of Columbia, in an unrelated case, questioned whether permitting stranded cost recovery was so inherently anticompetitive that it violates antitrust laws. While largely supported by the electric utility industry, the Proposed Rulemaking has been strongly opposed by other groups.
- In October 1994, the FERC issued a policy statement regarding pricing for electric transmission services. The policy statement contains certain principles that will provide the foundation for the FERC's analyses of all subsequent transmission rate proposals. Recognizing the evolution of a more competitive marketplace, the FERC contends that it is critical that transmission services be priced in a manner that appropriately compensates transmission owners and creates adequate incentives for efficient system expansion. Separately, the FERC has also determined that electric utilities providing transmission access must do so on a "comparable basis."
- In November 1994, the SEC issued a Concept Release seeking public comment on a series of issues regarding modernization of holding company regulation under the 1935 Act. In its comments on the Concept Release, GPU has urged that the 1935 Act be repealed because its purposes have long since been fulfilled and the statute now represents a significant impediment to competition. GPU also recommended, in the alternative, that the SEC substantially relax its regulation of registered holding company systems.
- In November 1994, the NJBPU issued a draft New Jersey Energy Master Plan Phase I Report promoting regulatory policy changes intended to move the state's electric and gas utilities into a competitive marketplace. In the draft, the NJBPU recommends, among other things, the adoption of 1) rate-flexibility legislation to allow utilities to compete in order to retain and attract customers; 2) alternatives to rate base/rate-of-return regulation; 3) consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities; and 4) an integrated resource planning and competitive supply-side procurement process to streamline the regulatory review process, lower costs, and ensure that the state's environmental and energy conservation goals are met in a competitive marketplace. Although the NJBPU proposes actions and regulatory reforms that encourage competition, the draft Plan calls for an evolutionary transition toward open markets. The recommendations are largely intended to be interim measures while the NJBPU investigates other issues, including retail wheeling and stranded costs, that are likely to affect the future of the electric utility industry. The Plan is being developed in three phases, with Phase I expected to be adopted in March 1995 and the remaining phases expected to be concluded by year- end 1995.
- In April 1994, the PaPUC initiated an investigation into the role of competition in the electric utility industry. Met-Ed and Penelec filed responses suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investment, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on utilities as compared with unregulated or out-of-state suppliers. The investigation is expected to be concluded in 1995, at which time the PaPUC will decide whether to conduct a rulemaking proceeding.
- In a January 1995 order, the FERC determined that a power purchase agreement between Connecticut Power & Light Co. and a nonutility generator was invalid since 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 implementing regulations. Then, in February 1995, the FERC found that the California Public Utilities Commission's (CPUC) capacity procurement program also violated PURPA because, as designed, it necessarily 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 have sought to have the FERC determine that categories of their nonutility generation power purchase agreements are void on the same or similar grounds. The Subsidiaries are reviewing these FERC decisions and various of their nonutility generation agreements in this light. In addition, the GPU System is, together with other electric utilities, currently engaged in efforts to repeal PURPA.
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 rests on the Subsidiaries' ability to recover such assets from their respective ratepayers 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 nonutility generators, 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. A third source of exposure is regulatory assets which, if not supported by regulators, would have no value in a competitive market. Statement of Financial Accounting Standard No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation", applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. If a portion of the GPU System's operations continues to be regulated, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. 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. 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 if regulators will allow recovery from customers of such costs during the industry's transition period.
As discussed below, in response to this situation the Subsidiaries, among other things, intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or inconsistent with competitive market pricing. The Subsidiaries are also seeking to renegotiate and wherever practicable buy out existing high cost long-term agreements, and will continue to pursue legal, regulatory and legislative initiatives to this end.
Also in 1994, EI acquired North Canadian Power, Inc. (NCP) and ownership interests in NCP's five operating cogeneration facilities for approximately $54 million. EI is actively engaged in a number of domestic and international energy development projects, including as a joint venture participant in a 750 MW combined-cycle project in Barranquilla, Colombia (see NONUTILITY BUSINESSES).
Corporate Realignment
GPU intends to organize a new subsidiary, GPU Generation Corporation (GPUGC), to operate, maintain and repair the non-nuclear generation facilities owned by the Subsidiaries as well as undertake responsibility to construct any new non-nuclear generation facilities which the Subsidiaries may need in the future. GPUGC will consolidate and streamline the management of these generation facilities. During 1994, the Subsidiaries received regulatory approvals from the PaPUC and NJBPU to enter into an operating agreement with GPUGC. An application for SEC authorization is pending.
The management of GPU's two Pennsylvania operating subsidiaries has also been combined. This action is intended to increase effectiveness and lower costs of Pennsylvania customer operations and service functions. In addition, employee participation in incentive compensation programs has been expanded to tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System workforce accepted the Voluntary Enhanced Retirement Programs (VERP) resulting in a pre-tax charge to earnings of $127 million of which JCP&L's, Met-Ed's and Penelec's shares were $47 million, $35 million and $45 million, respectively. Future payroll and benefits savings, which are estimated to be $75 million annually (JCP&L's, Met-Ed's and Penelec's shares of these savings are $31 million, $18 million and $26 million, respectively), began in the third quarter and reflect limiting the replacement of employees up to ten percent of those retired. Retirement benefits will be substantially paid from pension and postretirement plan trusts.
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 5 million in New Jersey and Pennsylvania. For the year 1994, the Subsidiaries' revenues were about equally divided between Pennsylvania customers and New Jersey customers. During 1994, the proportional breakdown of sales to customers by customer class was as follows:
% Operating Revenues % KWH Sales GPU JCP&L Met-Ed Penelec GPU JCP&L Met-Ed Penelec Residential 42 44 43 36 36 41 36 29 Commercial 34 38 28 32 32 38 27 29 Industrial 22 17 28 27 29 21 35 34 Other* 2 1 1 5 3 - 2 8 100 100 100 100 100 100 100 100
* Rural electric cooperatives, municipalities (primarily 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 customer 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 10%, 11% and 11%, respectively, of such 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 2.6 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 the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and the Mid-Atlantic Area Council, an organization providing coordinated review of the planning by utilities in the PJM area. The interconnection facilities are used for substantial capacity and energy interchange and purchased power transactions as well as emergency assistance.
NONUTILITY BUSINESSES
EI and EI Power, Inc. are in the business of developing, owning, operating and investing in cogeneration and other nonutility power production facilities.
As of December 31, 1994, EI had twelve combined-cycle cogeneration plants in-service located in the United States and Canada with a total capacity of 932 MW and a 24 MW facility under construction expected to be completed in 1996. EI has operating responsibility for nine of these plants. In 1994, EI acquired NCP along with partnership interests in NCP's five domestic operating projects. In addition, EI is a participant in a joint venture developing a 750 MW combined-cycle plant in Barranquilla, Colombia.
In 1994, GPU contributed $75 million in cash to EI for the purpose of investing in nonutility generation projects and partnerships. Total EI investments for the year consisted of approximately $54 million for the NCP acquisition and $20 million for other capital expenditures. At December 31,
1994, GPU's net investment in EI was $111 million. The SEC has authorized GPU to invest up to an additional $200 million in EI through 1997.
The EPAct created two new categories of nonutility entities - exempt wholesale generators (EWG) and foreign utility companies which are largely free from rate regulation (other than with respect to an EWG's wholesale rates), as well as regulation under the 1935 Act. EI has expanded its business activities to include the development of additional capacity through EWGs in the United States and is pursuing development projects in Latin America and Asia, while investigating other international opportunities.
NUCLEAR FACILITIES
The Subsidiaries have made investments in three major nuclear projects -- Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and TMI-2, which was damaged during a 1979 accident. At December 31, 1994, the Subsidiaries' net investment, including nuclear fuel, in TMI-1 was $627 million (JCP&L's, Met-Ed's and Penelec's shares are $162 million, $311 million and $154 million, respectively) and $817 million for Oyster Creek. 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 and safety standards and experience gained in the construction and operation of nuclear facilities. The GPU System may also incur costs and experience reduced output at its nuclear plants because of the 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 the plants' useful lives (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs described above through the ratemaking process, but recognizes that recovery is not assured.
TMI-1
TMI-1, a 786 MW pressurized water reactor, was licensed by the NRC in 1974 for operation through 2008. The NRC has extended the TMI-1 operating license through April 2014, in recognition of the plant's approximate six-year construction period. During 1994, TMI-1 operated at a capacity factor of approximately 96%. No refueling outages occurred in 1994; the next refueling outage is scheduled to begin in September 1995.
Oyster Creek
The Oyster Creek station, a 610 MW boiling water reactor (effective January 17, 1995 the Oyster Creek station was rerated at 619 MW), received a
provisional operating license from the NRC in 1969 and a full term operating license in 1991. In April 1993, the NRC extended the station's operating license from 2004 to 2009 in recognition of the plant's approximate four-year construction period. During the 65-day scheduled refueling outage which began in September 1994, inspections revealed unscheduled, necessary repairs that extended the outage to 97 days. Taking this into account the plant operated at a capacity factor of approximately 68% during 1994. The next refueling outage is scheduled to begin in September 1996.
TMI-2
The 1979 TMI-2 accident resulted in significant damage to, and contamination of, the plant and a release of radioactivity to the environment. The cleanup program was completed in 1990, and, after receiving NRC approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Corporation and the Subsidiaries. Approximately 2,100 of such claims are pending in the U.S. District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Subsidiaries had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against the Corporation and the Subsidiaries and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is likely to begin in 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released
cannot be resolved on a motion for summary judgement. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals.
In an order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against the Corporation and the Subsidiaries; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE). See 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 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1994 dollars) for TMI-1 are $157 million (JCP&L's, Met-Ed's and Penelec's shares are $39 million, $79 million and $39 million, respectively) and for Oyster Creek, $189 million. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes into account the accident (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1 and Oyster Creek that considered various decommissioning plans and estimated
the cost of the radiological portions of decommissioning each plant (adjusted to 1994 dollars) to range from approximately $225 to $309 million for TMI-1 while Met-Ed's share of the range is from $113 million to $155 million, and $239 to $350 million for Oyster Creek. In addition, the studies estimated the cost of removal of nonradiological structures and materials (adjusted to 1994 dollars) at $74 million for TMI-1 (JCP&L's, Met-Ed's and Penelec's shares are $18 million, $37 million and $19 million, respectively) and $48 million for Oyster Creek.
The ultimate cost of retiring the GPU System's nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Subsidiaries have contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990 and 1991 to an external trust and will await resolution of the case pending before the Pennsylvania Supreme Court (see TMI-2 Future Costs) before making any further contributions for amounts written off by Met-Ed and Penelec in 1994.
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 1991 and 1993 rate orders issued by the NJBPU, for its share of the cost of removal of nonradiological structures and materials. In January 1993, the PaPUC granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site-specific study. Effective October 1993, the PaPUC approved a rate change for Penelec which increased the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for decommissioning expenditures are deposited in external trusts. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $46 million for TMI-1 (JCP&L's, Met-Ed's and Penelec's shares are $17 million, $21 million and $8 million, respectively) and $100 million for Oyster Creek at December 31, 1994.
TMI-2 Future Costs
The Corporation and its Subsidiaries have recorded a liability amounting to $250 million (JCP&L's, Met-Ed's and Penelec's shares are $63 million, $125 million and $62 million, respectively) as of December 31, 1994, for the radiological decommissioning of TMI-2, reflecting the NRC funding target. The Subsidiaries record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Subsidiaries have also recorded a liability in the amount of $19 million (JCP&L's, Met-Ed's and Penelec's shares are $5 million, $9 million and $5 million, respectively) for incremental costs specifically attributable to monitored storage. In addition, the Subsidiaries
have recorded a liability in the amount of $72 million (JCP&L's, Met-Ed's and Penelec's shares are $18 million, $36 million and $18 million, respectively) for nonradiological cost of removal. In 1990, JCP&L made a contribution of $15 million to an external decommissioning trust. In 1991, Met-Ed and Penelec made contributions of $40 million and $20 million, respectively, to external decommissioning trusts relating to their shares of the accident-related portion of the decommissioning liability. These contributions were not recovered from customers and have been written off. Met-Ed and Penelec will await resolution of the appeal pending before the Pennsylvania Supreme Court (discussed below) before making any further contributions of amounts written off.
In 1993, the Pennsylvania Office of Consumer Advocate (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 (radiological decommissioning and nonradiological cost of removal). 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 December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to review the decision. Met-Ed and Penelec will be required to charge to expense their share of future increases in the estimate of the costs of retiring TMI-2 if the Supreme Court does not reverse the Commonwealth Court decision.
The NJBPU has granted JCP&L decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. JCP&L, which is not affected by the Commonwealth Court's ruling, intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 being excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor. In addition to the retrospective premiums payable under Price-Anderson, under insurance policies applicable to nuclear operations and facilities, the GPU System is also subject to retrospective premium assessments of up to $69 million in any one year (JCP&L's, Met-Ed's and Penelec's shares being $41 million, $19 million and $9 million, respectively).
The GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing by 20 percent for years two and three.
NONUTILITY AND OTHER POWER PURCHASES
The Subsidiaries have entered into power purchase agreements with nonutility generators for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Subsidiaries to purchase at the contract price the net output up to the contract limits. As of December 31, 1994, facilities covered by these agreements having 1,416 MW (JCP&L 882 MW, Met-Ed 239 MW and Penelec 295 MW) of capacity were in service and 130 MW were scheduled to commence operation in 1995. Actual payments from 1992 through 1994, and estimated payments to nonutility generators (including those scheduled to enter service thereafter) through 1999 are as follows:
Payments Under Nonutility Agreements (Millions)
Total JCP&L Met-Ed Penelec
1992 $ 471 $ 316 $ 78 $ 77 1993 491 292 95 104 1994 528 304 101 123 *1995 694 395 114 185 *1996 918 556 170 192 *1997 1,088 571 280 237 *1998 1,304 587 415 302 *1999 1,337 607 418 312
* Estimated
These agreements, in the aggregate, provide for the purchase of approximately 2,596 MW (JCP&L 1,176 MW, Met-Ed 846 MW and Penelec 574 MW) of capacity and energy by the GPU System by the mid-to-late 1990s.
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 now seek shorter-term agreements offering more flexibility. Due to the current availability of excess capacity in the market place, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing generation facilities is currently competitively priced. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Subsidiaries' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources.
These agreements have been entered into pursuant to the requirements of PURPA and state regulatory directives. Given these circumstances, the Subsidiaries have initiated a number of programs to attempt to substantially reduce these above market payments. In addition, the Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Subsidiaries are also attempting to renegotiate, and in some cases buyout, high cost long-term nonutility generation agreements.
While the Subsidiaries thus far have been granted recovery of their nonutility generation costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to be able to recover these costs throughout the term of the related agreements (see INDUSTRY DEVELOPMENTS). GPU currently estimates that in 1998, when substantially all of the these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $300 million to $450 million annually (for JCP&L, $120 million to $190 million; for Met-Ed, $90 million to $140 million; and for Penelec, $90 million to $120 million). Moreover, efforts to lower these costs have led to disputes before both the NJBPU and the PaPUC, as well as to litigation, and may result in claims against the Subsidiaries for substantial damages. There can be no assurance as to the outcome of these matters.
A 1993 NJBPU order directed all New Jersey utilities to identify nonutility generation contracts which were uneconomic and, therefore, candidates for buyout or other remedial measures. JCP&L identified the proposed 100 MW Freehold generation project as one such candidate, but was unable to negotiate a buyout or contract repricing to a level consistent with prices of replacement power. The NJBPU therefore ordered that hearings be held to determine whether its order approving the agreement should be modified or revoked. After hearings commenced in early 1994, the nonutility generator filed a complaint with the U.S. District Court seeking to enjoin the NJBPU proceedings on the grounds they were preempted by PURPA. The District Court dismissed the complaint on jurisdictional grounds. In January 1995, however, the U.S. Court of Appeals for the Third Circuit overturned the District Court decision. The Court of Appeals held, among other things, that once the NJBPU approves a power purchase agreement under PURPA and approves the utility's collection of costs from its customers, PURPA preempts the NJBPU from altering
its order approving the contract and JCP&L's recovery from customers of its payment to the nonutility generator. The Court of Appeals reached its decision despite the contract provision that if the NJBPU at any time in the future disallowed any such rate recovery, JCP&L's payments to the nonutility generator would be equally reduced. JCP&L, the NJBPU and the New Jersey Division of Ratepayer Advocate (Ratepayer Advocate) have each filed motions for in banc rehearing with the Court of Appeals before which the matter is pending.
In 1994, a nonutility generator requested that the NJBPU and the PaPUC order JCP&L and Met-Ed to enter into long-term agreements to buy capacity and energy from the nonutility generator's proposed 322 MW facility. On February 14, 1995, the NJBPU Administrative Law Judge (ALJ) hearing the matter issued a recommended decision finding that while the developer had established a right to an agreement under PURPA, the rates payable by JCP&L were to be based upon JCP&L's 1993 avoided energy costs and not 1992 costs as the developer requested. JCP&L has appealed aspects of the ALJ's decision to the NJBPU. Met-Ed sought to dismiss a similar request based on a May 1994 PaPUC order, which granted a Met-Ed and Penelec petition to obtain additional nonutility purchases through competitive bidding until new PaPUC regulations have been adopted. In September 1994, the Commonwealth Court granted the PaPUC's application to revise its May 1994 order for the purpose of reevaluating the nonutility generator's right to sell power to Met-Ed. The PaPUC has referred the matter to an ALJ for hearings.
In November 1994, Penelec requested the Pennsylvania Supreme Court to review a Commonwealth Court decision upholding a PaPUC order requiring Penelec to purchase a total of 160 MW from two nonutility generators. The PaPUC had ordered Penelec in 1993 to enter into power purchase agreements with the nonutility generators for 80 MW of power each under long-term contracts commencing in 1997 or later. In August 1994, the Commonwealth Court denied Penelec's appeal of the PaPUC order. Penelec is seeking review by the Pennsylvania Supreme Court on the grounds that the contracts would impose unnecessary and excessive costs on Penelec customers and, in any case, that the nonutility generators did not incur a legal obligation entitling them to a payment under PURPA.
In May 1994, the NJBPU granted two nonutility developers of a proposed 200 MW coal project final in-service date extensions for projects originally scheduled to be operational in 1997. JCP&L has appealed the NJBPU's decision to the Appellate Division of the New Jersey Superior Court on the grounds, among others, that the NJBPU exceeded its authority by unilaterally amending the power purchase agreements. Oral argument was held on March 1, 1995. The NJBPU order extends the in-service date for one year plus the period until JCP&L's appeals are decided.
As part of the effort to reduce above-market payments under nonutility generation agreements, the Subsidiaries are also seeking to implement a program under which the natural gas fuel procurement and transportation for the Subsidiaries' gas-fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, would be pooled and managed by a nonaffiliated fuel manager. The Subsidiaries believe the plan has the potential to provide substantial savings for their customers. The Subsidiaries have begun initial discussions with the nonutility generators who would be eligible to participate and are negotiating a proposed fuel
management agreement. Requirements for approval of the plan by state and federal regulatory agencies are being reviewed.
Met-Ed has entered into an agreement and JCP&L is completing contract negotiations with three other utilities to purchase capacity and energy for various periods through 2004. These agreements, including contracts under negotiation, will provide for up to 1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW by 2004. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated as follows:
Payments Under Other Utility Agreements (Millions)
Total JCP&L Met-Ed Penelec
1995 $ 208 $ 202 $ 6 $ - 1996 175 175 - - 1997 162 162 - - 1998 145 145 - - 1999 128 128 - -
JCP&L's contract negotiations are the result of its all-source solicitation for short- to intermediate-term energy and capacity (see the New Energy Supplies section of MANAGEMENT'S DISCUSSION AND ANALYSIS).
RATE PROCEEDINGS
Pennsylvania
In December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to review a Commonwealth Court decision reversing a 1993 PaPUC rate order allowing for the future recovery of certain TMI-2 retirement costs (see TMI-2 Future Costs in the Nuclear Plant Retirement Costs section above).
In 1993, Penelec began deferring FAS 106 incremental expense in accordance with the PaPUC's generic policy statement permitting the deferral of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of such costs, stating that FAS 106 expense incurred after January 1, 1993 (the effective date for the accounting change) but prior to its next base rate case could not be deferred for future recovery, and that to assure such future recovery constituted retroactive ratemaking (see page, Note 9 of GPU's Consolidated Financial Statements). As a result of the Court's decision, Penelec wrote off $14.6 million deferred since January 1993. Penelec anticipates it will take additional charges to income of approximately $9 million annually, beginning in 1995. The Corporation believes the Commonwealth Court ruling does not affect Met-Ed because it received PaPUC authorization as part of its 1993 retail base rate order to defer incremental FAS 106 expense. JCP&L received similar authorization in a 1993 NJBPU retail base rate order.
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 PaPUC will adopt a generic nuclear performance standard as a part of Met-Ed's and Penelec's energy cost rate clauses in 1995.
New Jersey
In December 1994, JCP&L filed a petition with the NJBPU requesting an increase in its levelized energy adjustment clause charges (LEAC) and demand side factors of approximately $68 million annually effective March 1, 1995. The proposed increase is based on additional costs of nonutility generation and demand-side management (DSM).
In May 1994, the NJBPU approved JCP&L's request to implement a new rate initiative designed to retain and expand the economic base in its service territory. Under the contract rate service, JCP&L may enter into individual contracts to provide electric service to large commercial and industrial customers. This initiative will allow JCP&L more flexibility in responding to competitive pressures.
JCP&L's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect of the performance standard charge at a 40% capacity factor would be approximately $11 million before tax. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBPU for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC.
The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from nonutility generation projects. The proceeding was initiated, in part, to respond to contentions of the Ratepayer Advocate, that by permitting utilities to recover such costs through the LEAC, an excess or "double recovery" may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1993, JCP&L and the other New Jersey electric utilities filed motions for summary judgment with the NJBPU. The Ratepayer Advocate has filed a brief in opposition to the utilities' summary judgment motions including a statement from its consultant that in his view, the "double recovery" for JCP&L for the 1988-92 LEAC periods would be approximately $102 million. In 1994, the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent LEACs remain open for further investigation. This matter is pending before an ALJ. JCP&L estimates that the potential exposure for LEAC periods subsequent to 1991 is approximately $67 million through February 1996, the end of the next LEAC period. There can be no assurance as to the outcome of this proceeding.
CAPITAL PROGRAMS
General
During 1994, the GPU System had gross plant additions of approximately $588 million (JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are $249 million, $171 million, $164 million and $4 million, respectively) attributable principally to improvements and modifications to existing generating stations, new combustion turbines, additions to the transmission and distribution system and clean air requirements. GPU also contributed $75 million in cash to EI during 1994 (see NONUTILITY BUSINESSES). The principal categories of the 1995 anticipated subsidiary construction
expenditures, which include an allowance for other funds used during construction, are as follows:
(In Millions)
GPU JCP&L Met-Ed Penelec
Generation - Nuclear $ 51 $ 30 $ 14 $ 7 Nonnuclear 148 50 31 67 Total Generation 199 80 45 74 Transmission & Distribution 249 124 58 67 Other 34* 16 12 3 Total $482 $220 $115 $144
* Includes $3 million for GPUSC.
The GPU System's gross plant additions are expected to be approximately $466 million in 1996 (JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are $217 million, $101 million, $145 million, and $3 million, respectively). The anticipated decrease in construction expenditures during 1996 is principally attributable to an anticipated reduction in the level of expenditures associated with clean air requirements. GPU will continue to contribute cash, from time to time, to EI during 1995 and 1996 as project investment opportunities arise. In addition, expenditures for maturing debt are expected to be $91 million for 1995 (JCP&L's, Met-Ed's and GPUSC's shares are $47 million, $41 million and $3 million, respectively) and $129 million for 1996 (JCP&L's, Met-Ed's, Penelec's and GPUSC's shares are $36 million, $15 million, $75 million and $3 million, respectively) including mandatory redemptions of preferred stock. Subject to market conditions, the Subsidiaries intend to refinance during these periods outstanding senior securities, should it prove economical to do so.
GPU estimates that two-thirds of the GPU System's total capital needs in each of 1995 and 1996 will be satisfied through internally generated funds. The Subsidiaries estimate that their respective capital needs will be met through internally generated funds in the following proportions:
JCP&L Met-Ed Penelec
1995 2/3 1/2 3/4 1996 3/4 3/4 1/2
The Subsidiaries expect to obtain the remainder of these funds principally through the sale of first mortgage bonds and preferred stock, subject to market conditions. The Subsidiaries' bond indentures and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short-term debt the Subsidiaries may issue (see LIMITATIONS ON ISSUING ADDITIONAL SECURITIES). Present plans call for the Subsidiaries to issue long-term debt and preferred stock during the next three years to finance construction activities and, depending on the level of interest rates, refinance outstanding senior securities.
The GPU System's 1995 construction program includes $57 million (JCP&L's, Met-Ed's and Penelec's shares are $20 million, $18 million and $19 million, respectively) in connection with the federal Clean Air Act Amendments of 1990 (Clean Air Act) requirements (see Environmental Matters-Air). The 1996 construction program currently includes approximately $12 million (JCP&L's, Met-Ed's and Penelec's shares are $2 million, $1 million and $9 million, respectively) for Clean Air Act compliance.
The GPU System's gross plant additions exclude nuclear fuel requirements provided under capital leases that amounted to $41 million (JCP&L's, Met-Ed's and Penelec's shares are $37 million, $3 million and $1 million, respectively) in 1994. When consumed, the presently leased material, which amounted to $148 million (JCP&L's, Met-Ed's and Penelec's shares are $99 million, $33 million and $16 million, respectively) at December 31, 1994, is expected to be replaced by additional leased material at an average rate of approximately $65 million (JCP&L's, Met-Ed's and Penelec's shares are $41 million, $16 million and $8 million, respectively) 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, each of the Subsidiaries is expected to experience an average growth in sales to customers of about 2% annually. These increases are expected to result from 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" markets, and avoidance of long-term firm commitments. Through 1999, the GPU System's plan consists of the continued utilization of existing generating facilities, combined with power purchases, construction of new facilities, and the continued promotion of economic energy conservation and load-management programs. Given the future direction of the industry, the GPU System'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 market. The GPU System will take necessary actions to avoid adding new capacity at costs that may exceed future market prices. In addition, the Subsidiaries will seek regulatory support to renegotiate or buyout contracts with nonutility generators where the pricing is in excess of projected prices of alternative sources.
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 over 43 MW through 1994.
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. However, an industrial intervenor contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed the PaPUC order. 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 1995. 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 $528 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 1994, Penelec and Met-Ed issued $205 million (Met-Ed $100 million and Penelec $105 million) of Monthly Income Preferred Securities through special- purpose finance subsidiaries, and an aggregate of $180 million (Met-Ed $50 million and Penelec $130 million) principal amount of long-term debt. A portion of the proceeds from these sales was used to refinance long-term debt amounting to $64 million (Met-Ed $26 million and Penelec $38 million) and redeem $60 million of more costly preferred stock (Met-Ed $35 million and Penelec $25 million). During the first quarter of 1995, Penelec and Met-Ed issued $60 million and $30 million, respectively, of long-term debt. The net proceeds from these sales were used to reduce short-term debt.
JCP&L anticipates receiving regulatory approval in the first quarter of 1995 to issue, through a special-purpose finance subsidiary, up to $125 million of Monthly Income Preferred Securities. A portion of these securities is expected to be issued in 1995 to reduce short-term debt.
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 for various periods through 1995. Under existing authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the amount of $275 million, $220 million and $230 million, respectively, of which $100 million for each Subsidiary may consist of preferred stock. Met-Ed and Penelec, through their special-purpose finance subsidiaries, have remaining regulatory authority to issue an additional $25 million and $20 million, respectively, of Monthly Income Preferred Securities. The Subsidiaries also
have regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
Present plans call for GPU to issue common stock and the Subsidiaries to issue long-term debt and Monthly Income Preferred Securities during the next three years to finance construction activities, make additional investments in GPU's nonregulated businesses, fund the redemption of maturing senior securities, make contributions to decommissioning trust funds and, depending on the level of interest rates, refinance outstanding senior securities.
Under the Subsidiaries nuclear fuel lease agreements with nonaffiliated fuel trusts, an aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any one time. It is contemplated that when consumed, portions of the currently 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' first mortgage bond indentures and/or articles of incorporation 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' first mortgage bond indentures require that, for a period of any twelve consecutive months out of the fifteen calendar months immediately preceding the issuance of additional bonds, 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 bonds shall have been at least twice the annual interest requirements on all bonds to be outstanding immediately after such issuance. Moreover, the Subsidiaries' first mortgage bond indentures restrict the ratio of the principal amount of first mortgage bonds which may be issued to not more than 60% of bondable value of property additions. In addition, the indentures, in general, permit the Subsidiaries to issue additional first mortgage bonds against a like principal amount of previously retired bonds.
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 any 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, and for Penelec, net earnings available for the payment of dividends on preferred stock shall have been at least three times the annual dividend requirements on all shares of preferred stock to be outstanding immediately after such issuance.
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, 1994, these restrictions would have permitted JCP&L, Met-Ed and Penelec to have approximately $277 million, $119 million and $131 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.
As of December 31, 1994, JCP&L's, Met-Ed's and Penelec's bondable value of property additions were $418 million, $659 million and $549 million, respectively. However, as a result of the TMI-2 retirement costs write-offs, together with certain other costs recognized in the second quarter of 1994 (see TMI-2 Future Costs), Met-Ed will be unable to meet the interest and preferred dividend coverage requirements of its indenture and charter, respectively, until the third quarter of 1995. Therefore, Met-Ed's ability to issue senior securities through June 1995 will be limited to the issuance of FMBs on the basis of $35 million of previously issued and retired bonds. For similar reasons, Penelec has sufficient coverage to issue only approximately $20 million of FMBs through June 1995, depending on interest rates at the time of issuance, plus $8 million of FMBs on the basis of previously issued and retired bonds. Penelec will be unable to meet dividend coverage requirements for issuing preferred stock until the third quarter of 1995. JCP&L currently has the ability to issue $319 million of FMBs on the basis of previously issued and retired bonds. JCP&L has sufficient interest coverage at December 31, 1994 to issue approximately $900 million of FMBs, depending on interest rates at the time of issuance; however, the issuances of FMBs on this basis would be limited to 60% of JCP&L's bondable property additions, or approximately $250 million. In addition, at December 31, 1994 JCP&L has sufficient dividend coverage to issue approximately $730 million of preferred stock, depending on interest rates at the time of issuance.
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 (NYPSC). 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.)
ELECTRIC GENERATION AND THE ENVIRONMENT
Fuel
Of the portion of their energy requirements supplied by their own generation, the Subsidiaries utilized fuels in the generation of electric energy during 1994 in approximately the following percentages:
Total JCP&L Met-Ed Penelec
Coal 59% 22% 57% 85% Nuclear 37% 68% 41% 14% Gas 2% 6% - - Oil 2% 6% - - Other* - (2)% 2% 1%
* Represents hydro and pumped storage (which is a net user of electricity).
Approximately 41% (JCP&L's, Met-Ed's and Penelec's percentages are 60%, 33% and 28%, respectively) of the Subsidiaries' total energy requirements in 1994 was supplied by purchases and interchange from other utilities and nonutility generators. For 1995, the Subsidiaries estimate that their generation of electric energy will be in the following proportions:
Total JCP&L Met-Ed Penelec
Coal 63% 23% 64% 89% Nuclear 34% 70% 33% 10% Gas 2% 5% 1% - Oil 1% 3% - - Other* - (1)% 2% 1%
* Represents hydro and pumped storage.
The anticipated changes in 1995 fuel utilization percentages are principally attributable to the refueling outage for TMI-1 scheduled during 1995. Approximately 41% (JCP&L's, Met-Ed's and Penelec's percentages are 60%, 37% and 26%, respectively) of the Subsidiaries' 1995 energy requirements are expected to be supplied by purchases and interchange from other utilities and nonutility generators.
Fossil: The Subsidiaries have entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which they have ownership interests (JCP&L 16.67% - ownership interest in Keystone; Met-Ed - 16.45% ownership interest in Conemaugh; and Penelec - 50% ownership in Homer City). The contracts, which expire between 1995 and the end of the expected service lives of the generating stations (2004 for Keystone, between 1995 and 1997 for Conemaugh and between 1995 and 2003 for Homer City), require the purchase of fixed amounts of coal. The price of the coal under the contracts is generally based on adjustments of indexed cost components. One of Penelec's contracts for Homer City also includes a provision for the payment of environmental and postretirement benefits costs. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $98 million for 1995 (JCP&L's, Met- Ed's and Penelec's shares are $21 million, $27 million and $50 million, respectively).
The Subsidiaries' coal-fired generating stations now in service are estimated to require an aggregate of 147 million tons (JCP&L's, Met-Ed's and Penelec's shares are 15 million tons, 38 million tons and 94 million tons, respectively) of coal over the next twenty years. Of this total requirement, approximately 11 million tons (JCP&L's and Penelec's shares are 4 million tons and 7 million tons, respectively) 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. While Oyster Creek currently has sufficient on-site storage capacity to accommodate, under normal operating conditions, its spent nuclear fuel while maintaining the ability to remove the entire reactor core, additional on-site storage capacity will be required at the Oyster Creek station beginning in 1996 in order to continue operation of the plant. Contract commitments with an outside vendor have been made for on- site incremental spent fuel dry storage capacity at Oyster Creek for 1996 and 1998. In March 1994, the Lacey Township Zoning Board of Adjustment issued a use variance for the facility. In May 1994, however, Berkeley Township and other parties appealed to the New Jersey Superior Court to overturn the decision. The court has scheduled a trial for March 30, 1995. Construction of the facility is scheduled for completion in September 1995.
Environmental Matters
The GPU System is subject to federal and state water quality, air quality, solid waste disposal and employee health and safety legislation and to environmental regulations issued by the U.S. Environmental Protection Agency (EPA), state environmental agencies and other federal agencies. In addition, the 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 manufactured gas plants 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 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 EPA for a discharge permit for its Yards Creek pumped storage facility. Met-Ed and Penelec have 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 New Jersey Department of Environmental Protection (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 Pennsylvania Department of Environmental Resources (PaDER) and the NJDEP.
During 1993, Met-Ed entered into an agreement with various agencies to construct a fish passage facility at its York Haven hydroelectric project by the year 2000. The present estimated installed cost of the facility is $6.7 million. Through 1994, less than $.5 million has been spent on pre- construction. Construction is expected to begin in late 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.
In June 1994, the Barnwell, South Carolina low level radioactive waste (radwaste) disposal site closed. GPUN had been using this facility for disposal of low-level radioactive waste from the Oyster Creek and TMI-1 nuclear generating stations. In July 1994, GPUN began on-site storage of low- level radwaste at Oyster Creek and TMI-1 and will continue on-site storage until June 1999, when both the Northeast Compact and Appalachian Compact disposal facilities are currently scheduled to open. If the disposal facilities are delayed beyond June 1999, GPUN will be required to perform an evaluation as to its ability to safely store radwaste beyond that date.
New Jersey and Connecticut have established the Northeast Compact, a low level radwaste disposal facility in New Jersey. The estimated cost to license and build the facility is $74 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 1994, $6 million has been paid. The development of the facility is expected to continue after 1997 which will most likely result in additional fees 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) 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.
The Subsidiaries have provided for future contributions to the Decontamination and Decommissioning Fund (part of the EPAct) for the cleanup of enrichment plants operated by the Federal government. The GPU System's total liability at December 31, 1994 amounted to $40 million (JCP&L's, Met- Ed's and Penelec's shares are $25 million, $10 million and $5 million, respectively). The Subsidiaries made their initial payment in 1993. The remaining amount recoverable from ratepayers at December 31, 1994 is $46 million (JCP&L's, Met-Ed's and Penelec's shares are $27 million, $13 million and $6 million, respectively).
Air: The Subsidiaries are subject to certain state environmental regulations of the NJDEP and the PaDER. The Subsidiaries are also subject to certain federal environmental regulations of the EPA.
The PaDER, NJDEP and the EPA have adopted air quality regulations designed to implement Pennsylvania, New Jersey and federal statutes relating to air quality.
Current Pennsylvania environmental regulations prescribe criteria that generally limit the sulfur dioxide content of stack gas emissions from 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 having a sulfur content meeting these criteria. If, and to the extent that, the Subsidiaries cannot continue to meet such limitations with processed coal, it may be necessary to retrofit operating stations with sulfur removal equipment that may require substantial capital expenditures as well as substantial additional operating costs. Such retrofitting would take approximately five years.
As a result of the Clean Air Act, which requires substantial reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year 2000, it will be necessary for the GPU System to install and operate emission control equipment as well as switch to slightly lower sulfur coal at some of the GPU System's coal-fired plants in order to achieve compliance. To comply with Title IV of the Clean Air Act, the GPU System expects to spend up to $380 million (JCP&L - $58 million; Met-Ed - $145 million; and Penelec - $177 million) by the year 2000 for air pollution control equipment, of which approximately $179 million (JCP&L's Met-Ed's and Penelec's shares are $16 million, $88 million and $75 million, respectively) has been spent as of December 31, 1994. The capital costs of equipment are for the installation of scrubbers, low Nox burner technology 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 first of two scrubbers was completed at the Conemaugh station during 1994. The second scrubber is expected to be installed by the end of November 1995. This action is part of the GPU System's plans to comply with Phase I 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, Sayreville and Werner 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 or emission control 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 nitrogen oxide will be required to implement Reasonably Available Control Technology (RACT) by May 31, 1995.
This will affect the GPU System's generating stations. PaDER's RACT regulations became effective in January 1994. Large coal-fired combustion units are required to comply with a NOx emission limitation based on federal RACT emission limitation requirements, or may elect to use a case-by-case analysis to establish RACT requirements. In order to comply with these RACT regulations, low NOx burners with separate overfire air are being installed at the Titus, Portland and Conemaugh stations. NJDEP's RACT regulations became effective in December 1993 and 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 nitrogen oxides emission reductions of 65% and 55%, 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 modeling can be performed which 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. However, the Homer City Coal Processing Plant is being studied to determine if it is a major source of air toxics.
Both the EPA and PaDER 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 PaDER have approved the use of a nonguideline air quality model. This model is more representative and less conservative than the EPA guideline model and will be used in the development of a compliance strategy for all generating stations in the Chestnut Ridge Energy Complex. Significant sulfur dioxide reductions may be required at the Keystone station, which could result in material capital and additional operating expenditures.
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 PaDER and EPA have approved the use of a nonguideline model which is more representative than guideline models. A model evaluation study is also being conducted at Shawville station. The results of this study will be available in 1995.
The attainment issue has been taken into account as part of the design of the Conemaugh station scrubbers. Met-Ed has initiated ambient air quality modeling studies for its Portland and Titus stations that will take several years to complete. While the results are uncertain, these studies may result in a revised Pennsylvania State Implementation Plan (PaSIP) in order to attain NAAQS for sulfur dioxide. If sulfur dioxide emissions need to be reduced to meet the new PaSIP, Met-Ed will reevaluate its options available for Portland and Titus stations.
Based on the results of the studies pursuant to NAAQS, significant sulfur dioxide reductions may be required at one or more of these stations which could result in 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 action plan relies heavily on voluntary action by industry. On February 3, 1995, GPU joined 30 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's, Met-Ed's and Penelec's Phase I and Phase II affected units as required by EPA, NJDEP and PaDER regulations.
The PaDER has a CEMS enforcement policy to ensure consistent compliance with air quality regulations under federal and state statutes. The CEMS enforcement policy includes matters such as visible emissions, sulfur dioxide emission standards, nitrogen oxide emissions and a requirement to maintain certified continuous emission monitoring equipment. In addition, this policy provides a mechanism for the payment of certain prescribed amounts to the Pennsylvania Clean Air Fund (Clean Air Fund) for air pollutant emission excesses or monitoring failures. With respect to the operation of Met-Ed's and Penelec's generating stations for 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 PaDER 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 1994, the Subsidiaries made capital expenditures of approximately $91 million (JCP&L's, Met-Ed's and Penelec's shares are $9 million, $36 million and $46 million, respectively) in response to environmental considerations and have budgeted approximately $68 million (JCP&L's, Met-Ed's and Penelec's shares are $24 million, $19 million and $25 million, respectively) for this purpose in 1995. The incremental annual operating and maintenance costs for such equipment is expected to be immaterial.
Electromagnetic Fields: There have been a number of scientific studies regarding the possibility of adverse health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. While some of the studies have indicated some association between exposure to EMF and cancer, other studies have indicated no such association. The studies have not shown any causal relationship between exposure to EMF and cancer, or any other adverse health effects. In 1990, the EPA issued a draft report that identifies EMF as a possible carcinogen, although it acknowledges that there is still scientific uncertainty surrounding these fields and their possible link to adverse health effects. On the other hand, a 1992 White House Office of Science and Technology policy report states that "there is no convincing evidence in the published literature to support the contention that exposures to extremely low frequency electric and magnetic fields generated by sources such as household appliances, video display terminals, and local power lines are demonstrable health hazards." And, 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. However, these findings conflict 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 EMF associated with the operation of transmission and distribution facilities will produce adverse impacts upon public health and safety and upon property values. Furthermore, regulatory actions under consideration by the NJDEP and bills introduced in the Pennsylvania legislature could, if enacted, establish a framework under which the intensity of EMF produced by electric transmission and distribution lines would be limited or otherwise regulated.
The Subsidiaries cannot determine at this time what effect, if any, this matter will have on their respective results of operation's and financial position.
Residual Waste: PaDER 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 requires, 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's and Met-Ed's landfills had preliminary permit modification applications submitted to the PaDER 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 conducted which are currently under review by the PaDER. 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 all lined facility requirements. The Portland station ash disposal site will require significant modifications under the new regulations. Various alternatives for upgrading the site are being evaluated, including beneficial uses of coal ash.
Other compliance requirements at Penelec that will be implemented in the future include the lining of currently unlined disposal sites and storage impoundments. Impoundments also will eventually require groundwater monitoring systems and assessments of impact on groundwater. Groundwater abatement may be necessary at locations where pollution problems are identified. The removal of all the residual waste or "clean closed" will be done at some impoundments to eliminate the need for future monitoring and abatement requirements. Storage impoundments must have implemented groundwater monitoring plans by 2002, but PaDER can require this at any time prior to this date or defer full compliance beyond 2002 for some storage impoundments at its discretion. Also being evaluated are the exercising of beneficial use options authorized by the regulations and source reductions.
Preliminary groundwater assessment plans have also been conducted at Met-Ed's Portland and Titus stations' industrial waste treatment impoundments and are currently under review by the PaDER. Additional data will be collected and evaluated to determine if abatement will be required. The Portland station impoundments were upgraded in 1987 and meet the requirements for lined impoundments. The Titus station impoundments will require significant modifications by 2002.
There are also a number of issues still to be resolved regarding certain waivers related to Penelec's existing landfill and storage impoundment compliance requirements. These waivers could significantly reduce the cost of many of 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 manufactured gas plants in New Jersey and Pennsylvania. Wastes associated with the operation and dismantlement of these gas manufacturing plants were disposed of both on-site and off-site. Claims have been asserted against the Subsidiaries for the cost of investigation and remediation of these waste disposal sites. The amount of such remediation costs and penalties may be significant and may not be covered by insurance. JCP&L has identified 17 such sites to date. JCP&L has entered into cost sharing agreements with New Jersey Natural Gas Company and Elizabethtown Gas Company under which JCP&L is responsible for 60% of all costs incurred in connection with the remediation of 12 of these sites. JCP&L has entered into Administrative Consent Orders (ACOs) with the 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.
At December 31, 1994, JCP&L has an estimated environmental liability of $32 million recorded on its balance sheet relating to these sites. The estimated liability is based upon ongoing site investigations and remediation efforts, including capping the sites and pumping and treatment of ground water. If the periods over which the remediation is currently expected to be performed are lengthened, JCP&L believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties: JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In December 1994, the NJBPU issued an order approving the recovery of future manufactured gas plant remediation costs through a Remediation Adjustment Clause which will be filed simultaneously with JCP&L's LEAC when remediation expenditures exceed prior collections. The NJBPU decision provides for interest to be credited to customers retroactive to June 1993, until the overrecovery is eliminated and for future costs to be amortized over seven years with interest. At December 31, 1994, JCP&L has collected from customers $3.3 million in excess of expenditures of $13.6 million. JCP&L is pursuing reimbursement of these remediation costs from its insurance carriers.
In November 1994, JCP&L filed a complaint with the New Jersey Superior Court against several of its insurance carriers, relative to these manufactured gas plant sites. JCP&L has 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.
The federal Resource Conservation and Recovery Act of 1976, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the Superfund Amendment and Reauthorization Act of 1986 authorize the EPA to issue an order compelling responsible parties to take cleanup action at any location that is determined to present an imminent and substantial danger to the public or to the environment because of an actual or threatened release of one or more hazardous substances. Pennsylvania and New Jersey have enacted legislation giving similar authority to the PaDER and the 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 13 hazardous and/or toxic waste sites (including those described below).
JCP&L MET-ED PENELEC GPUN GPU TOTAL
PRPs 7 5 3 1 1 13*
* In some cases, the Subsidiaries are named separately for the same site.
In addition, the GPU System companies have been requested to supply information to the EPA and state environmental authorities on several other sites for which the GPU System companies have not as yet been named as PRPs. Met-Ed and Penelec have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment.
In January 1995, the EPA informed GPU that it has been identified as a PRP at the Dover Gas Light Superfund Site in Dover, Delaware. This site was formerly owned by Associated Gas & Electric (AGE), a corporate predecessor of GPU. GPU is currently investigating this matter to determine what, if any, liability exists. The EPA identified GPU along with four other previously named PRPs in this matter.
The Subsidiaries received notification in 1986 from the EPA that they are among the more than 800 PRPs under CERCLA who may be liable to pay for the cost associated with the investigation and remediation of the Maxey Flats disposal site, located in Fleming County, Kentucky. JCP&L, Met-Ed, Penelec and Saxton are alleged to have contributed, in the aggregate, approximately 2.7% (JCP&L's, Met-Ed's, Penelec's and Saxton's shares are 1.81%, .60%, .08% and .23%, respectively) of the total volume of waste shipped to the Maxey Flats site. On September 30, 1991, the EPA issued a Record of Decision (ROD) advising that a remedial alternative had been selected. The PRPs estimate the cost of the remedial alternative selected and associated activities identified
in the ROD at approximately $63 million, for which all responsible parties would be jointly and severally liable. A tentative agreement among all parties has been reached. Final documents are being prepared by the EPA.
The EPA has initiated a suit under CERCLA and other laws for the initial cleanup of hazardous materials deposited at a waste disposal site at Harper Drive, Millcreek Township, Pennsylvania (Millcreek site). Penelec is one of over 50 PRPs at this site. Penelec does not know whether its insurance carriers will assume the responsibility to defend and indemnify it in connection with this matter.
Two lawsuits involving property owners at or near the Millcreek site have been filed against Penelec and other PRPs. Penelec's insurance carriers are defending these actions but may not provide coverage in the event compensatory damages are awarded. In addition, claims have also been made for punitive damages which may not be covered by insurance.
Penelec has been named as a PRP along with over 1,000 other PRPS at the Jack's Creek/Sitken site in Mifflin County, Pennsylvania. A PRP group has been formed and is working on the issues presented at the site.
Penelec, together with 24 others, has been named as a third party defendant in an action commenced under the CERCLA by the EPA in the U.S. District Court in Ohio. The EPA is seeking to recover costs for the cleanup of hazardous and toxic materials disposed at the New Lyme landfill site in Ashtabula, Ohio. Penelec, together with 22 others, has also been named as a third party defendant in an action under CERCLA by the State of Ohio seeking to recover costs it has incurred and will incur in the future at the New Lyme landfill site.
Met-Ed, together with 35 others, has been named as a third party defendant in an action commenced under CERCLA by the EPA in the U.S. District Court for the Eastern District of Pennsylvania. The EPA is seeking to recover response costs for hazardous materials disposed at the Mabry/Oswald Site in Upper Macungie and Longswamp Townships, Pennsylvania. Met-Ed is awaiting Court approval of a buyout settlement offer.
The ultimate cost of remediation of these sites will depend upon changing circumstances as site investigations continue, including (a) the technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the GPU System companies.
The Corporation and the 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 has the necessary nonexclusive primary franchise (charter rights granted by the state) and with minor and unimportant exceptions, the necessary secondary franchises (consents by municipalities to occupy the streets), free from unduly burdensome restrictions and perpetual as to time, to enable it to maintain and operate its existing facilities for the transmission and supply of electricity in the various municipalities in which these services are now supplied, except that (a) the right to maintain and operate these facilities in the streets of certain of the municipalities, although good, rests as against those municipalities on estoppel and not on a grant of a secondary franchise and (b) the secondary franchise granted by the Borough of Boyertown 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.
The electric franchise rights of Penelec which are generally nonexclusive, consist generally of (a) charter rights to furnish electric service, and (b) certificates of public convenience and/or "grandfather rights," which allow Penelec to furnish electric service in a specified city, borough, town or township or part thereof. Such electric franchises are unlimited as to time, except in a few relatively minor cases concerning the rights mentioned above. 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 NYSEG 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 28, 1995, the GPU System had 10,534 full-time employees (JCP&L's, Met-Ed's, Penelec's and all other companies' shares are 3,050, 2,028, 2,993 and 2,463, respectively). 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, 1994, the generating stations of the GPU System had an aggregate effective capability of 6,651,000 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 Met-Ed 1951-1953 241,000 Seward Penelec 1950-1957 196,000 Warren Penelec 1948-1949 82,000
NUCLEAR: TMI-1(d) All 1974 786,000 Oyster Creek(e) JCP&L 1969 610,000
GAS/OIL-FIRED: (gas or oil) Sayreville(f) JCP&L 1930-1958 229,000 Gilbert JCP&L 1930-1949 117,000 Combustion (gas or oil) Turbines(g) ALL 1960-1989 1,160,000 Werner (oil) JCP&L 1953 58,000 Other(h) ALL 1968-1977 328,000 Hydroelectric(i) Met-Ed/Penelec 1905-1969 64,000
PUMPED STORAGE:(j) Yards Creek JCP&L 1965 190,000 Seneca Penelec 1969 87,000 TOTAL 6,651,000
Aggregate Effective Capability by Subsidiary
Net KW (Summer) (Winter) JCP&L 2,765,000 3,130,000 Met-Ed 1,602,000 1,703,000 Penelec 2,284,000 2,365,000 TOTAL 6,651,000 7,198,000
(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) Jointly owned by JCP&L, Met-Ed and Penelec in percentages of 25%, 50% and 25%, respectively.
(e) Effective January 17, 1995, the Oyster Creek station was rerated at 619 MW.
(f) Effective February 1, 1994, 84,000 KW of capability were retired.
(g) JCP&L - 762,000 KW, Met-Ed - 266,000 KW and Penelec 132,000 KW.
(h) Consists of internal combustion and combined cycle units (JCP&L - 320,000 KW, Met-Ed - 2,000 KW and Penelec - 6,000 KW). Effective January 1, 1995, JCP&L retired 30,000 KW at its Gilbert station.
(i) Consists of Met-Ed's York Haven facility (19,000 KW) and Penelec's Piney (27,000 KW) and Deep Creek facilities (18,000 KW).
(j) Represents the Subsidiaries' undivided interests in these stations which are net users rather than net producers of electric energy.
All the GPU System's coal-fired, hydroelectric (other than the Deep Creek station) and pumped storage stations (other than the Yards Creek station) are located in Pennsylvania. The TMI-1 nuclear station is also located in Pennsylvania. The GPU System's gas-fired and oil-fired stations (other than some combustion turbines in Pennsylvania), the Yards Creek pumped storage station and the Oyster Creek nuclear station are located in New Jersey. The Deep Creek hydroelectric station is located in Maryland.
Substantially all of the Subsidiaries' properties are subject to the lien of their respective first mortgage bond indentures.
The peak loads of the GPU System and its Subsidiaries were as follows:
(In KW) Company Date Peak Load
GPU July 9, 1993 8,533,000 JCP&L July 9, 1993 4,564,000 Met-Ed July 20, 1994 2,000,000 Penelec Jan. 18, 1994 2,514,000
Nonutility Generation Facilities
At December 31, 1994, EI had ownership interests through special-purpose subsidiaries in natural gas-fired cogeneration facilities with an aggregate capability of 932,000 KW as follows:
Name of Year of EI Equity Facility Location Installation Total KW Interest (KW)
Selkirk NY 1992/94 350,000 70,000 Lake* FL 1993 112,000 56,000 Pasco* FL 1993 112,000 56,000 Onondaga* NY 1994 80,000 40,000 Syracuse* NY 1992 80,000 26,400 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 1988 24,000 12,000 932,000 327,990
* EI has operating responsibility for these plants.
Transmission and Distribution System
At December 31, 1994, the GPU System owned the following: GPU System JCP&L Met-Ed Penelec Total Transmission and Distribution Substations 297 295 469 1,061
Aggregate Installed Transformer Capacity of Substations (in kilovoltamperes - KVA) 22,039,652 11,645,925 16,012,505 49,698,082
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 232 356 1,325 1,913 69 KV, 46 KV and 34.5 KV 1,752 478 364 2,594 Total 2,572 1,408 2,734 6,714
Distribution System:
Line Transformer Capacity (KVA) 9,450,169 5,528,937 6,077,980 21,057,086
Pole Miles of Overhead Lines 15,519 12,613 22,436 50,568
Trench Miles of Underground Cable 6,484 1,943 1,752 10,179
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to Nuclear Facilities - TMI-2, Rate Proceedings and Environmental Matters under Item 1 and to Note 1 to 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's, Met-Ed's and Penelec's outstanding common stock is owned by GPU. During 1994, JCP&L, Met-Ed and Penelec paid GPU $100 million, $35 million and $65 million in dividends, respectively, on their common stock.
In accordance with the Subsidiaries' mortgage indentures, as supplemented, the balances of retained earnings at December 31, 1994 that is 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 28, 1995, there were approximately 48,000 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 1994 and 1993 are set forth below.
Common Stock
Dividends Declared Price Ranges* 1994 1993 1994 1993 Quarter High/Low High/Low
April $.45 $.40 First $30 7/8 $27 5/8 $30 1/4 $25 3/4 June .45 .425 Second 31 5/8 26 32 3/8 28 5/8 October .45 .425 Third 27 1/2 23 3/4 34 3/4 31 5/8 December .45 .425 Fourth 26 7/8 24 34 28 3/4
* Based on New York Stock Exchange Composite Transactions as reported in the Wall Street Journal.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
See page for 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 page 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 page 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 6 of GPU's Proxy Statement for the 1995 Annual Meeting of Stockholders. The current directors of JCP&L, Met-Ed/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) 62 Chairman of the Board 1986 and Chief Executive Officer D. Baldassari (b) 45 President 1982 R. C. Arnold (c) 57 Director 1989 J. G. Graham (d) 56 Vice President and Chief 1986 Financial Officer M. P. Morrell (e) 46 Vice President 1993 G. E. Persson (f) 63 Director 1983 D. W. Myers (g) 50 Vice President and Comptroller 1994 S. C. Van Ness (h) 61 Director 1983 S. B. Wiley (i) 65 Director 1982
Year First Elected Met-Ed/Penelec: Met-Ed Penelec J. R. Leva (a) 62 Chairman of the Board 1992 1992 and Chief Executive Officer F. D. Hafer (j) 53 President 1978 1994 J. G. Graham (d) 56 Vice President and 1986 1986 Chief Financial Officer J. F. Furst (k) 48 Vice President 1994 1994 G. R. Repko (l) 49 Vice President 1994 1993 R. S. Zechman (m) 51 Vice President 1994 1994 R. C. Arnold (c) 57 Director 1989 1989
(a) Mr. Leva is also Chairman, President, Chief Executive Officer and a director of GPUSC; Chairman of the Board and a director of GPUN; and Chairman and a director of Energy Initiatives, Inc. (EI), and EI Power, Inc. (EI Power), all subsidiaries of GPU. Prior to 1992, Mr. Leva served as President of JCP&L since 1986. Mr. Leva is also a director of Chemical Bank, NJ, N.A., Princeton Bank and Trust Co., N.A. and Utilities Mutual Insurance Company.
(b) Mr. Baldassari was elected a director of GPUSC and GPUN in 1992. Prior to that, Mr. Baldassari served as Vice President - Materials & Services of JCP&L since 1990. He also served as Vice President - Rates of JCP&L from 1982 to 1990. Mr. Baldassari is also a director of First Morris Bank of Morristown, NJ.
(c) Mr. Arnold was elected Executive Vice President-Power Supply of GPUSC in 1990. He is also a director of GPUSC.
(d) Mr. Graham was elected 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 EI and EI Power.
(e) Mr. Morrell became Vice President - Regulatory and Public Affairs in 1994. Prior to 1993, Mr. Morrell served as Vice President of GPU since 1989.
(f) Mrs. Persson is owner and President of Business Dynamics Associates of Red Bank, NJ. Prior to that, she was owner and operator of a family-owned business in Little Silver and Farmingdale, NJ since 1965. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College.
(g) Mr. Myers, prior to 1994, served as Vice President and Treasurer of GPU, GPUSC, JCP&L and Met-Ed/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 July 1990. Prior to that, he was affiliated with the law firm of Jamison, McCardell, Moore, Peskin and Spicer of Princeton, NJ since 1983. He also served as Commissioner of the Department of the Public Advocate, State of New Jersey, from 1974 to September 1982. Mr. Van Ness is a director of The Prudential Insurance Company of America.
(i) Mr. Wiley has been a partner in the law firm of Wiley, Malehorn and Sirota of Morristown, NJ since 1973. He is also Chairman of First Morris Bank of Morristown, NJ.
(j) Mr. Hafer is also a director of GPUSC and GPUN and a director of Meridian Bancorp of Reading, PA and Utilities Mutual Insurance Company.
(k) Mr. Furst was elected Vice President - Rates & Marketing of Met- Ed/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/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/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 Subsidiary companies are elected at their respective annual meeting 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 Subsidiary companies.
Identification of Executive Officers
The executive officers of GPU, JCP&L and Met-Ed/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) 62 Chairman, President and Chief 1992 Executive Officer I. H. Jolles (b) 56 Senior Vice President and General 1990 Counsel J. G. Graham (c) 56 Senior Vice President and Chief 1987 Financial Officer F. A. Donofrio (d) 52 Vice President, Comptroller and 1985 Chief Accounting Officer P. C. Mezey (e) 55 Senior Vice President, GPUSC 1992 T. G. Howson (f) 46 Vice President and Treasurer 1994 M. A. Nalewako (g) 60 Secretary 1988 P. R. Clark (h) 64 President, GPUN 1983 R. L. Wise (i) 51 President, Fossil Generation-GPUSC 1994 F. D. Hafer (j) 53 President, Met-Ed/Penelec 1994 D. Baldassari (k) 45 President, JCP&L 1992 B. L. Levy (l) 39 President and Chief Executive 1991 Officer, EI R. C. Arnold (m) 57 Executive Vice President, GPUSC 1990
JCP&L: J. R. Leva (a) 62 Chairman of the Board and Chief 1992 Executive Officer D. Baldassari (k) 45 President 1992 C. R. Fruehling 59 Vice President - Engineering and 1982 Operations J. G. Graham (c) 56 Vice President and Chief 1987 Financial Officer E. J. McCarthy (n) 56 Vice President - Customer Operations 1982 and Sales M. P. Morrell (o) 46 Vice President - Regulatory 1993 and Public Affairs T. G. Howson (f) 46 Vice President and Treasurer 1994 D. W. Myers (p) 50 Vice President - Operations Support 1994 and Comptroller R. J. Toole 52 Vice President - Generation 1990 J. J. Westervelt (q) 54 Vice President - Human Resources 1982 and Corporate Services R. S. Cohen 52 Secretary and Corporate Counsel 1986
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 9 through 18 of GPU's Proxy Statement for the 1995 Annual Meeting of Stockholders. The following table sets forth remuneration paid to the Chief Executive Officer and the four most highly compensated executive officers of JCP&L, Met-Ed and Penelec for the year ended December 31, 1994.
As discussed in Item 1 under Corporate Realignment, the managements of Met-Ed and Penelec were combined in 1994. Accordingly, the amounts shown below represent the aggregate remuneration paid to such executive officers by Met-Ed and Penelec during 1994. In addition, Mr. Toole's remuneration includes an amount paid by Met-Ed and JCP&L during the year.
Remuneration of Executive Officers
SUMMARY COMPENSATION TABLE Long-Term Compensation Annual Compensation Awards Other Name and Annual Restricted All Other Principal Compen- Stock/Unit Compen- Position Year Salary Bonus sation(1) Awards(2) sation
J. R. Leva Chairman of the Board and Chief Executive Officer (3) (3) (3) (3) (3) (3)
JCP&L: D. Baldassari 1994 $271,250 $62,000 $ 17 $39,188 $16,823(4) President 1993 253,750 57,000 - 41,850 15,436 1992 211,480 50,000 - 35,100 14,177
M. P. Morrell 1994 150,175 27,300 804 15,936 6,000(5) Vice President - 1993 144,200 26,000 1,932 15,500 5,768 Regulatory and 1992 137,500 24,900 1,166 14,560 5,267 Public Affairs
D. W. Myers 1994 142,125 29,300 - 13,716 5,685(6) Vice President - 1993 135,125 22,400 - 13,950 5,405 Operations Support 1992 129,925 25,000 - 14,300 5,197 and Comptroller
E. J. McCarthy 1994 136,267 26,100 - 13,324 5,451(7) Vice President - 1993 125,825 22,500 - 13,020 5,033 Customer Operations 1992 121,125 19,100 - 13,000 4,845 and Sales
R. S. Cohen 1994 127,225 22,800 - 12,018 5,089(8) Secretary and 1993 122,500 19,500 - 12,710 4,902 Corporate Counsel 1992 117,950 18,600 - 13,000 4,718
Met-Ed/Penelec: F. D. Hafer 1994 275,250 77,000 - 39,841 19,733(9) President 1993 258,250 50,000 - 41,850 18,975 1992 246,250 40,000 - 41,600 18,375
J. G. Herbein 1994 148,025 34,000 - 14,238 9,861(10) Vice President - 1993 142,200 25,900 - 15,190 15,338 Generation 1992 136,500 22,100 743 15,340 10,507
G. R. Repko 1994 142,225 32,000 - 14,630 5,689(11) Vice President - 1993 129,100 24,200 - 13,330 5,164 Customer Services 1992 120,900 19,200 - 13,520 4,836 and Operations
R. J. Toole 1994 142,125 30,100 - 13,716 5,685(12) Vice President - 1993 136,750 21,000 - 13,950 5,470 Generation 1992 131,875 17,100 - 13,520 5,275
R. S. Zechman 1994 132,500 31,000 - 13,324 5,300(13) Vice President - 1993 118,750 17,000 - 12,400 4,750 Administration 1992 113,750 12,500 - 12,480 4,550 and Finance
D. L. O'Brien 1994 129,750 23,000 548 12,018 1,238(14) Comptroller 1993 124,750 16,500 1,161 12,400 1,187 1992 119,750 12,500 598 13,000 1,137
(1) "Other Annual Compensation" is composed entirely of the above-market interest accrued on the preretirement portion of deferred compensation.
(2) Number and value of aggregate restricted shares/units at the end of 1994 (dividends are paid or accrued on these restricted shares/units and reinvested): Aggregate Aggregate Shares/Units $ Value JCP&L: D. Baldassari 5,000 $134,302 M. P. Morrell 2,520 65,284 D. W. Myers 2,285 59,192 E. J. McCarthy 2,190 56,588 R. S. Cohen 2,140 55,202
Met-Ed/Penelec: F. D. Hafer 7,075 182,129 J. G. Herbein 2,535 65,444 G. R. Repko 2,270 58,724 R. J. Toole 2,355 60,721 R. S. Zechman 2,105 54,439 D. L. O'Brien 2,090 53,981
(3) As noted above, Mr. Leva is Chairman and Chief Executive Officer of General Public Utilities Corporation and its affiliates. 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 13 through 15 in GPU's 1995 Proxy Statement, which are incorporated herein by reference.
(4) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($4,850), the benefit of interest-free use of the non- term portion of employer paid premiums for split-dollar life insurance ($5,956) and above-market interest accrued on the retirement portion of deferred compensation ($17).
(5) Consists of employer matching contributions under the Savings Plan ($6,000).
(6) Consists of employer matching contributions under the Savings Plan ($5,685).
(7) Consists of employer matching contributions under the Savings Plan ($5,451).
(8) Consists of employer matching contributions under the Savings Plan ($5,089).
(9) Consists of employer matching contributions under the Savings Plan ($6,000), matching contributions under the non-qualified deferred compensation plan ($5,010), the benefit of interest-free use of the non- term portion of employer paid premiums for split-dollar life insurance ($8,630) and above-market interest accrued on the retirement portion of deferred compensation ($93).
(10) Consists of employer matching contributions under the Savings Plan ($4,661) and above-market interest accrued on the retirement portion of deferred compensation ($5,200).
(11) Consists of employer matching contributions under the Savings Plan ($5,689).
(12) Consists of employer matching contributions under the Savings Plan ($5,685).
(13) Consists of employer matching contributions under the Savings Plan ($5,300).
(14) Consists of employer matching contributions under the Savings Plan ($1,238).
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 premium to the projected date the premiums will be refunded to the Corporation. Prior years' amounts have been restated.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Estimated future payouts under nonstock price- based plans(1) Performance Number of or other shares, period until units or maturation Target Name other rights or payout ( $ or #) JCP&L: D. Baldassari 1,500 5 years $35,438 M. P. Morrell 610 5 years $14,411 D. W. Myers 525 5 years $12,403 E. J. McCarthy 510 5 years $12,049 R. S. Cohen 460 5 years $10,868
Met-Ed/Penelec: F. D. Hafer 1,525 5 years $36,028 J. G. Herbein 545 5 years $12,876 G. R. Repko 560 5 years $13,230 R. J. Toole 525 5 years $12,403 R. S. Zechman 510 5 years $12,049 D. L. O'Brien 460 5 years $10,868
(1) The 1990 Stock Plan for Employees of General Public Utilities Corporation and Subsidiaries also provides for a Performance Cash Incentive Award in the event that the annualized GPU Total Shareholder Return exceeds the annualized Industry Total Return (Edison Electric Institute's Investor- Owned Electric Utility Index) for the period between the award and vesting dates. These payments are designed to compensate recipients of restricted stock/unit awards for the amount of federal and state income taxes that will be payable upon the restricted stock/units that are vesting for the recipient. The amount is computed by multiplying the applicable gross-up percentage by the amount of gross income the recipient recognizes for federal income tax purposes when the restrictions lapse. The estimated amounts above are computed based on the number of restricted units awarded for 1994 multiplied by the 1994 year-end market value of $26.25. Actual payments would be based on the market value of GPU common stock at the time the restrictions lapse and may be different from those indicated above.
Proposed Remuneration of Executive Officers
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 annual compensation as defined below. Under federal law, an employee's pension benefits that may be paid from a qualified trust under a qualified pension plan such as the GPU System plans are subject to certain maximum amounts. The GPU System companies also have adopted 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 from funded and unfunded sources resulting from employer contributions to the qualified trust and direct payments payable upon retirement in 1995 (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 Base Salary, Deferred Compensation and Incentive Compensation Plan awards. The career average compensation amounts for the following named executive officers differ by more than 10% from the three year average annual compensation set forth in the Summary Compensation Table and are as follows: JCP&L: Messrs. Baldassari - $158,239; Morrell - $122,625; Myers - $141,733; McCarthy - $120,292; Cohen - $107,124 and Met-Ed/Penelec: Messrs. Hafer - $238,121; Herbein - $134,432; Repko - $121,220; Toole - $121,095; Zechman - $103,287; O'Brien - $115,985.
(2) Years of Creditable Service: JCP&L: Messrs. Baldassari - 22 years; Morrell - 23 years; Myers - 14 years; McCarthy - 34 years; Cohen - 26 years and Met-Ed/Penelec: Messrs. Hafer - 32 years; Herbein - 29 years; Repko - 28 years; Toole - 28 years; Zechman - 25 years; O'Brien - 22 years.
(3) Based on an assumed retirement at age 65 in 1995. To reduce the above amounts to reflect a retirement benefit assuming a continual annuity to a surviving spouse equal to 50 percent of the annuity payable at retirement, multiply the above benefits by 90 percent. The estimated annual benefits are not subject to any reduction for Social Security benefits or other offset amounts.
(4) Annual retirement benefit cannot exceed 55 percent of the average compensation received during the last three years prior to retirement.
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 8 of the GPU Proxy Statement for the 1995 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, 1995, the beneficial ownership of equity securities of each of the Company's directors and each of the executive officers named in the Company's Summary Compensation Table, and of all directors and officers of the Company as a group. The shares owned by all directors and executive officers as a group constitute less than 1% of the total shares outstanding.
Title of Amount and Nature of Name Class Beneficial Ownership (1) JCP&L: J. R. Leva GPU Common Stock 4,170 Shares - Direct GPU Common Stock 100 Shares - Indirect J. G. Graham GPU Common Stock 6,626 Shares - Direct GPU Common Stock 1,480 Shares - Indirect R. C. Arnold GPU Common Stock 6,003 Shares - Direct D. Baldassari GPU Common Stock 1,009 Shares - Direct R. S. Cohen GPU Common Stock 970 Shares - Direct E. J. McCarthy GPU Common Stock 958 Shares - Direct M. P. Morrell GPU Common Stock 1,071 Shares - Direct D. W. Myers GPU Common Stock 959 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 26,427 Shares - Direct Officers as a Group GPU Common Stock 1,580 Shares - Indirect
Met-Ed/Penelec: J. R. Leva GPU Common Stock 4,170 Shares - Direct GPU Common Stock 100 Shares - Indirect J. G. Graham GPU Common Stock 6,626 Shares - Direct GPU Common Stock 1,480 Shares - Indirect R. C. Arnold GPU Common Stock 6,003 Shares - Direct J. F. Furst GPU Common Stock 746 Shares - Direct GPU Common Stock 1,363 Shares - Indirect F. D. Hafer GPU Common Stock 4,470 Shares - Direct GPU Common Stock 116 Shares - Indirect J. G. Herbein GPU Common Stock 1,144 Shares - Direct G. R. Repko GPU Common Stock 958 Shares - Direct R. J. Toole GPU Common Stock 1,776 Shares - Direct R. S. Zechman GPU Common Stock 895 Shares - Direct D. L. O'Brien GPU Common Stock 920 Shares - Direct
All Directors and GPU Common Stock 29,886 Shares - Direct Officers as a Group GPU Common Stock 3,059 Shares - Indirect
(1) The number of shares owned and the nature of such ownership, not being within the knowledge of the Company, have been furnished by each individual.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) See page for reference to Financial Statement Schedules required by this item.
1. Exhibits:
3-A GPUSC By-Laws, as amended.
4-A First Amendment to the Credit Agreement dated November 1, 1994 between GPU, JCP&L, Met-Ed and Penelec; Chemical Bank and Citibank, N.A. as co-agents; and Chemical Bank as administrative agent incorporated by reference to Exhibit B-1(a) pursuant to Rule 24 Certificate for SEC File No. 70-7926.
4-B Subordinated Debenture Indenture of Penelec dated as of July 1, 1994 incorporated by reference to Exhibit No. A-8(a) pursuant to Rule 24 Certificate for SEC File No. 70-8403.
4-C Subordinated Debenture Indenture of Met-Ed dated as of August 1, 1994 incorporated by reference to Exhibit No. A-8(a) pursuant to Rule 24 Certificate for SEC File No. 70-8401.
10-A General Public Utilities Corporation Restricted Stock Plan for Outside Directors
10-B Retirement Plan for Outside Directors of General Public Utilities Corporation
10-C Deferred Remuneration Plan for Outside Directors of General Public Utilities Corporation
12 Statements Showing Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
A - Jersey Central Power & Light Company B - Metropolitan Edison Company C - Pennsylvania Electric Company
21 Subsidiaries of the Registrant
A - Metropolitan Edison Company B - Pennsylvania Electric Company
23 Consent of Independent Accountants
A - General Public Utilities Corporation B - Jersey Central Power & Light Company C - Metropolitan Edison Company D - Pennsylvania Electric Company
27 Financial Data Schedule
A - General Public Utilities Corporation B - Jersey Central Power & Light Company C - Metropolitan Edison Company D - Pennsylvania Electric Company
(b) Reports on Form 8-K:
None.
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 9, 1995 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 9, 1995 J. R. Leva, Chairman (Chief Executive Officer) President and Director
/s/ J. G. Graham March 9, 1995 J. G. Graham, Senior Vice President (Chief Financial Officer)
/s/ F. A. Donofrio March 9, 1995 F. A. Donofrio, Vice President and Comptroller (Chief Accounting Officer)
/s/ L. J. Appell, Jr. March 9, 1995 L. J. Appell, Jr., Director
/s/ D. J. Bainton March 9, 1995 D. J. Bainton, Director
/s/ T. H. Black March 9, 1995 T. H. Black, Director
/s/ T. B. Hagen March 9, 1995 T. B. Hagen, Director
/s/ H. F. Henderson, Jr. March 9, 1995 H. F. Henderson, Jr., Director
/s/ J. M. Pietruski March 9, 1995 J. M. Pietruski, Director
/s/ C. A. Rein March 9, 1995 C. A. Rein, Director
/s/ P. R. Roedel March 9, 1995 P. R. Roedel, Director
/s/ C. A. H. Trost March 9, 1995 C. A. H. Trost, Director
/s/ P. K. Woolf March 9, 1995 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 9, 1995 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 9, 1995 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ D. Baldassari March 9, 1995 D. Baldassari, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 9, 1995 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. W. Myers March 9, 1995 D. W. Myers, Vice President-Comptroller (Principal Accounting Officer) and Director
/s/ R. C. Arnold March 9, 1995. R. C. Arnold, Director
/s/ M. P. Morrell March 9, 1995 M. P. Morrell, Vice President and Director
/s/ G. E. Persson March 9, 1995 G. E. Persson, Director
/s/ S. C. Van Ness March 9, 1995 S. C. Van Ness, Director
/s/ S. B. Wiley March 9, 1995 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 9, 1995 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 9, 1995 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ F. D. Hafer March 9, 1995 F. D. Hafer, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 9, 1995 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. L. O'Brien March 9, 1995 D. L. O'Brien, Comptroller (Principal Accounting Officer)
/s/ J. F. Furst March 9, 1995 J. F. Furst, Vice President and Director
/s/ G. R. Repko March 9, 1995 G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 9, 1995 R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 9, 1995 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 9, 1995 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 9, 1995 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ F. D. Hafer March 9, 1995 F. D. Hafer, President (Principal Operating Officer) and Director
/s/ J. G. Graham March 9, 1995 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ D. L. O'Brien March 9, 1995 D. L. O'Brien, Comptroller (Principal Accounting Officer)
/s/ J. F. Furst March 9, 1995 J. F. Furst, Vice President and Director
/s/ G. R. Repko March 9, 1995 G. R. Repko, Vice President and Director
/s/ R. S. Zechman March 9, 1995 R. S. Zechman, Vice President and Director
/s/ R. C. Arnold March 9, 1995 R. C. Arnold, Director
Exhibit 12 Page 1 of 2
Exhibit 12 Page 2 of 2
JERSEY CENTRAL POWER & LIGHT COMPANY STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503 (In Thousands)
NOTES:
(A) The Company has included the equivalent of the interest portion of all rentals charged to income as fixed charges for this statement and has excluded such components from Operating Expenses.
(B) Represents income before provision for income taxes divided by income before cumulative effect of accounting change as follows:
Exhibit 12 Page 1 of 2
Exhibit 12 Page 2 of 2
METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503 (In Thousands)
NOTES:
(A) The Company included the equivalent of the interest portion of all rentals charged to income as fixed charges for this statement and has excluded such components from Operating Expenses.
(B) Includes dividends as preferred securities of subsidiary of $3,200.
(C) Represents income before provisions for income taxes divided by income before cumulative effect of accounting change as follows:
Twelve Months Ended December 31, December 31, December 31, December 31, 1990 1991 1992 1993
Income before provisions for income taxes $136 798 $ 73 443 $122 492 $124 923
Income before cumulative effect of accounting changes 93 191 47 400 73 077 77 875
For the twelve months ended December 31, 1994, the ratio was based on the composite income tax rate for 1994.
Exhibit 12 Page 1 of 2
Exhibit 12 Page 2 of 2
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503 (In Thousands)
Notes:
(A) The Company has included the equivalent of the interest portion of all rentals charged to income as fixed charges for this statement and has excluded such components from Operating Expenses.
(B) Includes dividends on preferred securities of subsidiary of $4,492.
(C) Represents income before provision for income taxes divided by income before cumulative effect of accounting change as follows:
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, 1994, 1993 and 1992 Balance Sheets as of December 31, 1994 and 1993 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1992-1994
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, 1994, 1993 and 1992 Balance Sheets as of December 31, 1994 and 1993 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 Statement of Capital Stock as of December 31, 1994 Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 Statement of Long-Term Debt as of December 31, 1994 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1992-1994
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, 1994, 1993 and 1992 Balance Sheets as of December 31, 1994 and 1993 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 Statement of Capital Stock and Preferred Securities as of December 31, 1994 Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 Statement of Long-Term Debt as of December 31, 1994 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1992-1994
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, 1994, 1993 and 1992 Balance Sheets as of December 31, 1994 and 1993 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 Statement of Capital Stock and Preferred Securities as of December 31, 1994 Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 Statement of Long-Term Debt as of December 31, 1994 Notes to Financial Statements
Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts for the Years 1992-1994
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Financial Statements or Notes thereto.
General Public Utilities Corporation and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings per share were $1.42 compared to $2.65 per share in 1993 and net income decreased $132 million to $163.7 million. The 1994 earnings decrease was principally attributable to a second quarter write-off of $104.9 million after-tax ($0.91 per share) from an unfavorable Pennsylvania Commonwealth Court order disallowing the collection of revenues for certain Three Mile Island Unit 2 (TMI-2) retirement costs, a $76.1 million after-tax ($0.66 per share) charge to earnings for costs related to the Voluntary Enhanced Retirement Programs, and a $10.6 million after-tax ($0.09 per share) write-off of postretirement benefit costs not considered likely to be recovered through ratemaking. The effect of these charges was partially offset by first quarter interest income of $26.9 million after-tax ($0.23 per share) from refunds of previously paid federal income taxes related to the tax retirement of TMI-2. Net income for 1994 would have been $328.4 million, or $2.85 per share, if not for these nonrecurring events.
Earnings were positively affected by an increase in sales resulting primarily from growth in the number of customers and colder winter weather as compared to last year, and an increase in 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. GPU's return on average common equity was 6.3% for 1994 compared to 11.9% for 1993.
Net income for 1993 was $295.7 million, or $2.65 per share, compared to $251.6 million, or $2.27 per share in 1992. Earnings in 1993 benefited primarily from the February 1993 retail base rate increase at JCP&L and higher customer sales due primarily to the significantly warmer summer temperatures as compared to the mild weather in 1992. These gains were partially offset by increases in other O&M expense, the write-off of $15.4 million after-tax ($0.14 per share) of costs related to the cancellation of proposed power supply and transmission facilities agreements and increased depreciation expense associated with additions to utility plant. Earnings in 1992 were negatively affected primarily by a reduction in weather-related sales and increased capital costs, partially offset by increased revenues from new residential and commercial customers.
OPERATING REVENUES: Revenues increased 1.5% to $3.65 billion in 1994 after increasing 4.7% to $3.6 billion in 1993. The components of these changes are as follows:
General Public Utilities Corporation and Subsidiary Companies
(In Millions) 1994 1993
Kilowatt-hour (KWH) revenues $ 30.6 $ 61.0 (excluding energy portion) Rate increases 20.8 108.7 Energy revenues (.9) (24.1) Other revenues 2.9 16.3 Increase in revenues $ 53.4 $161.9
Kilowatt-hour revenues
The increase in KWH revenues was principally due to increases in sales resulting from new customer additions in the residential and commercial sectors, and the colder winter weather as compared to last year.
KWH revenues increased primarily due to higher third quarter sales in the JCP&L service territory resulting from the significantly warmer summer temperatures as compared to the milder weather during the same period in 1992. An increase in weather-related sales in the Metropolitan Edison Company (Met- Ed) service territory, a 1.2% increase in the average number of customers and a slight increase in nonweather-related usage also contributed to the increase in KWH revenues. New customer growth, which occurred in the commercial and residential sectors, was partially offset by a slight reduction in the number of industrial customers.
1994 MWH Customer Sales by Service Class
Residential 36% Commercial 32% Industrial/Other 32%
Rate increases
In February 1993, the New Jersey Board of Public Utilities (NJBPU) authorized a $123 million increase in JCP&L's retail base rates, or approximately 7% annually.
Energy revenues
1994 and 1993 Changes in energy revenues do not affect net income as they reflect corresponding changes in the energy cost rates billed to customers and expensed. The 1993 decrease in energy revenues was principally due to lower electric sales to other utilities as compared to 1992 when the GPU System experienced a significant increase in sales to other utilities.
General Public Utilities Corporation and Subsidiary Companies
Other revenues
1994 and 1993 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. However, earnings in 1993 were favorably affected by a one-time benefit from the recognition of prior period transmission service revenues approved by the Pennsylvania Public Utility Commission (PaPUC).
OPERATING EXPENSES: Power purchased and interchanged
1994 and 1993 Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings since these cost increases are substantially recovered through the Subsidiaries' energy clauses. However, earnings for 1994 and 1993 were favorably affected by a reduction in reserve capacity expense resulting from the replacement of expiring utility purchase power contracts at lower rates.
Other operation and maintenance
The increase in other O&M expense was primarily attributable to a $127 million pre-tax charge for costs related to the Voluntary Enhanced Retirement Programs. Increases were 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.
The increase in other O&M expense was largely due to emergency and storm-related activities, higher tree-trimming expenses and increased costs related to fossil plant outages.
Depreciation and amortization
The increase in depreciation and amortization expense for 1993 primarily resulted from additions to existing generating facilities to maintain system reliability and additions to the transmission and distribution system related to new customer growth.
General Public Utilities Corporation and Subsidiary Companies
Taxes, other than income taxes
1994 and 1993 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
The increase in other expense is principally related to the second quarter write-off of future TMI-2 retirement costs and postretirement benefit costs. The effect of these write-offs was partially offset by first quarter interest income resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993 PaPUC order that permitted Met-Ed to recover estimated TMI-2 retirement costs from customers. As a result, second quarter charges were taken at Met-Ed totaling $127.6 million pre-tax. Pennsylvania Electric Company (Penelec) recorded charges of $56.3 million pre-tax for its share of such costs. These charges were comprised of $169.2 million for retirement costs and $14.7 million for monitored storage costs.
Also in the second quarter of 1994, Penelec wrote off $14.6 million pre-tax in deferred postretirement benefit costs related to the adoption of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." This was a result of a Commonwealth Court decision reversing a PaPUC order that allowed a nonaffiliated utility, outside a base rate case, to defer certain postretirement benefit costs for future recovery from customers. Penelec had deferred such costs under a similar accounting order issued by the PaPUC. In addition, Penelec recognized a $4 million pre-tax charge for the remaining transition obligation related to postretirement benefit costs for the employees who participated in the Voluntary Enhanced Retirement Programs.
The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. The effect on pre-tax earnings was an increase of $59.4 million in interest income.
The reduction in other income is principally due to the write-off of $24.7 million pre-tax of costs related to the cancellation of proposed power supply and transmission facilities agreements between the Subsidiaries and Duquesne Light Company. The decrease is also due to the absence of carrying charges on certain tax payments made by JCP&L in 1992 that are now being recovered through rates.
General Public Utilities Corporation and Subsidiary Companies
INTEREST CHARGES AND PREFERRED DIVIDENDS: 1994 and 1993 Other interest expense was higher in 1994 due primarily to the tax retirement of TMI-2, which resulted in a $13.8 million pre-tax increase in interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken. Preferred stock dividends decreased in both years due to the redemption of $60 million and $156 million stated value of preferred stock in 1994 and 1993, respectively.
Interest on long-term debt increased in 1993 primarily due to the issuance of additional long-term debt, offset partially by decreases resulting from the refinancing of higher cost debt at lower interest rates.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Subsidiaries' capital needs were $719 million in 1994, consisting of cash construction expenditures of $586 million and amounts for maturing obligations of $133 million. During 1994, construction funds were used primarily to maintain and improve existing generation facilities and the transmission and distribution system, proceed with various clean air compliance projects, and build new generation facilities. For 1995, construction expenditures are estimated to be $482 million, consisting mainly of $384 million for ongoing system development, $57 million for clean air compliance projects, and $36 million for the continued construction of new generation facilities. The 1995 estimated reduction is largely due to the completion in 1994 of a significant portion of clean air compliance requirements and a new generation facility. Expenditures for maturing debt are expected to be $91 million for 1995, and $129 million for 1996 including amounts for mandatory redemptions of preferred stock. 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 two-thirds of the GPU System's 1995 capital needs will be satisfied through internally generated funds.
Cash Construction Expenditures (In millions of dollars)
1990 1991 1992 1993 1994 1995
$491 $467 $460 $496 $586 $482*
* Forecast
The Subsidiaries' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any time. Nuclear fuel capital leases at December 31, 1994, totaled $148 million. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $65 million annually. In the event the needed nuclear fuel cannot be leased, the associated capital requirements would have to be met by other means.
General Public Utilities Corporation and Subsidiary Companies
FINANCING: In 1994, Penelec and Met-Ed issued $205 million of Monthly Income Preferred Securities (carried on the balance sheet as Preferred securities of subsidiaries) through special-purpose finance subsidiaries, and an aggregate of $180 million principal amount of long-term debt. A portion of these proceeds was used to refinance long-term debt and redeem more costly preferred stock amounting to $64 million and $60 million, respectively. In February 1995, Penelec issued $30 million of long-term debt. The net proceeds from this issuance will be used to reduce short-term debt.
JCP&L anticipates receiving regulatory authorization in the first quarter of 1995 to issue, through a special-purpose finance subsidiary, up to $125 million of Monthly Income Preferred Securities. A portion of the JCP&L securities is expected to be issued in 1995 to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and Exchange Commission (SEC) to issue up to five million shares of additional common stock through 1996. The proceeds from the sale of such additional common stock would be used to increase the Subsidiaries' common equity ratios and reduce GPU short-term debt. GPU will monitor the capital markets as well as its capitalization ratios relative to its targets to determine whether, and when, to issue such shares.
The Subsidiaries have regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock for various periods through 1995. Under existing authorization, JCP&L, Met-Ed and Penelec may issue senior securities in the amount of $275 million, $250 million and $260 million, respectively, of which $100 million for each Subsidiary may consist of preferred stock. Met-Ed and Penelec, through their special-purpose finance subsidiaries, have remaining regulatory authority to issue an additional $25 million and $20 million, respectively, of Monthly Income Preferred Securities. The Subsidiaries also have regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
The Subsidiaries' bond indentures and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Subsidiaries may issue. As a result of the TMI-2 retirement costs write-offs, together with certain other costs recognized in the second quarter of 1994, Met-Ed will be unable to meet the interest and preferred dividend coverage requirements of its indenture and charter, respectively, until the third quarter of 1995. Therefore, Met-Ed's ability to issue senior securities through June 1995 will be limited to the issuance of FMBs on the basis of $65 million of previously issued and retired bonds. For similar reasons, Penelec has sufficient coverage to issue only approximately $49 million of FMBs through June 1995, depending on interest rates at the time
General Public Utilities Corporation and Subsidiary Companies
of issuance, plus $38 million of FMBs on the basis of previously issued and retired bonds. Penelec will be unable to meet coverage requirements for issuing preferred stock until the third quarter of 1995. The ability of Met- Ed and Penelec to issue their remaining authorized Monthly Income Preferred Securities, which have no such coverage restrictions, is not affected by these write-offs. JCP&L currently has the ability to issue $319 million of FMBs on the basis of previously issued and retired bonds and has interest and dividend coverage ratios well in excess of indenture and charter restrictions.
The GPU System's cost of capital and ability to obtain external financing is affected by the Subsidiaries' security ratings, which are periodically reviewed by the three major credit rating agencies. In June 1994, Standard & Poor's Corporation (S&P) and Duff & Phelps (D&P) lowered JCP&L's security ratings citing relatively high customer rates in an increasingly competitive environment and a perceived credit risk associated with large purchased power commitments.
Following a review that was prompted by the Commonwealth Court's order denying recovery of TMI-2 retirement costs, Moody's Investors Service (Moody's) and S&P downgraded Met-Ed and Penelec's security ratings in August 1994 citing, among other things, the Subsidiaries' weakened financial flexibility resulting from the second quarter 1994 write-offs. Though unaffected by the Court's order, JCP&L's credit ratings were reduced by Moody's due, in part Moody's said, to its relatively high cost structure. The Subsidiaries' FMBs are currently rated at an equivalent of a BBB+ or higher by the three major credit rating agencies, while the preferred stock issues and Monthly Income Preferred Securities have been assigned an equivalent of BBB or higher. In addition, the Subsidiaries' commercial paper is rated as having good to high credit quality. Although credit quality has been reduced, the Subsidiaries' credit ratings remain above investment grade.
In 1994, the 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, was revised to "stable" from "negative" for each of the Subsidiaries. The outlooks reflect S&P's judgement that the Subsidiaries have manageable construction spending, limited external financing requirements, regionally competitive rates (particularly Penelec), and an emphasis on cost cutting to offset base rate relief requirements during the next few years. Though its outlook was upgraded, S&P believed that Met-Ed risked some deterioration in its competitive position due to S&P's judgment that there are substantial purchased power-related rate recovery needs. S&P also assigned the Subsidiaries a "low average" to "average" business position, 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.
In June 1994, Moody's announced that it developed a new method to calculate the minimum price an electric utility must charge its customers in order to recover all of its generation costs. Moody's believes that an
General Public Utilities Corporation and Subsidiary Companies
assessment of relative cost position will become increasingly critical to the credit analysis of electric utilities in a competitive marketplace. Specific rating actions are not anticipated, however, until the pace and implications of utility market deregulation are more certain.
Present plans call for GPU to issue common stock and the Subsidiaries to issue long-term debt and Monthly Income Preferred Securities during the next three years to finance construction activities, make additional investments in GPU's nonregulated businesses, fund the redemption of maturing senior securities, make contributions to decommissioning trust funds and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION: The GPU System targets capitalization ratios that should warrant sufficient credit quality ratings to permit capital market access at reasonable costs. Recent evaluations of the industry by credit rating agencies indicate that the Subsidiaries may have to increase their equity ratios to maintain their current credit ratings. GPU's financing plans contemplate security issuances in 1995 to strengthen the equity component of the Subsidiaries' capital structures. The targets and actual capitalization ratios are as follows:
Target Range 1994 1993 1992 Common equity 46-49% 44% 47% 46% Preferred equity 8-10 8 5 9 Notes payable and long-term debt 46-41 48 48 45 100% 100% 100% 100%
In 1994, the quarterly dividend on common stock was increased by 5.9% to an annualized rate of $1.80 per share. Management will continue to review its dividend policy to determine how to best serve the long-term interests of shareholders.
NONREGULATED BUSINESS: Energy Initiatives, Inc. (EI), a wholly-owned subsidiary of GPU develops, owns, operates and invests in cogeneration and other nonutility power production facilities.
In 1994, EI acquired North Canadian Power, Inc. (NCP) along with partnership interests in NCP's five domestic operating projects. As of December 31, 1994, EI had twelve combined-cycle cogeneration plants in-service located in the United States and Canada totaling 932 MW of capacity and a 24 MW facility under construction expected to be completed in 1996. EI operates nine of these plants. In addition, EI is a participant in a joint venture developing a 750 MW combined-cycle plant in Barranquilla, Colombia.
General Public Utilities Corporation and Subsidiary Companies
As a result of the federal Energy Policy Act of 1992, EI has expanded its business activities to include development of exempt wholesale generation facilities in both domestic and certain international markets. EI has submitted proposals for the development of additional capacity in the United States and is pursuing development projects in Latin America and Asia, while investigating other international opportunities.
In 1994, GPU made $75 million in cash capital contributions to EI for the purpose of investing in nonutility generation projects and partnerships. Total EI investments for the year consisted of approximately $54 million for the NCP acquisition and $20 million for other capital expenditures. At December 31, 1994, GPU's net investment in EI was $111 million. The SEC has authorized GPU to invest up to an additional $200 million in EI through 1997.
Management expects that EI will be a source of future earnings growth and intends to make additional investments in the development and ownership of nonutility generation facilities to expand these business activities. The timing and amounts of these investments, however, will depend upon the development of appropriate opportunities.
COMPETITIVE ENVIRONMENT: - Recent Regulatory Actions
The electric power markets have traditionally been served by regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the continued development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of competition in Pennsylvania's electric utility industry and solicited comments on various issues. Met-Ed and Penelec jointly filed responses in November 1994 suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investments, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on Pennsylvania utilities as compared with unregulated or out-of-state suppliers. At the end of the investigation, which is expected to be concluded in early 1995, the PaPUC will decide whether to conduct a rulemaking proceeding.
In May 1994, the NJBPU approved JCP&L's request to implement a new rate initiative designed to retain and expand the economic base in its service territory. Under the contract rate service, JCP&L may enter into individual contracts to provide electric service to large commercial and industrial customers. This initiative will allow JCP&L more flexibility in responding to competitive pressures.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking regarding the recovery by utilities of legitimate and verifiable stranded costs. Costs incurred by a utility to
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provide integrated electric service to a franchise customer become stranded when that customer subsequently purchases power from another supplier using the utility's transmission services. Among other things, the FERC proposed that utilities be allowed under certain circumstances to recover such stranded costs associated with existing wholesale customer contracts, but not under new wholesale contracts unless expressly provided for in the contract. While it stated a "strong" policy preference that state regulatory agencies address recovery of stranded retail costs, the FERC also set forth alternative proposals for how it would address the matter if the states failed to do so. Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of Appeals for the District of Columbia, in an unrelated case, questioned the FERC's authority to permit utilities to recover stranded costs. The Court remanded the matter to the FERC for it to conduct an evidentiary hearing in the case to determine whether, among other things, permitting stranded cost recovery was so inherently anticompetitive that it violates antitrust laws. While largely supported by the electric utility industry, the Proposed Rulemaking has been strongly opposed by other groups. There can be no assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing for electric transmission services. The policy statement contains five principles that will provide the foundation for the FERC's analyses of all subsequent transmission rate proposals. Recognizing the evolution of a more competitive marketplace, the FERC contends that it is critical that transmission services be priced in a manner that appropriately compensates transmission owners and creates adequate incentives for efficient system expansion.
In November 1994, the NJBPU issued a draft New Jersey Energy Master Plan Phase I Report promoting regulatory policy changes intended to move the state's electric and gas utilities into a competitive marketplace. In the draft, the NJBPU recommends, among other things, the adoption of 1) rate- flexibility legislation to allow utilities to compete in order to retain and attract customers; 2) alternatives to rate base/rate-of-return regulation; 3) consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities; and 4) an integrated resource planning and competitive supply-side procurement process to streamline the regulatory review process, lower costs, and ensure that the state's environmental and energy conservation goals are met in a competitive marketplace. Although the NJBPU proposes actions and regulatory reforms that encourage competition, the draft Plan calls for an evolutionary transition toward open markets. The recommendations are largely intended to be interim measures while the NJBPU investigates other issues, including retail wheeling and stranded costs, that are likely to affect the future of the electric utility industry. The New Jersey Energy Master Plan is being developed in three phases, with Phase I scheduled to be adopted in March 1995 and the remaining phases expected to be concluded by year-end 1995.
In 1994, the SEC issued for public comment a Concept Release regarding modernization of the Public Utility Holding Company Act of 1935 (Holding Company Act). GPU regards the Holding Company Act as a significant impediment
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to competition and supports its repeal. In addition, GPU believes that the Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally reformed given the burdens being placed on electric utilities by PURPA mandated uneconomic long-term power purchase agreements with nonutility generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning activities. Responding to its assessment that competition in the electric utility industry is likely to accelerate, GPU proceeded to implement two major organizational changes as well as other programs designed to reduce costs and strengthen GPU's competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the non-nuclear generation facilities owned by the Subsidiaries as well as undertake responsibility to construct any new non-nuclear generation facilities which the Subsidiaries may need in the future. By forming GPU Generation Corporation (GPUGC), GPU will consolidate and streamline the management of these generation facilities, and seek to apply management and operating efficiency techniques similar to those employed in more competitive industries. This initiative is intended to bring the Subsidiaries' generation costs more in line with projected market prices. GPU Nuclear Corporation is engaging in a search for parallel opportunities. The Subsidiaries received regulatory approvals to enter into an operating agreement with GPUGC from the PaPUC and NJBPU. SEC authorization is expected to be received in 1995.
The second part of the realignment includes the management combination of the two Pennsylvania subsidiaries. This action is intended to increase effectiveness and lower costs of Pennsylvania customer operations and service functions.
Other organizational realignments, designed to streamline management and reduce costs, were also implemented throughout the GPU System in 1994. In addition, GPU expanded employee participation in its incentive compensation program to tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System workforce accepted the Voluntary Enhanced Retirement Programs. Future payroll and benefits savings, which are estimated to be $75 million annually, began in the third quarter and reflect limiting the replacement of employees up to ten percent of those retired. Retirement benefits will be substantially paid from pension and postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the electric utility industry that calls into question the assumptions regarding the recovery of certain costs through ratemaking. As the utility industry
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continues to experience an increasingly competitive environment, GPU is attempting to assess the impact that these and other changes will have on its financial position. 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 the Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term regional energy supply from existing facilities, as evidenced by the results of the JCP&L all source competitive supply solicitation conducted in 1994, is less than the rates in virtually all of the Subsidiaries' nonutility generation agreements. In addition, the projected cost of energy from new supply sources is now lower than was expected in the recent past due to improvements in power plant technologies and reduced fuel prices.
The long-term nonutility generation agreements included in GPU's supply plan have been entered into pursuant to the requirements of PURPA and state regulatory directives. The Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Subsidiaries are also attempting to renegotiate, and in some cases buy out, existing high cost long-term nonutility generation agreements.
While the Subsidiaries thus far have been granted recovery of their nonutility generation costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to recover these costs throughout the terms of the related agreements. GPU currently estimates that in 1998, when substantially all of these nonutility generation projects are scheduled to be in-service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $300 million to $450 million annually.
THE GPU SUPPLY PLAN: 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 an increasingly competitive environment, its supply plan currently focuses on maintaining the Subsidiaries' existing customer base by offering competitively priced electricity.
Over the next five years, each Subsidiary is projected to experience an average growth in sales to customers of about 2% annually. These increases are expected to result from continued economic growth in the service
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territories and a slight increase in customers. To meet this growth, assuming the continuation of existing retail electric regulation, actual and projected capacity and sources of energy are as follows:
Capacity 1994 1999 MW % MW % Coal 3,022 30 3,040 28 Nuclear 1,396 14 1,405 13 Gas, Hydro & Oil 2,233 22 2,480 23 Contracted Purchases 3,463 34 3,695 34 Uncommitted Sources - - 280 2 Total 10,114 100 10,900 100
Sources of Energy 1994 1999 GWH % GWH % Coal 16,547 35 17,210 32 Nuclear 10,217 22 10,105 19 Gas, Hydro & Oil 1,071 2 1,325 2 Contracted Purchases 14,533 31 21,150 39 Spot Market & Interchange Purchases 4,603 10 4,465 8 Total 46,971 100 54,255 100
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. Through 1999, the plan consists of the continued utilization of GPU's existing generation facilities combined with power purchases, the construction of new facilities, and the continued promotion of economic energy-conservation and load-management programs. 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. The GPU System will take necessary actions to avoid adding new capacity at costs that may exceed future market prices. In addition, GPU will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected market prices.
New Energy Supplies
The GPU System's supply plan includes contracted capacity from nonutility generators, the replacement of expiring utility purchase contracts at lower costs, the construction of new peaking units, and the repowering of existing generation facilities. The supply plan also includes the addition of approximately 280 MW of currently uncommitted capacity. Additional capacity needs are principally related to the expiration of existing commitments rather than new customer load.
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The Subsidiaries have contracts and anticipated commitments with nonutility generators under which a total of 1,416 MW of capacity is currently in service and about an additional 1,180 MW are currently scheduled or anticipated to be in service by 1999.
In January 1994, JCP&L issued an all-source solicitation for the short- to intermediate-term supply of energy and capacity to determine and evaluate the availability of competitively priced power supply options. JCP&L is completing contract negotiations with three suppliers to purchase about 350 MW of capacity beginning in 1996, increasing to approximately 700 MW by 1999, for terms of up to eight years. 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.
In October 1994, Met-Ed completed construction on a 134 MW gas-fired combustion turbine located adjacent to its Portland Generating station at a cost of approximately $50 million. After completing operational testing, the new unit was placed in-service in January 1995 and is expected to produce power at a lower cost than similar peaking units now in operation.
JCP&L has commenced construction of a 141 MW gas-fired combustion turbine at its Gilbert Generating station. The new facility is estimated to cost $50 million and, coupled with the retirement of two older units, will result in a net capacity increase of approximately 95 MW. The project is expected to be in-service by mid-1996. Petitions have been filed with the NJBPU by two organizations seeking, among other things, reconsideration of the NJBPU's order which found that New Jersey's Electric Facility Need Assessment Act is not applicable to this combustion turbine and that construction of this facility, without a market test, is consistent with New Jersey energy policies. This matter is pending.
The GPU supply plan also includes a repowering project at Penelec's Warren Generating station that combines a coal-fueled combustion turbine with an existing generator. The repowering project will enable the station to comply with state and federal standards for reduced emissions and increase electrical output to approximately 100 MW. While the U.S. Department of Energy has agreed to fund 50% of the $146 million project cost as part of its Clean Coal Technology Program, management is unable to determine what effect recent federal budget cut proposals will have on Congressional appropriation of this funding. The project is in the early stages of development and is estimated to be in-service in 1996.
Managing Nonutility Generation
The Subsidiaries are pursuing actions to either eliminate or substantially reduce above-market payments for energy supplied by nonutility generators. The Subsidiaries will also continue to take legal, regulatory and legislative initiatives to avoid entering into any new power-supply agreements that are either not needed or, if needed, are not consistent with competitive market pricing. The following is a discussion of major nonutility generation activities involving the Subsidiaries.
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In a 1993 order, the NJBPU directed all utilities to identify nonutility generation contracts which were uneconomic and, therefore, candidates for buyout or other remedial measures. JCP&L identified a proposed 100 MW nonutility generation project as such a candidate, but was unable to negotiate a buyout or contract repricing to a level consistent with prices of replacement power. The NJBPU therefore ordered that hearings be held to determine whether their order approving the agreement should be modified or revoked. After hearings commenced in early 1994, the nonutility generator filed a complaint with the U.S. District Court seeking to enjoin the NJBPU proceedings on the grounds they were preempted by PURPA. The District Court dismissed the complaint finding, among other things, that the federal courts did not have jurisdiction to consider the matter. In January 1995, however, the U.S. Court of Appeals for the Third Circuit overturned the District Court decision. The Court of Appeals held, among other things, that once the NJBPU approves a power purchase agreement under PURPA and approves the utility's collection of costs from its customers, PURPA preempts the NJBPU from altering its order approving the contract and JCP&L's recovery from customers of its payment to the nonutility generator. The Court of Appeals reached its decision despite the contract provision that if the NJBPU at any time in the future disallowed any such rate recovery, JCP&L's payments to the nonutility generator would be equally reduced. JCP&L, the NJBPU and the New Jersey Division of Rate Advocate have each filed motions for rehearing with the Court of Appeals.
In 1994, a nonutility generator requested that the NJBPU and the PaPUC order JCP&L and Met-Ed to enter into long-term agreements to buy capacity and energy. JCP&L is contesting this request and the NJBPU has referred this matter to an Administrative Law Judge for hearings. Met-Ed sought to dismiss the request based on a May 1994 PaPUC order, which granted a Met-Ed and Penelec petition to obtain additional nonutility purchases through competitive bidding until new PaPUC regulations have been adopted. In September 1994, the Commonwealth Court granted the PaPUC's application to revise its May 1994 order for the purpose of reevaluating the nonutility generator's right to sell power to Met-Ed. The PaPUC subsequently ordered that hearings be held in this matter.
In November 1994, Penelec requested the Pennsylvania Supreme Court to review a Commonwealth Court decision upholding a PaPUC order requiring Penelec to purchase a total of 160 MW from two nonutility generators. The PaPUC had ordered Penelec in 1993 to enter into power purchase agreements with the nonutility generators for 80 MW of power each under long-term contracts commencing in 1997 or later. In August 1994, the Commonwealth Court denied Penelec's appeal of the PaPUC order. Penelec's petition to the Supreme Court contends that the Commonwealth Court imposed unnecessary and excessive costs on Penelec customers by finding that Penelec had a need for capacity. The petition also questions the Commonwealth Court's upholding of the PaPUC's determination that the nonutility generators had incurred a legal obligation entitling them to payments under PURPA.
In May 1994, the NJBPU issued an order granting two nonutility generators, aggregating 200 MW, a final in-service date extension for projects originally scheduled to be operational in 1997. In June 1994, JCP&L appealed
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the NJBPU's decision to the Appellate Division of the New Jersey Superior Court. The NJBPU order extends the in-service date for one year plus the period until JCP&L's appeals are decided.
As part of the effort to reduce above-market payments under nonutility generation agreements, the Subsidiaries are seeking to implement a program under which the natural gas fuel and transportation for the Subsidiaries' gas- fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, would be pooled and managed by a nonaffiliated fuel manager. The Subsidiaries believe the plan has the potential to provide substantial savings for their customers. The Subsidiaries have begun initial discussions with the nonutility generators who would be eligible to participate. Requirements for approval of the plan by state and federal regulatory agencies are being reviewed.
Conservation and Load Management
The NJBPU and PaPUC continue to encourage the development of new conservation and load-management programs. Because the benefits of some of these programs may not offset program costs, the Subsidiaries are working to mitigate the impacts these programs can have on the Subsidiaries' competitive position in the marketplace.
In New Jersey, JCP&L continues to conduct demand-side management (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 over 43 MW through 1994.
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. However, an industrial intervenor had contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed the PaPUC order. As a result, the nature and scope of Met-Ed and Penelec's DSM programs is uncertain at this time.
ENVIRONMENTAL ISSUES: The Clean Air Act Amendments of 1990 (Clean Air Act) require substantial reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000. The Subsidiaries' current 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 $380 million by the year 2000 for air pollution control equipment. During 1994, the first of two scrubbers was installed at the jointly owned Conemaugh station. The second scrubber is scheduled to be installed in November 1995. When operational, these scrubbers are expected to reduce sulfur dioxide emissions by 95%. Met-Ed's share of the total project cost is estimated to be
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$55 million. Through December 31, 1994, the Subsidiaries have made capital expenditures of approximately $179 million (including the first Conemaugh scrubber mentioned above) to comply with the Clean Air Act requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Subsidiaries expect that the U.S. Environmental Protection Agency will approve the proposal, and that as a result, the Subsidiaries will spend an estimated $60 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Subsidiaries are unable to determine what, if any, additional costs will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the Subsidiaries will continue to evaluate the risk of recovering capital investments compared to increased participation in the emission allowance market and the use of low-sulfur coal or the early retirement of facilities. These and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected 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 the Consolidated Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS: As a result of the TMI-2 accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Subsidiaries and are still pending. For more information, see the TMI-2 section of Note 1 to the 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.
Given the competitive pressures facing the electric utility industry, the Subsidiaries do not plan to take any actions that would increase customers' base rates over the next several years. Therefore, the control of
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operating and capital costs will be essential. 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. Though currently operating in a regulated environment, the GPU System's focus will be less reliant on the ratemaking process, and geared toward continued performance improvement and cost reduction 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of General Public Utilities Corporation and Subsidiary Companies as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 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.
As more fully discussed in Note 1 to the consolidated financial statements, the Corporation is unable to determine the ultimate consequences of certain contingencies which have resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The matters which remain uncertain are (a) the extent to which the retirement costs of TMI-2 could exceed amounts currently recognized for ratemaking purposes or otherwise accrued, and (b) the excess, if any, of amounts which might be paid in connection with claims for damages resulting from the accident over available insurance proceeds.
As discussed in Notes 7 and 9 to the consolidated financial statements, the Corporation was required to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993.
COOPERS & LYBRAND L.L.P. New York, New York February 1, 1995
General Public Utilities Corporation and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Public Utilities Corporation (the Corporation) is a holding company registered under the Public Utility Holding Company Act of 1935. The Corporation does not directly operate any utility properties, but owns all the outstanding common stock of three electric utilities -- Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec) (the Subsidiaries). The Corporation also owns all the common stock of GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and Energy Initiatives, Inc. (EI) and EI Power, Inc., which develop, own and operate nonutility generating facilities. All of these companies considered together with their subsidiaries are referred to as the "GPU System."
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, TMI-2 and Oyster Creek, including nuclear fuel, was as follows:
Net Investment (Millions) TMI-1 TMI-2 Oyster Creek 1994 $627 $103 $817 1993 $670 $115 $784
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The GPU System may also incur costs and experience reduced output at its nuclear plants because of the prevailing design criteria at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now-assumed lives cannot be assured. Also, not all risks associated with the ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric utilities to obtain adequate and timely recovery of costs 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).
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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 accident cleanup program was completed in 1990. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100 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 and the suppliers of equipment and services to TMI-2, and are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery on the basis of alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Subsidiaries had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against the Corporation and the Subsidiaries and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is likely to begin in 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion
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for summary judgment. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals.
In an Order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against the Corporation and the Subsidiaries; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Subsidiaries submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Subsidiaries intend to complete the funding for Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1994 dollars) for TMI-1 and Oyster Creek are $157 million and $189 million, respectively. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
In 1988, a consultant to GPUN performed site-specific studies of TMI-1 and Oyster Creek that considered various decommissioning plans and estimated the cost of decommissioning the radiological portions of each plant to range from approximately $225 to $309 million and $239 to $350 million, respectively (adjusted to 1994 dollars). In addition, the studies estimated the cost of removal of nonradiological structures and materials for TMI-1 and Oyster Creek at $74 million and $48 million, respectively (adjusted to 1994 dollars).
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The ultimate cost of retiring the GPU System's nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Subsidiaries charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Subsidiaries have contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990 and 1991 to TMI-2's external trust and will await resolution of the case pending before the Pennsylvania Supreme Court before making any further contributions for amounts written off by Met- Ed and Penelec in 1994. Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the balance sheet.
TMI-1 and Oyster Creek:
JCP&L is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. JCP&L is also collecting revenues, based on estimates of $15.3 million for TMI-1 and $31.6 million for Oyster Creek adopted in rate orders issued in 1991 and 1993 by the New Jersey Board of Public Utilities (NJBPU), for its share of the cost of removal of nonradiological structures and materials. In 1993, the Pennsylvania Public Utility Commission (PaPUC) granted Met-Ed revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site- specific study. Also in 1993, the PaPUC approved a rate change for Penelec that increased the collection of revenues for decommissioning costs for TMI-1 to a basis equivalent to that granted Met-Ed. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditures of these funds has been made in accumulated depreciation, amounting to $46 million for TMI-1 and $100 million for Oyster Creek at December 31, 1994. Oyster Creek and TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the current ratemaking process.
TMI-2 Future Costs:
The Corporation and its Subsidiaries have recorded a liability for the radiological decommissioning of TMI-2, reflecting the NRC funding target in 1994 dollars. The Subsidiaries record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Subsidiaries have also recorded a liability for incremental costs specifically attributable to monitored storage. In addition, the Subsidiaries have recorded a liability for
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nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $2 million as of December 31, 1994. Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and 1993 are as follows:
(Millions) (Millions) 1994 1993
Radiological Decommissioning $250 $229 Nonradiological Cost of Removal 72 71 Incremental Monitored Storage 19 20 Total $341 $320
The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. At December 31, 1994, $109 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and $56 million was recoverable from customers and included in Three Mile Island Unit 2 Deferred Costs on the balance sheet.
In 1993, a PaPUC rate order for Met-Ed allowed for the future recovery of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order. In December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to review that decision. As a consequence of the Commonwealth Court decision, Met-Ed recorded pre-tax charges totaling $127.6 million during 1994. Penelec, which is also subject to PaPUC regulation, recorded pre-tax charges of $56.3 million during 1994, for its share of such costs applicable to its retail customers. These charges appear in the Other Income and Deductions section of the Income Statement and are composed of $121 million for radiological decommissioning costs, $48.2 million for the nonradiological cost of removal and $14.7 million for incremental monitored storage costs. Met-Ed and Penelec will await resolution of the case pending before the Pennsylvania Supreme Court before making any nonrecoverable funding contributions to external trusts for their share of these costs. The Pennsylvania Subsidiaries will be similarly required to charge to expense their share of future increases in the estimate of the costs of retiring TMI-2. Future earnings on trust fund deposits for Met-Ed and Penelec will be recorded as income. Prior to the Commonwealth Court's decision, Met-Ed and Penelec expensed and contributed $40 million and $20 million respectively, to external trusts relating to their nonrecoverable shares of the accident-related portion of the decommissioning liability. JCP&L has also expensed and made a nonrecoverable contribution of $15 million to an external decommissioning trust. JCP&L's share of earnings on trust fund deposits are offset against amounts shown on the balance sheet under Three Mile Island Unit 2 Deferred Costs as collectible from customers.
The NJBPU has granted decommissioning revenues for JCP&L's share of the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. JCP&L, which is not affected by the Commonwealth Court's ruling, intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
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As a result of TMI-2's entering long-term monitored storage in late 1993, the Subsidiaries are incurring incremental annual storage costs of approximately $1 million. The Subsidiaries estimate that the remaining annual storage costs will total $19 million through 2014, the expected retirement date of TMI-1. JCP&L's rates reflect its $5 million share of these costs.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the GPU System.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 is excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor.
The GPU System has insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and facilities, the GPU System is subject to retrospective premium assessments of up to $69 million in any one year, in addition to those payable (up to $20 million annually per incident) under the Price-Anderson Act.
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COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the GPU System's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator; b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the GPU System's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. Management believes that to the extent that the GPU System no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Subsidiaries have entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Subsidiaries to purchase at the contract price all of the power produced up to the contract limits. As of December 31, 1994, facilities covered by these agreements having 1,416 MW (JCP&L 882 MW, Met-Ed 239 MW and Penelec 295 MW) of capacity were in service and 130 MW were scheduled
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to commence operation in 1995. Payments made pursuant to these agreements were $528 million, $491 million and $471 million for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated to aggregate $694 million, $918 million, $1,088 million, $1,304 million and $1,337 million, respectively. These agreements, together with those for facilities which are not yet in operation, provide for the purchase of approximately 2,596 MW (JCP&L 1,176 MW, Met-Ed 846 MW and Penelec 574 MW) of capacity and energy by the GPU System by the mid-to-late 1990s, 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 now seek shorter-term agreements offering more flexibility (see Management's Discussion and Analysis -COMPETITIVE ENVIRONMENT). Due to the current availability of excess capacity in the market place, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing generation facilities is currently competitively priced. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Subsidiaries' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources. These agreements have been entered into pursuant to the requirements of the federal Public Utility Regulatory Policies Act and state regulatory directives. The Subsidiaries have initiated lawful actions which are intended to substantially reduce these above market payments. In addition, the Subsidiaries intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Subsidiaries are also attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation agreements.
While the Subsidiaries thus far have been granted recovery of their nonutility generation costs from customers by the PaPUC and NJBPU, there can be no assurance that the Subsidiaries will continue to be able to recover these costs throughout the term of the related agreements. GPU currently estimates that in 1998, when substantially all of the these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas- fired combined cycle facility) will range from $300 million to $450 million annually. Moreover, efforts to lower these costs have led to disputes before both the NJBPU and the PaPUC, as well as to litigation, and may result in claims against the Subsidiaries for substantial damages. There can be no assurance as to the outcome of these matters.
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
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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 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.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of 1990, the Subsidiaries expect to spend up to $380 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the GPU System will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Corporation expects that the U.S. Environmental Protection Agency (EPA) will approve the proposal, and that as a result, the Subsidiaries will spend an estimated $60 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Subsidiaries are unable to determine what, if any, additional costs will be incurred.
The GPU System companies have been notified by the EPA and state environmental authorities that they are among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 13 hazardous and/or toxic waste sites. In addition, the Subsidiaries have been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which they have not yet been named as PRPs. The Subsidiaries have also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Subsidiaries.
JCP&L has entered into agreements with the New Jersey Department of Environmental Protection for the investigation and remediation of 17 formerly owned manufactured gas plant sites. One of these sites has been repurchased by JCP&L. JCP&L has also entered into various cost-sharing agreements with other utilities for some of the sites. As of December 31, 1994, JCP&L has an estimated environmental liability of $32 million recorded on its balance sheet relating to these sites. The estimated liability is based upon ongoing site investigations and remediation efforts, including capping the sites and pumping and treatment of ground water. If the periods over which the remediation is currently expected
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to be performed are lengthened, JCP&L believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties as JCP&L does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If JCP&L is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In 1993, the NJBPU approved a mechanism similar to JCP&L's Levelized Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas plant remediation costs when expenditures exceed prior collections. The NJBPU decision provides for interest to be credited to customers until the overrecovery is eliminated and for future costs to be amortized over seven years with interest. A final NJBPU order dated December 16, 1994 indicated that interest is to be accrued retroactive to June 1993. JCP&L is pursuing reimbursement of the above costs from its insurance carriers. In November 1994, JCP&L filed a complaint with the Superior Court of New Jersey against several of its insurance carriers, relative to these manufactured gas plant sites. JCP&L requested the Court to order the insurance carriers to reimburse JCP&L for all amounts it has paid, or may be required to pay, in connection with the remediation of the sites.
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
During 1994, the Corporation's Subsidiaries offered Voluntary Enhanced Retirement Programs (VERP) to certain employees. The enhanced retirement programs were part of a corporate realignment undertaken in 1994. Approximately 82% of eligible employees accepted the retirement programs, resulting in a pre-tax charge to earnings of $127 million. These charges are included as Other Operation and Maintenance on the income statement.
The GPU System's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $482 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured.
The Subsidiaries have entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which they have ownership interests. The contracts, which expire between 1995 and the end of the expected service lives of the generating stations, require the
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purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal under the contracts is based on adjustments of indexed cost components. One contract also includes a provision for the payment of environmental and postretirement benefits. The Subsidiaries' share of the cost of coal purchased under these agreements is expected to aggregate $98 million for 1995.
The Subsidiaries have entered into agreements and JCP&L is completing contract negotiations with three other utilities to purchase capacity and energy for various periods through 2004. These agreements, including contracts under negotiation, will provide for up to 1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW by 2004. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated to aggregate $208 million, $175 million, $162 million, $145 million and $128 million, respectively. JCP&L's contract negotiations are the result of their all-source solicitation for competitively priced, short- to intermediate-term energy and capacity, described in the New Energy Supplies section of Management's Discussion and Analysis.
The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from nonutility generation projects. The proceeding was initiated, in part, to respond to contentions of the Division of the Ratepayer Advocate (Ratepayer Advocate), that by permitting utilities to recover such costs through the LEAC, an excess or "double recovery" may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1993, JCP&L and the other New Jersey electric utilities filed motions for summary judgment with the NJBPU. Ratepayer Advocate has filed a brief in opposition to the utilities' summary judgment motions including a statement from its consultant that in his view, the "double recovery" for JCP&L for the 1988-92 LEAC periods would be approximately $102 million. In 1994, the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent LEACs remain open for further investigation. This matter is pending before a NJBPU Administrative Law Judge. Management estimates that the potential exposure for LEAC periods subsequent to 1991 is approximately $67 million through February 1996, the end of the next LEAC period. There can be no assurance as to the outcome of this proceeding.
JCP&L's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate annual generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect on net income of the performance standard charge at a 40% capacity factor would be approximately $11 million. 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. At the request of the PaPUC, Met-Ed and Penelec, as well as the other Pennsylvania utilities, have supplied the PaPUC with proposals for the establishment of a nuclear performance standard. Met-Ed and Penelec expect the PaPUC to adopt a generic nuclear performance standard as a part of their respective energy cost rate (ECR) clauses in 1995.
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During the normal course of the operation of their businesses, in addition to the matters described above, the GPU System companies are from time to time involved in disputes, claims and, in some cases, as defendants in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these types of matters would have a material effect on the GPU System's financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS The consolidated financial statements include the accounts of all subsidiaries. Certain reclassifications of prior years' data have been made to conform with current presentation. The Subsidiaries' accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the PaPUC and NJBPU.
REVENUES The Corporation and its 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.
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,
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resulted in annual rates of 3.16%, 3.19% and 3.17% for the years 1994, 1993 and 1992, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the 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 6.45%, 6.80% and 7.33% for the years 1994, 1993 and 1992, respectively.
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 TMI-2 investment attributable to retail customers. At December 31, 1994, $91 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 Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1994 amounted to $40 million 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, 1994, $46 million is recorded on the balance sheet in Deferred Debits and Other Assets - Other.
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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, 1994, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $150 million, and is reflected in Deferred Credits and Other Liabilities - Other. As the actual liability is substantially in excess of the amount recovered to date from ratepayers, the Subsidiaries have reflected such excess of $28 million at December 31, 1994 in Deferred Debits and Other Assets - Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over remaining periods of 12 years for JCP&L, 13 years for Met-Ed and 3 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.
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.
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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, 1994, the GPU System had $348 million of short-term notes outstanding, of which $60 million was commercial paper and the remainder was issued under bank lines of credit (credit facilities).
The GPU System has $528 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, 1994, the Subsidiaries had long-term debt outstanding, as follows:
Interest Rates
4 5/8% to 7% to 9% to Maturities 6.97% 8 7/8% 10 1/2% Total (In Thousands) First mortgage bonds: 1995-2004 $ 587,005 $ 494,191 $148,500 $1,229,696 2005-2014 215,120 138,300 - 353,420 2015-2025 205,000 557,200 50,000 812,200 Total $1,007,125 $1,189,691 $198,500 2,395,316
Amounts due within one year (87,930) Total 2,307,386
Other long-term debt (net of $3,235 due within one year) 42,968 Unamortized net discount (4,937) Total $2,345,417
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For the years 1995, 1996, 1997, 1998 and 1999, the Subsidiaries have long-term debt maturities of $91 million, $119 million, $145 million, $39 million and $63 million, respectively. Substantially all of the utility plant owned by the Subsidiaries is subject to the lien of their respective mortgages.
The estimated fair value of the Corporation's long-term debt, as of December 31, 1994 and 1993 is as follows: (In Thousands) Carrying Fair Amount Value
1994 $2,345,417 $2,142,854 1993 $2,320,384 $2,446,407
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 Corporation for debt of the same remaining maturities and credit qualities.
5. PREFERRED SECURITIES OF SUBSIDIARIES
At December 31, 1994, Met-Ed Capital L.P., a special-purpose finance subsidiary of Met-Ed, and Penelec Capital L.P., a special-purpose finance subsidiary of Penelec, had the following issues of Monthly Income Preferred Securities outstanding:
Issue Securities Company Series Price Outstanding Total (In Thousands) Met-Ed Capital 9.00% $25 4,000,000 $100,000 Penelec Capital 8.75% $25 4,200,000 105,000 Total $205,000
The fair value of the Monthly Income Preferred Securities for Met-Ed Capital and Penelec Capital, based on market price quotes at December 31, 1994, is $98 million and $100.8 million, respectively.
In 1994, Met-Ed Capital L.P. and Penelec Capital L.P. issued $100 million and $105 million, respectively, of Monthly Income Preferred Securities. The proceeds from the issuance of the Monthly Income Preferred Securities were then lent to Met-Ed and Penelec; they in turn issued deferrable interest subordinated debentures to their special-purpose finance subsidiaries. Penelec and Met-Ed are taking tax deductions for the interest paid on the subordinated debentures.
The issued and outstanding Monthly Income Preferred Securities of Met-Ed Capital L.P. and Penelec Capital L.P. mature in 2043. They are redeemable at the option of Met-Ed and Penelec at 100 percent of the principal amount beginning in 1999, or earlier under certain limited circumstances, including the loss of the tax deduction for interest paid. Distributions on the Monthly Income Preferred Securities are paid monthly but can be deferred for up to 60 months. However, 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.
General Public Utilities Corporation and Subsidiary Companies
6. CAPITAL STOCK
COMMON STOCK The following table presents information relating to the common stock ($2.50 par value) of the Corporation:
1994 1993
Authorized shares 150,000,000 150,000,000 Issued shares 125,783,338 125,783,338 Reacquired shares 10,575,086 10,816,561 Outstanding shares 115,208,252 114,966,777 Restricted units 107,063 74,076
In 1993, the Corporation sold four million shares of common stock through an underwritten public offering. In 1994 and 1993, pursuant to the 1990 Restricted Stock Plan, the Corporation issued to officers restricted units representing rights to receive shares of common stock, on a one-for-one basis, at the end of the restriction period. The restricted units do not affect the issued and outstanding shares of common stock until conversion at the end of the restriction period. However, the restricted units are considered common stock equivalents and therefore are included in average common shares outstanding for the earnings per share computation on the income statement. The restricted units accrue dividends on a quarterly basis. In 1994 and 1993, the Corporation awarded to plan participants 34,595 and 32,740 restricted units, respectively. In 1994 and 1993, the Corporation issued a total of 6,275 and 3,729 restricted shares, respectively, from previously reacquired shares. No shares of common stock were reacquired in 1994 or 1993.
PREFERRED STOCK At December 31, 1994, the Subsidiaries had the following issues of cumulative preferred stock outstanding:
Stated Value Shares (In Thousands) Series per Share Outstanding Stated Value
With mandatory redemption:
7.52% - 8.65% $100 1,500,000 $150,000
Without mandatory redemption:
3.70% - 4.70% $100 723,912 $ 72,391 7.88% $100 250,000 25,000 Total 973,912 97,391 Premium 725 Total $ 98,116
General Public Utilities Corporation and Subsidiary Companies
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.
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.
During 1992, JCP&L issued 500,000 shares of 7.52% Series cumulative preferred stock with mandatory redemption provisions. The series is callable beginning in the year 2002 at various prices above its stated value. The series is to be redeemed ratably over 20 years beginning in the year 1998. This issue provides that JCP&L may, at its option, redeem an amount of shares equal to its mandatory sinking fund requirement at such time as the mandatory sinking fund redemption is made. Expenses of $0.5 million incurred in connection with the issuance of the cumulative preferred stock were charged to Capital Surplus on the balance sheet.
During 1992, JCP&L redeemed all its outstanding 8.75% Series H cumulative preferred stock (aggregate stated value of $50 million), at a total cost of $51.6 million. This resulted in a $1.6 million charge to Retained Earnings. Additional preferred stock expenses of $0.7 million were charged to Retained Earnings.
The issued and outstanding shares of preferred stock without mandatory redemption are callable at various prices above their stated values. At December 31, 1994, the aggregate amount at which these shares could be called by the Subsidiaries was $102 million. The issued and outstanding shares with mandatory redemption have aggregate redemption requirements of $45 million for the years 1995 through 1999.
At December 31, 1994 and 1993, 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.
General Public Utilities Corporation and Subsidiary Companies
7. INCOME TAXES
Effective January 1, 1993, the GPU System implemented FAS 109, "Accounting for Income Taxes." In 1993, the cumulative effect on net income of this accounting change was immaterial. Also in 1993, the federal income tax rate changed from 34% to 35%, retroactive to January 1, 1993, resulting in an increase in the deferred tax assets of $9 million and an increase in the deferred tax liabilities of $48 million. The tax rate change did not have a material effect on net income as the changes in deferred taxes were substantially offset by the recording of regulatory assets and liabilities. As of December 31, 1994 and 1993, the balance sheet reflected $562 million and $555 million, respectively, of income taxes recoverable through future rates, (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $106 million and $111 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, 1994 and 1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993 Current: Current: Unbilled revenue $ 16 $ 14 Revenue taxes $ 18 $ (12) Other 2 2 Deferred energy 4 (6) Total $ 18 $ 16 Total $ 22 $ (18) Noncurrent: Noncurrent: Unamortized ITC $106 $111 Liberalized Decommissioning 131 48 depreciation: Contribution in aid previously flowed of construction 25 22 through $ 333 $ 327 Other 167 94 future revenue Total $ 429 $275 requirements 229 228
Subtotal 562 555 Liberalized depreciation 767 726 Forked River 54 30 Other 56 78 Total $1,439 $1,389
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:
General Public Utilities Corporation and Subsidiary Companies
(In Millions) 1994 1993 1992
Net income $164 $296 $252 Preferred stock dividends 21 29 37 Income tax expense 86 197 174 Book income subject to tax $271 $522 $463
Federal statutory rate 35% 35% 34% State tax, net of federal benefit - 4 5 Other (3) (1) (1) Effective income tax rate 32% 38% 38%
Federal and state income tax expense is comprised of the following:
(In Millions) 1994 1993 1992 Provisions for taxes currently payable $162 $127 $165
Deferred income taxes: Liberalized depreciation 31 32 34
New Jersey revenue tax 32 32 3 Deferral of energy costs 12 6 (16) Accretion income 11 7 9 Decommissioning (76) - - VERP (51) - - Other (21) 5 (8) Deferred income taxes, net (62) 82 22 Amortization of ITC, net (14) (12) (13) Income tax expense $ 86 $197 $174
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.
General Public Utilities Corporation and Subsidiary Companies
8. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following:
(In Millions) 1994 1993 1992
Maintenance $271 $275 $251 Other taxes: New Jersey unit tax $204 $202 $197 Pennsylvania state gross receipts 70 68 67 Real estate and personal property 21 21 22 Other 54 53 42 Total $349 $344 $328
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) 1994 1993 1992
Service cost-benefits earned during the period $ 34.8 $ 28.6 $ 26.3 Interest cost on projected benefit obligation 95.4 91.8 87.8 Less: Expected return on plan assets (104.4) (96.6) (89.5)
Amortization (1.4) (2.2) (2.5) Net periodic pension cost $ 24.4 $ 21.6 $ 22.1
The above 1994 amounts do not include a pre-tax charge to earnings of $97 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992 were gains of $13.8 million, $145.9 million and $53.2 million, respectively.
The funded status of the plans and related assumptions at December 31, 1994 and 1993 were as follows:
General Public Utilities Corporation and Subsidiary Companies
(In Millions) 1994 1993
Accumulated benefit obligation (ABO): Vested benefits $ 1,118.2 $ 982.3 Nonvested benefits 120.5 122.9 Total ABO 1,238.7 1,105.2 Effect of future compensation levels 182.6 197.2 Projected benefit obligation (PBO) $ 1,421.3 $ 1,302.4
PBO $(1,421.3) $(1,302.4) Plan assets at fair value 1,279.9 1,288.6 PBO in excess of plan assets (141.4) (13.8) Less: Unrecognized net loss 72.5 19.8 Unrecognized prior service cost (0.6) (5.9) Unrecognized net transition asset (6.6) (8.6) Adjustment required to recognize minimum liability (1.2) (2.3)
Accrued pension liability $ (77.3) $ (10.8)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5 Annual increase in compensation levels 6.0 5.0
In 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $48 million decrease in the PBO as of December 31, 1994. Also, in 1994, the PBO increased by $109 million as a result of the VERP. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net 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 as a credit to pension cost over the average remaining service periods for covered employees.
At December 31, 1994 and 1993, GPUSC had accumulated pension obligations in excess of amounts accrued; as a result, additional minimum liabilities in the amounts of $.7 million and $1.3 million, net of deferred income taxes of $.5 million and $1 million, respectively, are reflected as reductions in Retained Earnings.
General Public Utilities Corporation and Subsidiary Companies
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 1994, 1993 and 1992 were $12.7 million, $12.2 million and $11.2 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. For 1992, the annual premium costs associated with providing these benefits totaled approximately $16.6 million.
Effective January 1, 1993, the GPU System adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The GPU System has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1994 and 1993 follows:
(In Millions) 1994 1993 Service cost-benefits attributed to service during the period $14.6 $ 12.5 Interest cost on the accumulated postretirement benefit obligation 37.0 34.3 Expected return on plan assets (7.0) (3.4) Amortization of transition obligation 18.1 18.1 Other amortization, net 2.1 - Net periodic postretirement benefit cost 64.8 61.5 Less, deferred for future recovery (15.8) (27.5) Postretirement benefit cost, net of deferrals $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 1994 and 1993 was a gain of $2.3 million and $3.9 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as follows:
General Public Utilities Corporation and Subsidiary Companies
(In Millions) 1994 1993 Accumulated Postretirement Benefit Obligation: Retirees $ 291.7 $ 207.1 Fully eligible active plan participants 67.2 72.4 Other active plan participants 197.6 223.1 Total accumulated postretirement benefit obligation (APBO) $ 556.5 $ 502.6
APBO $(556.5) $(502.6) Plan assets at fair value 129.0 47.1 APBO in excess of plan assets (427.5) (455.5) Less: Unrecognized net loss 46.9 65.2 Unrecognized prior service cost 2.5 2.9 Unrecognized transition obligation 313.3 343.6 Accrued postretirement benefit liability $ (64.8) $ (43.8)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5
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.
In 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $39 million decrease in the APBO as of December 31, 1994. Also, in 1994, the APBO increased by $35 million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for Medicare, then decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $53 million as of December 31, 1994 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $6 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 began 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.
General Public Utilities Corporation and Subsidiary Companies
In 1993, Penelec began deferring its FAS 106 incremental expense in accordance with the PaPUC's generic policy statement permitting the deferral of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of such costs, stating that FAS 106 expense incurred after January 1, 1993 (the effective date for the accounting change) but prior to its next base rate case could not be deferred for future recovery, and that to assure such future recovery constituted retroactive ratemaking. As a result of the Court's decision, in the second quarter of 1994, Penelec determined that deferred incremental FAS 106 expense was not likely to be recovered and wrote off $14.6 million deferred since January 1993. In addition, $4 million of Penelec's unrecognized transition obligation resulting from employees who elected to participate in the VERP was also written off during the second quarter of 1994. During the remainder of 1994, Penelec continued to expense FAS 106 costs ($4.2 million) and anticipates annual charges to income of approximately $9 million, beginning in 1995, which represents continued amortization of the transition obligation along with current accruals of FAS 106 expense for active employees.
The Corporation believes that the Commonwealth Court ruling does not affect Met-Ed because it received PaPUC authorization as part of its 1993 retail base rate order to defer incremental FAS 106 expense. JCP&L received similar authorization in a 1993 NJBPU base rate order.
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, 1994:
Balance (In Millions) % Accumulated Station Owner Ownership Investment Depreciation
Homer City Penelec 50 $441.2 $158.7 Conemaugh Met-Ed 16.45 138.9 27.9 Keystone JCP&L 16.67 84.5 20.8 Yards Creek JCP&L 50 26.4 6.7 Seneca Penelec 20 16.4 4.5
11. LEASES
The GPU System's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $148 million and $150 million, respectively (net of amortization of $112 million and $69 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
General Public Utilities Corporation and Subsidiary Companies
The Subsidiaries have nuclear fuel lease agreements with nonaffiliated fuel trusts. An aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any one time. It is contemplated that when consumed, portions of the presently leased material will be replaced by additional leased material. The Subsidiaries are responsible for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases are renewable annually. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1994, 1993 and 1992 these amounts were $50 million, $66 million and $74 million, respectively. The leases may be terminated at any time with at least five months notice by either party prior to the end of the current period. Subject to certain conditions of termination, the Subsidiaries are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.
JCP&L and Met-Ed have sold and leased back substantially all of their respective ownership interests in the Merrill Creek Reservoir project. The minimum lease payments under these operating leases, which have remaining terms of 38 years, average approximately $3 million annually for each company.
Jersey Central Power & Light Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In 1994, earnings available for common stock increased $6.5 million to $148 million due principally to increases in sales resulting from growth in the number of customers and colder winter weather as compared to last year, and an increase in revenues attributable to a February 1993 retail base rate case. Also contributing to the earnings increase was reduced reserve capacity expense, first quarter interest income of $7.4 million after-tax from refunds of previously paid federal income taxes related to the tax retirement of Three Mile Island Unit 2 (TMI-2), and a performance award for the operation of the Company's nuclear generating stations.
The earnings increase was partially offset by a second quarter after-tax charge of $30.4 million related to the Voluntary Enhanced Retirement Programs and increased other operation and maintenance (O&M) expense, which included higher emergency and winter storm repairs.
Earnings available for common stock increased $44.8 million to $141.5 million in 1993 due principally to additional revenues resulting from a February 1993 retail base rate increase and higher customer sales due primarily to the significantly warmer summer temperatures as compared with the mild weather in 1992. Also contributing to the increase in earnings was reduced reserve capacity expense. The increase in earnings was partially offset by increased other O&M expense, the write-off of approximately $6.2 million (after-tax) of costs related to the cancellation of proposed power supply and transmission facilities agreements, and higher depreciation expense and financing costs associated with additions to utility plant. Financing costs reflect savings derived from the early redemption of first mortgage bonds and preferred stock.
The Company's return on average common equity was 11.2% for 1994 as compared with 11.1% for 1993.
OPERATING REVENUES:
Revenues increased 0.9% to $1.95 billion in 1994 after increasing 9.1% to $1.94 billion in 1993. The components of these changes are as follows:
(In Millions) 1994 1993 Kilowatt-hour (KWH) revenues (excluding energy portion) $ 21.5 $ 37.5 Rate increase 20.8 108.2 Energy revenues (31.0) 13.4 Other revenues 5.2 2.7 Increase in revenues $ 16.5 $161.8
Jersey Central Power & Light Company
Kilowatt-hour revenues
The increase in KWH revenues was due principally to increases in sales resulting from new customer additions and the colder winter weather as compared to last year. New customer growth occurred primarily in the residential and commercial sectors.
KWH revenues increased due principally to higher third quarter sales resulting from the significantly warmer summer temperatures as compared with the milder weather during the same period in 1992. An increase in nonweather- related usage in the residential and commercial sectors, and a 1.4% increase in the average number of customers also contributed to the increase in KWH revenues. New customer growth occurred primarily in the residential sector, and was partially offset by a reduction in the number of industrial customers.
Rate increase
In February 1993, the New Jersey Board of Public Utilities (NJBPU) authorized a $123 million increase in retail base rates, or approximately 7% annually.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues decreased as a result of a January 1994 decrease in energy cost rates in effect, the loss of wholesale customers and decreased KWH sales to other utilities.
Energy revenues increased as a result of increased KWH sales to ultimate customers partially offset by decreased sales to other utilities.
Other revenues
1994 and 1993 Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes.
OPERATING EXPENSES: Power purchased and interchanged
Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings since these
Jersey Central Power & Light Company
cost increases are substantially recovered through the Company's energy clause. However, earnings were favorably affected by lower reserve capacity expense resulting primarily from the expiration of a purchase contract with another utility and a reduction in purchases from affiliated companies. The decrease in expense was partially offset by higher nonutility generation purchases.
Earnings were favorably impacted by a reduction in reserve capacity expense resulting from the expiration of a purchase contract with another utility and a reduction in purchases from another utility. Power purchased and interchanged also decreased due to a decrease in nonutility generation purchases.
Other operation and maintenance
The increase in other O&M expense was primarily attributable to a $46.9 million pre-tax charge for costs related to the Voluntary Enhanced Retirement Programs. Increases were 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.
Other O&M expense increased primarily due to emergency and storm-related activities and higher tree trimming expense. Other O&M expense also increased due to the recognition of current and previously deferred demand side management expenses as directed in the Company's rate orders, an increase in the accrual of nuclear outage maintenance costs and an increase in the amortization of previously deferred nuclear expenses.
Depreciation and amortization
1994 and 1993 Depreciation and amortization expense increased due to increases in utility plant and additional amortization of deferred assets. The increases in utility plant consisted primarily of additions to existing generating facilities to maintain system reliability and additions to the transmission and distribution system related to new customer growth.
Taxes, other than income taxes
1994 and 1993 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
Jersey Central Power & Light Company
OTHER INCOME AND DEDUCTIONS: Other income, net
The increase in other income, net was due principally to first quarter interest income resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. The effect on pre-tax earnings was an increase of $14.7 million.
The reduction in other income, net was due to the write-off of $9.3 million pre-tax of costs related to the cancellation of proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne Light Company. The decrease was also due to the absence of carrying charges on certain tax payments made by the Company in 1992, which are now being recovered through rates.
INTEREST CHARGES AND PREFERRED DIVIDENDS: Interest on long-term debt decreased due to the retirement of $60 million of secured medium-term notes and lower interest rates associated with the refinancing in 1993 of higher cost debt. Other interest expense was higher due primarily to an increase in the average levels of short-term borrowings outstanding. Other interest expense also increased due to the tax retirement of TMI-2, which resulted in a $3.3 million pre-tax increase in interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Interest on long-term debt increased due primarily to the issuance of additional long-term debt, offset partially by decreases associated with the refinancing of higher cost debt at lower interest rates. Other interest was favorably affected by lower short-term interest rates and a reduction in the average levels of short-term borrowings outstanding.
1994 and 1993 Preferred dividends decreased due to the redemption in 1993 of an aggregate of $50 million of preferred stock.
LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS:
The Company's capital needs were $304 million in 1994, consisting of cash construction expenditures of $244 million and amounts for maturing obligations
Jersey Central Power & Light Company
of $60 million. During 1994, construction funds were used primarily to maintain and improve existing generation facilities and the transmission and distribution system, proceed with various clean air compliance projects, and build a new generation facility. For 1995, the Company's construction expenditures are estimated to be $220 million, consisting mainly of $182 million for ongoing system development, $20 million for clean air compliance requirements, and $16 million for the continued construction of a new generation facility. The 1995 estimated reduction is largely due to the completion in 1994 of construction expenditures during an outage at the Company's Oyster Creek Nuclear Generating Station. Expenditures for maturing debt are expected to be $47 million for 1995 and $36 million for 1996 including amounts for mandatory redemptions of preferred stock. 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 two-thirds of the Company's 1995 capital needs will be satisfied through internally generated funds.
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any one time. The Company's share of nuclear fuel capital leases at December 31, 1994 totaled $99 million. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $41 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:
The Company anticipates receiving regulatory authorization in the first quarter of 1995 to issue, through a special-purpose finance subsidiary, up to $125 million of Monthly Income Preferred Securities. A portion of these securities is expected to be issued in 1995 to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and Exchange Commission (SEC) to issue up to five million shares of additional common stock through 1996. The proceeds from the sale of such additional common stock would be used to increase the Company and its affiliates' common equity ratios and reduce GPU short-term debt. GPU will monitor the capital markets as well as its capitalization ratios relative to its targets to determine whether, and when, to issue such shares.
The 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 1995. Under existing authorization, the Company may issue senior securities in the amount of $275 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
Jersey Central Power & Light Company
The Company's cost of capital and ability to obtain external financing is affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. In June 1994, Standard & Poor's Corporation (S&P) and Duff & Phelps lowered the Company's security ratings citing relatively high customer rates in an increasingly competitive environment and a perceived credit risk associated with large purchased power commitments. Moody's Investors Service (Moody's) downgraded the Company's security ratings in August 1994 due, in part Moody's said, to the Company's relatively high cost structure. The Company's FMBs are currently rated at an equivalent of a BBB+ by the three major credit rating agencies, while the preferred stock issues have been assigned an equivalent of BBB. In addition, the Company's commercial paper is rated as having good credit quality. Although credit quality has been reduced, the Company's credit ratings remain above investment grade.
In 1994, the 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, was revised to "stable" from "negative" for the Company. The outlook reflects S&P's judgment that the Company's newly assigned BBB+ bond rating should be sustainable going forward without further decline anticipated in the near term. S&P also assigned the Company a "low average" business position, 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.
In June 1994, Moody's announced that it developed a new method to calculate the minimum price an electric utility must charge its customers in order to recover all of its generation costs. Moody's believes that an assessment of relative cost position will become increasingly critical to the credit analysis of electric utilities in a competitive marketplace. Specific rating actions are not anticipated, however, until the pace and implications of utility market deregulation are more certain.
The Company's bond indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Company can issue. The Company currently has interest and dividend coverage ratios well in excess of indenture and charter restrictions. The ability to issue securities in the future will depend on interest and dividend coverages at that time. Present plans call for the Company to issue long-term debt and Monthly Income Preferred Securities during the next three years to finance construction activities, fund the redemption of maturing senior securities and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION:
The Company targets capitalization ratios that should warrant sufficient credit quality ratings to permit capital market access at reasonable costs. Recent evaluations of the industry by credit rating agencies indicate that the Company may have to increase its equity ratio to maintain its current credit
Jersey Central Power & Light Company
ratings. GPU's financing plans contemplate security issuances in 1995 to strengthen the equity component of the Company and its affiliates' capital structures. The Company's targets and actual capitalization ratios are as follows:
Capitalization Target Range 1994 1993 1992
Common equity 48-51% 47% 47% 47% Preferred equity 8-10 7 7 9 Notes payable and long-term debt 44-39 46 46 44 100% 100% 100% 100%
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the continued development of additional competition in the electric utility industry.
In May 1994, the NJBPU approved the Company's request to implement a new rate initiative designed to retain and expand the economic base in its service territory. Under the contract rate service, the Company may enter into individual contracts to provide electric service to large commercial and industrial customers. This initiative will allow the Company more flexibility in responding to competitive pressures.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking regarding the recovery by utilities of legitimate and verifiable stranded costs. Costs incurred by a utility to provide integrated electric service to a franchise customer become stranded when that customer subsequently purchases power from another supplier using the utility's transmission services. Among other things, the FERC proposed that utilities be allowed under certain circumstances to recover such stranded costs associated with existing wholesale customer contracts, but not under new wholesale contracts unless expressly provided for in the contract. While it stated a "strong" policy preference that state regulatory agencies address recovery of stranded retail costs, the FERC also set forth alternative proposals for how it would address the matter if the states failed to do so. Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of Appeals for the District of Columbia, in an unrelated case, questioned the FERC's authority to permit utilities to recover stranded costs. The Court remanded the matter to the FERC for it to conduct an evidentiary hearing in the case to determine whether, among other things, permitting stranded cost recovery was so inherently anticompetitive that it violates antitrust laws. While largely supported by the electric utility industry, the Proposed Rulemaking has been strongly opposed by other groups. There can be no assurance as to the outcome of this proceeding.
Jersey Central Power & Light Company
In October 1994, the FERC issued a policy statement regarding pricing for electric transmission services. The policy statement contains five principles that will provide the foundation for the FERC's analyses of all subsequent transmission rate proposals. Recognizing the evolution of a more competitive marketplace, the FERC contends that it is critical that transmission services be priced in a manner that appropriately compensates transmission owners and creates adequate incentives for efficient system expansion.
In November 1994, the NJBPU issued a draft New Jersey Energy Master Plan Phase I Report promoting regulatory policy changes intended to move the state's electric and gas utilities into a competitive marketplace. In the draft, the NJBPU recommends, among other things, the adoption of 1) rate- flexibility legislation to allow utilities to compete in order to retain and attract customers; 2) alternatives to rate base/rate-of-return regulation; 3) consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities; and 4) an integrated resource planning and competitive supply-side procurement process to streamline the regulatory review process, lower costs, and ensure that the state's environmental and energy conservation goals are met in a competitive marketplace. Although the NJBPU proposes actions and regulatory reforms that encourage competition, the draft Plan calls for an evolutionary transition toward open markets. The recommendations are largely intended to be interim measures while the NJBPU investigates other issues, including retail wheeling and stranded costs, that are likely to affect the future of the electric utility industry. The New Jersey Energy Master Plan is being developed in three phases, with Phase I scheduled to be adopted in March 1995 and the remaining phases expected to be concluded by year-end 1995.
In 1994, the SEC issued for public comment a Concept Release regarding modernization of the Public Utility Holding Company Act of 1935 (Holding Company Act). GPU regards the Holding Company Act as a significant impediment to competition and supports its repeal. In addition, GPU believes that the Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally reformed given the burdens being placed on electric utilities by PURPA mandated uneconomic long-term power purchase agreements with nonutility generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning activities. Responding to its assessment that competition in the electric utility industry is likely to accelerate, GPU proceeded to implement two major organizational changes as well as other programs designed to reduce costs and strengthen GPU's competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the non-nuclear generation facilities owned by the Company and its affiliates as well as undertake responsibility to construct any new non-nuclear generation
Jersey Central Power & Light Company
facilities which the Company and its affiliates may need in the future. By forming GPU Generation Corporation (GPUGC), GPU will consolidate and streamline the management of these generation facilities, and seek to apply management and operating efficiency techniques similar to those employed in more competitive industries. This initiative is intended to bring the Company and its affiliates' generation costs more in line with projected market prices. GPU Nuclear Corporation is engaging in a search for parallel opportunities. The Company and its affiliates received regulatory approvals to enter into an operating agreement with GPUGC from the NJBPU and Pennsylvania Public Utility Commission. SEC authorization is expected to be received in 1995.
The second part of the realignment includes the management combination of the Company's affiliates, Metropolitan Edison Company and Pennsylvania Electric Company. This action is intended to increase effectiveness and lower costs of Pennsylvania customer operations and service functions.
Other organizational realignments, designed to streamline management and reduce costs, were also implemented throughout the GPU System in 1994. In addition, GPU expanded employee participation in its incentive compensation program to tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System workforce accepted the Voluntary Enhanced Retirement Programs. Future payroll and benefits savings, which are estimated to be $75 million annually (of which the Company's share is $31 million), began in the third quarter and reflect limiting the replacement of employees up to ten percent of those retired. Retirement benefits will be substantially paid from pension and postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the electric utility industry that calls into question the assumptions regarding the recovery of certain costs through ratemaking. As the utility industry continues to experience an increasingly competitive environment, GPU is attempting to assess the impact that these and other changes will have on the Company and its affiliates' financial position. For additional information regarding the other changes that may have an adverse effect on the Company, see the Competition and the Changing Regulatory Environment section of Note 1 to the Financial Statements.
Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term regional energy supply from existing facilities, as evidenced by the results of the Company's all-source competitive supply solicitation conducted in 1994, is less than the rates in virtually all of the Company's nonutility generation agreements. In addition, the projected cost of energy from new supply sources is now lower than was expected in the recent past due to improvements in power plant technologies and reduced fuel prices.
Jersey Central Power & Light Company
The long-term nonutility generation agreements included in the Company's supply plan have been entered into pursuant to the requirements of PURPA and state regulatory directives. The Company intends to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company is also attempting to renegotiate, and in some cases buy out, existing high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility generation costs from customers by the NJBPU, there can be no assurance that the Company will continue to recover these costs throughout the terms of the related agreements. The Company currently estimates that in 1998, when all of these nonutility generation projects are scheduled to be in-service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $120 million to $190 million annually.
THE SUPPLY PLAN:
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 Company's supply plan. As the Company prepares to operate in an increasingly competitive environment, its supply plan currently focuses on maintaining the existing customer base by offering competitively priced electricity.
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.
Over the next five years, the Company is projected to experience an average growth in sales to customers of about 2% annually. These increases are expected to result from continued economic growth in the service territory and a slight increase in customers. To meet this growth, assuming the continuation of existing retail electric regulation, the Company's plan consists of the continued utilization of existing generation facilities combined with power purchases, the construction of a new facility, and the utilization of capacity of its affiliates. The plan also includes the continued promotion of economic energy-conservation and load-management programs.
Jersey Central Power & Light Company
The Company'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. The Company will take necessary actions to avoid adding new capacity at costs that may exceed future market prices. In addition, the Company will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected market prices.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility generators, the replacement of expiring utility purchase contracts at lower costs, and the construction of a new peaking unit. The supply plan also includes the addition of approximately 265 MW of currently uncommitted capacity. Additional capacity needs are principally related to the expiration of existing commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility generators under which a total of 882 MW of capacity is currently in service and about an additional 294 MW are currently scheduled or anticipated to be in service by 1998.
In January 1994, the Company issued an all-source solicitation for the short- to intermediate-term supply of energy and capacity to determine and evaluate the availability of competitively priced power supply options. The Company is completing contract negotiations with three suppliers to purchase about 350 MW of capacity beginning in 1996, increasing to approximately 700 MW by 1999, for terms of up to eight years. The Company 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.
The Company has commenced construction of a 141 MW gas-fired combustion turbine at its Gilbert Generating Station. The new facility is estimated to cost $50 million and, coupled with the retirement of two older units, will result in a net capacity increase of approximately 95 MW. The project is expected to be in-service by mid-1996. Petitions have been filed with the NJBPU by two organizations seeking, among other things, reconsideration of the NJBPU's order which found that New Jersey's Electric Facility Need Assessment Act is not applicable to this combustion turbine and that construction of this facility, without a market test, is consistent with New Jersey energy policies. This matter is pending.
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially reduce above-market payments for energy supplied by nonutility generators. The Company will also continue to take legal, regulatory and legislative
Jersey Central Power & Light Company
initiatives to avoid entering into any new power-supply agreements that are either not needed or, if needed, are not consistent with competitive market pricing. The following is a discussion of major nonutility generation activities involving the Company.
In a 1993 order, the NJBPU directed all utilities to identify nonutility generation contracts which were uneconomic and, therefore, candidates for buyout or other remedial measures. The Company identified a proposed 100 MW nonutility generation project as such a candidate, but was unable to negotiate a buyout or contract repricing to a level consistent with prices of replacement power. The NJBPU therefore ordered that hearings be held to determine whether their order approving the agreement should be modified or revoked. After hearings commenced in early 1994, the nonutility generator filed a complaint with the U.S. District Court seeking to enjoin the NJBPU proceedings on the grounds they were preempted by PURPA. The District Court dismissed the complaint finding, among other things, that the federal courts did not have jurisdiction to consider the matter. In January 1995, however, the U.S. Court of Appeals for the Third Circuit overturned the District Court decision. The Court of Appeals held, among other things, that once the NJBPU approves a power purchase agreement under PURPA and approves the utility's collection of costs from its customers, PURPA preempts the NJBPU from altering its order approving the contract and the Company's recovery from customers of its payment to the nonutility generator. The Court of Appeals reached its decision despite the contract provision that if the NJBPU at any time in the future disallowed any such rate recovery, the Company's payments to the nonutility generator would be equally reduced. The Company, the NJBPU and the New Jersey Division of Rate Advocate have each filed motions for rehearing with the Court of Appeals.
In 1994, a nonutility generator requested that the NJBPU order the Company to enter into a long-term agreement to buy capacity and energy. The Company is contesting this request and the NJBPU has referred this matter to an Administrative Law Judge for hearings.
In May 1994, the NJBPU issued an order granting two nonutility generators, aggregating 200 MW, a final in-service date extension for projects originally scheduled to be operational in 1997. In June 1994, the Company appealed the NJBPU's decision to the Appellate Division of the New Jersey Superior Court. The NJBPU order extends the in-service date for one year plus the period until the Company's appeals are decided.
As part of the effort to reduce above-market payments under nonutility generation agreements, the Company and its affiliates are seeking to implement a program under which the natural gas fuel and transportation for the Company and its affiliates' gas-fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, would be pooled and managed by a nonaffiliated fuel manager. The Company and its affiliates believe the plan has the potential to provide substantial savings for their customers. The Company and its affiliates have begun initial discussions with the nonutility generators who would be eligible to participate. Requirements for approval of the plan by state and federal regulatory agencies are being reviewed.
Jersey Central Power & Light Company
Conservation and Load Management
The NJBPU continues to encourage the development of new conservation and load-management programs. Because the benefits of some of these programs may not offset program costs, the Company is working to mitigate the impacts these programs can have on the Company's competitive position in the marketplace.
The Company continues to conduct demand-side management (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 Company programs have resulted in summer peak demand reductions of over 43 MW through 1994.
ENVIRONMENTAL ISSUES:
The Clean Air Act Amendments of 1990 (Clean Air Act) require substantial reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000. To comply with the Clean Air Act, the Company expects to spend up to $58 million by the year 2000 for pollution control equipment. Through December 31, 1994, the Company has made capital expenditures of approximately $16 million to comply with the Clean Air Act requirements.
In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate the risk of recovering capital investments compared to increased participation in the emission allowance market and the use of low-sulfur coal or the early retirement of facilities. These and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected 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 the Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Company and its affiliates and GPU and are still pending. For more information, see Note 1 to the Financial Statements.
Jersey Central Power & Light Company
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since the regulatory process results in a time lag during which increased operating expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry, the Company does not plan to take any actions that would increase customers' base rates over the next several years. Therefore, the control of operating and capital costs will be essential. As competition and deregulation accelerate, there can be no assurance as to the recovery of increased operating expense or utility plant investments.
The Company 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. Though currently operating in a regulated environment, the Company's focus will be less reliant on the ratemaking process, and geared toward continued performance improvement and cost reduction to facilitate the competitive pricing of its products and services.
Jersey Central Power & Light Company
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter 1994* 1993 1994** 1993
Operating revenues $486 910 $448 634 $458 897 $463 354
Operating income 71 521 51 411 29 270 57 053
Net income 53 097 30 830 5 175 31 551
Earnings available for common stock 49 398 26 124 1 476 26 845
In Thousands
Third Quarter Fourth Quarter 1994 1993 1994 1993***
Operating revenues $567 827 $576 268 $438 791 $447 653
Operating income 99 304 98 552 54 183 49 914
Net income 74 573 75 239 29 996 20 724
Earnings available for common stock 70 875 71 540 26 297 17 025
* Results for the first quarter 1994 reflect an increase in earnings of $7.4 million after-tax for interest income from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of $30.4 million after-tax for costs related to the Voluntary Enhanced Retirement Programs.
*** Results for the fourth quarter 1993 reflect a decrease in earnings of $6.0 million after-tax for the write-off of the Duquesne transactions.
Jersey Central Power & Light Company
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors Jersey Central Power & Light Company Morristown, New Jersey
We have audited the financial statements and financial statement schedule of Jersey Central Power & Light 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jersey Central Power & Light Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 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 financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
As more fully discussed in Note 1 to financial statements, the Company is unable to determine the ultimate consequences of the contingency which has resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The matter which remains uncertain is the excess, if any, of amounts which might be paid in connection with claims for damages resulting from the accident over available insurance proceeds.
As discussed in Notes 5 and 7 to the financial statements, the Company was required to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993.
New York, New York COOPERS & LYBRAND L.L.P. February 1, 1995
Jersey Central Power & Light Company
STATEMENTS OF INCOME
(In Thousands) For the Years Ended December 31, 1994 1993 1992
Operating Revenues $1 952 425 $1 935 909 $1 774 071
Operating Expenses: Fuel 94 503 98 683 84 851 Power purchased and interchanged: Affiliates 18 661 23 681 24 281 Others 579 948 578 131 616 418 Deferral of energy and capacity costs, net (19 448) 28 726 4 232 Other operation and maintenance 526 623 460 128 424 285 Depreciation and amortization 191 042 182 945 167 022 Taxes, other than income taxes 231 070 228 690 215 507 Total operating expenses 1 622 399 1 600 984 1 536 596
Operating Income Before Income Taxes 330 026 334 925 237 475 Income taxes 75 748 77 995 43 621 Operating Income 254 278 256 930 193 854
Other Income and Deductions: Allowance for other funds used during construction 893 2 471 4 015 Other income, net 21 995 6 281 21 519 Income taxes (9 372) (2 847) (8 268) Total other income and deductions 13 516 5 905 17 266
Income Before Interest Charges 267 794 262 835 211 120
Interest Charges: Interest on long-term debt 93 477 100 246 92 942 Other interest 14 726 6 530 4 873 Allowance for borrowed funds used during construction (3 250) (2 285) (4 056) Total interest charges 104 953 104 491 93 759
Net Income 162 841 158 344 117 361 Preferred stock dividends 14 795 16 810 20 604 Earnings Available for Common Stock $ 148 046 $ 141 534 $ 96 757
The accompanying notes are an integral part of the financial statements.
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands) December 31, 1994 1993
ASSETS Utility Plant: In service, at original cost $4 119 617 $3 938 700 Less, accumulated depreciation 1 499 405 1 380 540 Net utility plant in service 2 620 212 2 558 160 Construction work in progress 136 884 102 178 Other, net 123 349 116 751 Net utility plant 2 880 445 2 777 089
Other Property and Investments: Nuclear decommissioning trusts 165 511 139 279 Nuclear fuel disposal fund 82 920 82 095 Other, net 6 906 5 802 Total other property and investments 255 337 227 176
Current Assets: Cash and temporary cash investments 1 041 17 301 Special deposits 4 608 7 124 Accounts receivable: Customers, net 126 760 133 407 Other 16 936 31 912 Unbilled revenues 59 288 57 943 Materials and supplies, at average cost or less: Construction and maintenance 95 937 102 659 Fuel 18 563 11 886 Deferred income taxes 10 454 28 650 Prepayments 45 880 58 057 Total current assets 379 467 448 939
Deferred Debits and Other Assets: Three Mile Island Unit 2 deferred costs 138 294 146 284 Unamortized property losses 104 451 109 478 Deferred income taxes 122 944 110 794 Income taxes recoverable through future rates 132 642 121 509 Other 323 208 327 886 Total deferred debits and other assets 821 539 815 951
Total Assets $4 336 788 $4 269 155
The accompanying notes are an integral part of the financial statements.
Jersey Central Power & Light Company
BALANCE SHEETS
(In Thousands) December 31, 1994 1993
LIABILITIES AND CAPITAL Capitalization: Common stock $ 153 713 $ 153 713 Capital surplus 435 715 435 715 Retained earnings 772 240 724 194 Total common stockholder's equity 1 361 668 1 313 622 Cumulative preferred stock: With mandatory redemption 150 000 150 000 Without mandatory redemption 37 741 37 741 Long-term debt 1 168 444 1 215 674 Total capitalization 2 717 853 2 717 037
Current Liabilities: Debt due within one year 47 439 60 008 Notes payable 110 356 - Obligations under capital leases 102 059 89 631 Accounts payable: Affiliates 34 283 34 538 Other 118 369 95 509 Taxes accrued 22 561 119 337 Deferred energy credits 148 23 633 Interest accrued 29 765 33 804 Other 75 159 50 950 Total current liabilities 540 139 507 410
Deferred Credits and Other Liabilities: Deferred income taxes 598 843 569 966 Unamortized investment tax credits 72 928 79 902 Three Mile Island Unit 2 future costs 85 273 79 967 Other 321 752 314 873 Total deferred credits and other liabilities 1 078 796 1 044 708
Commitments and Contingencies (Note 1)
Total Liabilities and Capital $4 336 788 $4 269 155
The accompanying notes are an integral part of the financial statements.
Jersey Central Power & Light Company
NOTES TO FINANCIAL STATEMENTS
Jersey Central Power & Light Company (the Company), which was incorporated under the laws of New Jersey in 1925, is a wholly owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to herein as the "Company and its affiliates." The Company is also 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), and EI Power, Inc., which develop, own and operate nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in three major nuclear projects -- Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by the Company, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by the Company. At December 31, the Company's net investment in TMI-1, TMI-2 and Oyster Creek, including nuclear fuel, was as follows:
Net Investment (Millions) TMI-1 TMI-2 Oyster Creek 1994 $162 $ 89 $817 1993 $173 $ 95 $784
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates 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
Jersey Central Power & Light Company
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 accident cleanup program was completed in 1990. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates and the suppliers of equipment and services to TMI- 2, and are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery on the basis of alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Company and its affiliates had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against GPU and the Company and its affiliates and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is likely to begin in 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases
Jersey Central Power & Light Company
from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals.
In an Order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against GPU and the Company and its affiliates; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1994 dollars) for TMI-1 is $157 million, of which the Company's share is $39 million, and $189 million for Oyster Creek. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
Jersey Central Power & Light Company
In 1988, a consultant to GPUN performed site-specific studies of TMI-1 and Oyster Creek that considered various decommissioning plans and estimated the cost of decommissioning the radiological portions of each plant to range from approximately $225 million to $309 million, of which the Company's share would range from $56 million to $77 million, and $239 to $350 million, respectively (adjusted to 1994 dollars). In addition, the studies estimated the cost of removal of nonradiological structures and materials for TMI-1 and Oyster Creek at $74 million, of which the Company's share is $18 million, and $48 million, respectively (adjusted to 1994 dollars).
The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company and its affiliates charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990 to TMI-2's external trust. Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the balance sheet.
TMI-1 and Oyster Creek:
The Company is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. The Company is also collecting revenues, 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 rate orders issued in 1991 and 1993 by the New Jersey Board of Public Utilities (NJBPU), for its share of the cost of removal of nonradiological structures and materials. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditures of these funds has been made in accumulated depreciation, amounting to $17 million for TMI-1 and $100 million for Oyster Creek at December 31, 1994. Oyster Creek and TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the radiological decommissioning of TMI-2, reflecting the NRC funding target in 1994 dollars. The Company and its affiliates record escalations, when applicable, in the liability based upon changes in the NRC funding target.
Jersey Central Power & Light Company
The Company and its affiliates have also recorded a liability for incremental costs specifically attributable to monitored storage. In addition, the Company and its affiliates have recorded a liability for nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $2 million, of which the Company's share is $.5 million, as of December 31, 1994. Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and 1993 for the Company are as follows:
(Millions) (Millions) 1994 1993
Radiological Decommissioning $63 $57 Nonradiological Cost of Removal 18 18 Incremental Monitored Storage 5 5 Total $86 $80
The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. At December 31, 1994, $45 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and $51 million was recoverable from customers and included in Three Mile Island Unit 2 Deferred Costs on the balance sheet. The Company has expensed and made a nonrecoverable contribution of $15 million to an external decommissioning trust. The Company's share of earnings on trust fund deposits are offset against amounts shown on the balance sheet under Three Mile Island Unit 2 Deferred Costs as collectible from customers. The NJBPU has granted decommissioning revenues for the Company's share of the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. The Company intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage in late 1993, the Company and its affiliates are incurring incremental annual storage costs of approximately $1 million, of which the Company's share is $.25 million. The Company and its affiliates estimate that the remaining annual storage costs will total $19 million, of which the Company's share is $5 million, through 2014, the expected retirement date of TMI-1. The Company's rates reflect its $5 million share of these costs.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company.
Jersey Central Power & Light Company
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 is excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and facilities, the GPU System is subject to retrospective premium assessments of up to $69 million, of which the Company's share is $41 million, in any one year, in addition to those payable (up to $20 million, of which the Company's share is $13 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
Jersey Central Power & Light Company
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Company has entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Company to purchase at the contract price all of the power produced up to the contract limits. As of December 31, 1994, facilities covered by these agreements having 882 MW of capacity were in service. Payments made pursuant to these agreements were $304 million, $292 million and $316 million for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated to aggregate $395 million, $556 million, $571 million, $587 million and $607 million, respectively. These agreements, together with those for facilities which are not yet in operation, provide for the purchase of approximately 1,176 MW of capacity and energy by the Company by the mid-to- late 1990s, at varying prices.
The emerging competitive generation market has created uncertainty regarding the forecasting of the GPU System's energy supply needs which has caused the Company and its affiliates to change their supply strategy to now
Jersey Central Power & Light Company
seek shorter-term agreements offering more flexibility (see Management's Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current availability of excess capacity in the market place, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing generation facilities is currently competitively priced. 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 Company's and its affiliates' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources. These agreements have been entered into pursuant to the requirements of the federal Public Utility Regulatory Policies Act and state regulatory directives. The Company's and its affiliates' have initiated lawful actions which are intended to substantially reduce these above market payments. In addition, the Company and its affiliates intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company and its affiliates are also attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery of their nonutility generation costs from customers by the NJBPU and the Pennsylvania Public Utility Commission (PaPUC), there can be no assurance that the Company and its affiliates will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that in 1998, when substantially all of the these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas- fired combined cycle facility) will range from $300 million to $450 million annually, of which the Company's share will range from $120 million to $190 million annually. Moreover, efforts to lower these costs have led to disputes before both the NJBPU and the PaPUC, as well as to litigation, and may result in claims against the Company and its affiliates for substantial damages. There can be no assurance as to the outcome of these matters.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles and 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.
Jersey Central Power & Light Company
To comply with the federal Clean Air Act Amendments (Clean Air Act) of 1990, the Company expects to spend up to $58 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the Company 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.
The Company has been notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 7 hazardous and/or toxic waste sites. In addition, the Company has been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The Company has 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 Company.
The Company has entered into agreements with the New Jersey Department of Environmental Protection for the investigation and remediation of 17 formerly owned manufactured gas plant sites. One of these sites has been repurchased by the Company. The Company has also entered into various cost- sharing agreements with other utilities for some of the sites. As of December 31, 1994, the Company has an estimated environmental liability of $32 million recorded on its balance sheet relating to these sites. The estimated liability is based upon ongoing site investigations and remediation efforts, including capping the sites and pumping and treatment of ground water. If the periods over which the remediation is currently expected to be performed are lengthened, the Company believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties as the Company does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If the Company is required to utilize different remediation methods, the costs could be materially in excess of $60 million.
In 1993, the NJBPU approved a mechanism similar to the Company's Levelized Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas plant remediation costs when expenditures exceed prior collections. The NJBPU decision provides for interest to be credited to customers until the overrecovery is eliminated and for future costs to be amortized over seven years with interest. A final NJBPU order dated December 16, 1994 indicated that interest is to be accrued retroactive to June 1993.
Jersey Central Power & Light Company
The Company is pursuing reimbursement of the above costs from its insurance carriers. In November 1994, the Company filed a complaint with the Superior Court of New Jersey against several of its insurance carriers, relative to these manufactured gas plant sites. The Company requested the Court to order the insurance carriers to reimburse the Company for all amounts it has paid, or may be required to pay, in connection with the remediation of the sites.
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement Programs (VERP) to certain employees. The enhanced retirement programs were part of a corporate realignment undertaken in 1994. Approximately 82% of eligible GPU System employees accepted the retirement programs, resulting in a pre-tax charge to earnings of $127 million, of which the Company's share is $47 million. These charges are included as Other Operation and Maintenance on the income statement.
The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $220 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured.
The Company has entered into a long-term contract with a nonaffiliated mining company for the purchase of coal for the Keystone generating station in which the Company owns a one-sixth undivided interest. This contract, which expires in 2004, requires the purchase of minimum amounts of the station's coal requirements. The price of the coal under the contract is based on adjustments of indexed cost components. The Company's share of the cost of coal purchased under this agreement is expected to aggregate $21 million for 1995.
The Company and its affiliates have entered into agreements and the Company is completing contract negotiations with three other utilities to purchase capacity and energy for various periods through 2004. These agreements, including contracts under negotiation, will provide for up to 1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW by 2004. For the years 1995, 1996, 1997, 1998, and 1999, the Company's share of payments
Jersey Central Power & Light Company
pursuant to these agreements are estimated to aggregate $202 million, $175 million, $162 million, $145 million and $128 million, respectively. The Company's contract negotiations are the result of its all-source solicitation for competitively priced, short- to intermediate-term energy and capacity, described in the New Energy Supplies section of Management's Discussion and Analysis.
The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from nonutility generation projects. The proceeding was initiated, in part, to respond to contentions of the Division of the Ratepayer Advocate (Ratepayer Advocate), that by permitting utilities to recover such costs through the LEAC, an excess or "double recovery" may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1993, the Company and the other New Jersey electric utilities filed motions for summary judgment with the NJBPU. Ratepayer Advocate has filed a brief in opposition to the utilities' summary judgment motions including a statement from its consultant that in his view, the "double recovery" for the Company for the 1988-92 LEAC periods would be approximately $102 million. In 1994, the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent LEACs remain open for further investigation. This matter is pending before a NJBPU Administrative Law Judge. Management estimates that the potential exposure for LEAC periods subsequent to 1991 is approximately $67 million through February 1996, the end of the next LEAC period. There can be no assurance as to the outcome of this proceeding.
The Company's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate annual generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect on net income of the performance standard charge at a 40% capacity factor would be approximately $11 million. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBPU for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC.
During the normal course of the operation of its business, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these types of matters would have a material effect on the Company's financial position or results of operations.
Jersey Central Power & Light Company
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS The Company's accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the NJBPU. Certain reclassifications of prior years' data have been made to conform with current presentation.
REVENUES The Company recognizes 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.
UTILITY PLANT It is the policy of the Company to record additions to utility plant (material, labor, overhead and an allowance for funds used during construction) at cost. The cost of current repairs and minor replacements is charged to appropriate operating and maintenance expense and clearing accounts, and the cost of renewals is capitalized. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.
DEPRECIATION The Company provides for depreciation at annual rates determined and revised periodically, on the basis of studies, to be sufficient to depreciate the original cost of depreciable property over estimated remaining service lives,which are generally longer than those employed for tax purposes. The Company used depreciation rates which, on an aggregate composite basis, resulted in annual rates of 3.62%, 3.59% and 3.51% for the years 1994, 1993 and 1992, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the 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 5.35%, 7.80% and 8.19% for the years 1994, 1993 and 1992, respectively.
Jersey Central Power & Light Company
AMORTIZATION POLICIES Accounting for TMI-2 and Forked River Investments:
The Company is collecting annual revenues for the amortization of TMI-2 of $9.6 million. This level of revenue will be sufficient to recover the remaining investment by 2008. At December 31, 1994, $91 million is included in Unamortized Property Losses on the balance sheet for the Company's Forked River project. The Company is collecting annual revenues for the amortization of this project of $11.2 million, which will be sufficient to recover its remaining investment by the year 2006. Because the Company has not been provided revenues for a return on the unamortized balances of 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 Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1994 amounted to $25 million 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 Company made its initial payment to this fund in 1993, and is recovering the remaining amounts through its fuel clause. At December 31, 1994, $27 million is recorded on the balance sheet in Deferred Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS The Company accrues incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE The Company is providing for estimated future disposal costs for spent nuclear fuel at Oyster Creek and TMI-1 in accordance with the Nuclear Waste Policy Act of 1982. The Company entered into contracts in 1983 with the DOE for the disposal of spent nuclear fuel. The total liability under these contracts, including interest, at December 31, 1994, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $114 million, and is reflected in Deferred Credits and Other Liabilities - Other. As the actual liability is substantially in excess of the amount recovered to date from ratepayers, the Company has reflected such excess of
Jersey Central Power & Light Company
$28 million at December 31, 1994 in Deferred Debits and Other Assets - Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over remaining periods of 12 years.
The Company is collecting one mill per kilowatt-hour from its customers for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. This amount is 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 Company implemented Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes" which requires the use of the liability method of financial accounting and reporting for income taxes. Under FAS 109, deferred income taxes reflect the impact of temporary differences between the 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, 1994, the Company had $110 million of short-term notes outstanding, of which $33 million was commercial paper and the remainder was issued under bank lines of credit (credit facilities).
Jersey Central Power & Light Company
GPU and the Company and its affiliates have $528 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, 1994 and 1993, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1994: Cumulative preferred stock with mandatory redemption $ 150 $ 140 Long-term debt 1,168 1,051
December 31, 1993: Cumulative preferred stock with mandatory redemption $ 150 $ 161 Long-term debt 1,216 1,276
The fair values of the Company's long-term debt and preferred stock with mandatory redemption 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." In 1993, the cumulative effect on net income of this accounting change was immaterial. Also in 1993, the federal income tax rate changed from 34% to 35%, retroactive to January 1, 1993, resulting in an increase in the deferred tax assets of $5 million and an increase in the deferred tax liabilities of $20 million. The tax rate change did not have a material effect on net income as the changes in deferred taxes were substantially offset by the recording of regulatory assets and liabilities. As of December 31, 1994 and 1993, the balance sheet reflected $132 million and $122 million, respectively, of income taxes recoverable through future rates, (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $40 million and $43 million, respectively, (related to unamortized ITC), substantially due to the recognition of amounts not previously recorded.
Jersey Central Power & Light Company
A summary of the components of deferred taxes as of December 31, 1994 and 1993 is as follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993 Current: Current: Unbilled revenue $ 10 $ 9 Revenue taxes - 12 Revenue taxes $ 18 $ - Other - 8 Deferred energy - - Total $ 10 $ 29 Total $ 18 $ - Noncurrent: Noncurrent: Unamortized ITC $ 40 $ 43 Liberalized Decommissioning 25 19 depreciation: Contribution in aid previously flowed of construction 20 17 through $ 86 $ 80 Other 38 32 future revenue Total $ 123 $111 requirements 46 42 Subtotal 132 122 Liberalized depreciation 383 364 Forked River 54 30 Other 29 54 Total $ 598 $ 570
The reconciliations from net income to book income subject to tax and from the federal statutory rate to combined federal and state effective tax rates are as follows:
(In Millions) 1994 1993 1992
Net income $163 $158 $117 Income tax expense 85 81 52 Book income subject to tax $248 $239 $169
Federal statutory rate 35% 35% 34% Other (1) (1) (3) Effective income tax rate 34% 34% 31%
Jersey Central Power & Light Company
Federal and state income tax expense is comprised of the following:
(In Millions) 1994 1993 1992 Provisions for taxes currently payable $ 50 $ 42 $ 37
Deferred income taxes: Liberalized depreciation 13 19 24 Gain/Loss on reacquired debt 6 9 4 New Jersey revenue tax 32 32 3 Deferral of energy costs 9 (8) - Abandonment loss - Forked River (5) (4) (4) Nuclear outage maintenance costs 6 - (3) Accretion income 6 6 6 Unbilled revenues 2 5 (2) VERP (15) - - Other (12) (14) (6) Deferred income taxes, net 42 45 22 Amortization of ITC, net ( 7) ( 6) ( 7) Income tax expense $ 85 $ 81 $ 52
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) 1994 1993 1992
Maintenance $ 132 $135 $125 Other taxes: New Jersey unit tax $ 204 $202 $197 Real estate and personal property 7 6 7 Other 20 21 12 Total $ 231 $229 $216
Jersey Central Power & Light Company
For the years 1994, 1993 and 1992, the cost to the Company of services rendered to it by GPUSC amounted to approximately $48 million, $39 million and $37 million, respectively, of which approximately $37 million, $29 million and $28 million, respectively, was charged to income. For the years 1994, 1993 and 1992, the cost to the Company of services rendered to it by GPUN amounted to approximately $268 million, $227 million and $247 million, respectively of which approximately $205 million, $184 million and $170 million, respectively was charged to income. For the years 1994, 1993 and 1992, the Company purchased $22 million, $23 million and $22 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) 1994 1993 1992
Service cost-benefits earned during the period $ 8.8 $ 8.7 $ 8.1 Interest cost on projected benefit obligation 29.0 29.4 27.6 Less: Expected return on plan assets (33.3) (32.1) (29.1) Amortization (.5) (.4) (.6) Net periodic pension cost $ 4.0 $ 5.6 $ 6.0
The above 1994 amounts do not include a pre-tax charge to earnings of $38 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992 were gains of $4.4 million, $48.0 million and $17.5 million, respectively.
The funded status of the plans and related assumptions at December 31, 1994 and 1993 were as follows:
Jersey Central Power & Light Company
(In Millions) 1994 1993 Accumulated benefit obligation (ABO): Vested benefits $ 335.9 $ 310.7 Nonvested benefits 34.3 36.2 Total ABO 370.2 346.9 Effect of future compensation levels 55.9 61.8 Projected benefit obligation (PBO) $ 426.1 $ 408.7
PBO $ (426.1) $ (408.7) Plan assets at fair value 403.7 425.2 PBO (in excess of) less than plan assets (22.4) 16.5 Less: Unrecognized net loss (gain) 13.3 (10.1) Unrecognized prior service cost 3.5 4.0 Unrecognized net transition asset (2.5) (4.3) (Accrued) prepaid pension cost $ (8.1) $ 6.1
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5 Annual increase in compensation levels 6.0 5.0
In 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the PBO as of December 31, 1994. Also, in 1994, the PBO increased by $25 million as a result of the VERP. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net loss (gain) represents actual experience different from that assumed, which is deferred and not included in the determination of pension cost until it exceeds certain levels. The unrecognized prior service cost resulting from retroactive changes in benefits 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 as a charge or credit to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1994, 1993 and 1992 were $2.4 million, $2.4 million and $2.1 million, respectively.
Jersey Central Power & Light Company
Postretirement Benefits Other than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. For 1992, the annual premium costs associated with providing these benefits totaled approximately $4.5 million.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1994 and 1993 follows:
(In Millions) 1994 1993 Service cost-benefits attributed to service during the period $ 3.3 $ 3.4 Interest cost on the accumulated postretirement benefit obligation 9.4 10.4 Expected return on plan assets (1.7) (.7) Amortization of transition obligation 5.2 5.7 Other amortization, net .4 - Net periodic postretirement benefit cost 16.6 18.8 Less, deferred for future recovery (7.8) (9.6) Postretirement benefit cost, net of deferrals $ 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 $6.1 million of allocated postretirement benefit costs from the Company's affiliates for 1994.
The actual return on the plans' assets for the years 1994 and 1993 was a gain of $.6 million and $.9 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as follows:
Jersey Central Power & Light Company
(In Millions) 1994 1993 Accumulated Postretirement Benefit Obligation: Retirees $ 72.0 $ 52.7 Fully eligible active plan participants 24.7 28.8 Other active plan participants 47.1 58.2 Total accumulated postretirement benefit obligation (APBO) $ 143.8 $ 139.7
APBO $(143.8) $(139.7) Plan assets at fair value 26.0 10.3 APBO in excess of plan assets (117.8) (129.4) Less: Unrecognized net loss 7.5 7.5 Unrecognized transition obligation 90.0 108.3 Accrued postretirement benefit liability $ (20.3) $ (13.6)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5
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 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $10 million decrease in the APBO as of December 31, 1994. Also, in 1994, the APBO increased by $8 million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for Medicare, then decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $14 million as of December 31, 1994 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 (EITF) 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
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, 1994:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation Three Mile Island Unit 1 25 $202.4 $ 63.1 Keystone 16.67 84.5 20.8 Yards Creek 50 26.4 6.7
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $99 million and $86 million, respectively (net of amortization of $68 million and $44 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. An aggregate of up to $250 million ($125 million each for Oyster Creek and TMI-1) of nuclear fuel costs may be outstanding at any one time. It is contemplated that when consumed, portions of the 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 are renewable annually. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1994, 1993 and 1992 these amounts were $28 million, $34 million and $36 million, respectively. The leases may be terminated at any time with at least five months notice by either party prior to the end of the current period. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.
The Company has sold and leased back substantially all of its ownership interest in the Merrill Creek Reservoir Project. The minimum lease payments under this operating lease, which has a remaining term of 38 years, averages 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
In 1994, earnings available for common stock decreased $73.1 million resulting in a net loss of $2.2 million. The 1994 earnings decrease was principally attributable to a second quarter write-off of $72.8 million after- tax from an unfavorable Pennsylvania Commonwealth Court order disallowing the collection of revenues for certain Three Mile Island Unit 2 (TMI-2) retirement costs and a $20.1 million after-tax charge to earnings for costs related to the Voluntary Enhanced Retirement Programs. The effect of these charges was partially offset by first quarter interest income of $13 million after-tax from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
Also contributing to the 1994 earnings decrease was increased other operation and maintenance (O&M) expense, which included higher emergency and winter storm repairs. Earnings were favorably affected by reduced reserve capacity expense.
In 1993, earnings available for common stock increased $8.1 million to $70.9 million. The increase in earnings was principally due to higher kilowatt-hour sales due primarily to the significantly warmer summer temperatures as compared with the mild weather in 1992. This increase was partially offset by the write-off of $4.8 million after-tax of costs related to the cancellation of proposed energy-related agreements, increased interest charges and an increase in other O&M expense.
The Company's return on average common equity was (.4)% for 1994 as compared to 12.2% for 1993.
OPERATING REVENUES:
Revenues in 1994 decreased slightly to $801.3 million after decreasing 2.5% to $801.5 million in 1993. The components of these changes are as follows:
(In Millions) 1994 1993 Kilowatt-hour (KWH) revenues (excluding energy portion) $ .4 $ 12.4 Rate increases - .5 Energy revenues (2.2) (35.7) Other revenues 1.6 2.5 Decrease in revenues $ (.2) $(20.3)
Metropolitan Edison Company and Subsidiary Companies
Kilowatt-hour revenues
The increase in KWH revenues was due principally to an increase in nonweather-related customer usage and an increase in the average number of customers. New customer growth occurred primarily in the residential sector. The increase was partially offset by lower sales to other utilities.
KWH revenues increased due principally to an increase in weather- related sales and an increase in the average number of customers, partially offset by a decrease in nonweather-related customer usage. New customer growth, which occurred in the commercial and residential sectors, was partially offset by a slight reduction in the number of industrial customers.
Energy revenues
1994 and 1993 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 decreased in 1994 primarily from lower electric sales to other utilities offset partially by higher sales to ultimate customers. The 1993 decrease in energy revenues is due principally to lower electric sales to other utilities and lower energy cost rates in effect.
Other revenues
1994 and 1993 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
1994 and 1993 Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy cost rate. The 1994 decrease was primarily attributable to reductions in reserve capacity expense and energy purchases from other utilities, offset partially by an increase in nonutility generation purchases. The reduction in reserve capacity expense favorably affected earnings since these costs are not recovered through energy revenues. Power purchased and interchanged increased in 1993 primarily as a result of increases in nonutility generation purchases.
Other operation and maintenance
The increase in other O&M expense was primarily attributable to a $35.2 million pre-tax charge for costs related to the Voluntary Enhanced Retirement
Metropolitan Edison Company and Subsidiary Companies
Programs. Increases were also attributable 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.
Other O&M expense increased primarily due to emergency and storm- related activities and increased costs related to fossil plant outages.
Depreciation and amortization
Depreciation and amortization expense decreased in 1993 due to decreases in the amortization relating to TMI-2, partially offset by additions to utility plant. Additions to utility plant primarily consist of additions to existing generating facilities to maintain system reliability and additions to the transmission and distribution system related to new customer growth.
Taxes, other than income taxes
1994 and 1993 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
The increase in other expense is related principally to the second quarter write-off of future TMI-2 retirement costs. The effect of this write- off was partially offset by first quarter interest income resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993 Pennsylvania Public Utility Commission (PaPUC) order that permitted the Company to recover estimated TMI-2 retirement costs from customers. As a result, second quarter charges were taken totaling $127.6 million pre-tax. These charges were comprised of $117.6 million for retirement costs and $10 million for monitored storage costs.
The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. The effect on pre-tax earnings was an increase of $29.8 million in interest income.
The reduction in other income was principally due to the write-off of $8.1 million pre-tax of costs related to the cancellation of proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne Light Company.
Metropolitan Edison Company and Subsidiary Companies
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES: Interest charges
Other interest expense was higher due primarily to the tax retirement of TMI-2, which resulted in a $7 million pre-tax increase in interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Interest on long-term debt increased primarily due to the issuance of additional long-term debt, offset partially by decreases associated with the refinancing of higher cost debt at lower interest rates.
Dividends on preferred securities of subsidiary
The increase is attributable to the payment of dividends on the Monthly Income Preferred Securities issued by the Company's special-purpose finance subsidiary, Met-Ed Capital L.P.
PREFERRED STOCK DIVIDENDS:
1994 and 1993 Preferred stock dividends decreased in 1994 and 1993 due to the redemption of $35 million and $81 million stated value of preferred stock, respectively.
LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS:
The Company's capital needs were $160 million in 1994, consisting of cash construction expenditures. During 1994, construction funds were used primarily to maintain and improve existing generation facilities and the transmission and distribution system, proceed with various clean air compliance projects, and build a new generation facility. For 1995, construction expenditures are estimated to be $115 million, consisting mainly of $96 million for ongoing system development and $18 million for clean air requirements. The 1995 estimated reduction is largely due to the completion in 1994 of a significant portion of clean air compliance requirements and a new generation facility. Expenditures for maturing debt are expected to be $41 million for 1995 and $15 million for 1996. In the late 1990s, construction expenditures are expected to include substantial amounts for clean air requirements and other Company needs. Management estimates that approximately one-half of the Company's 1995 capital needs will be satisfied through internally generated funds.
Metropolitan Edison Company and Subsidiary Companies
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $125 million of nuclear fuel costs may be outstanding at any one time for TMI-1. The Company's share of the nuclear fuel capital leases at December 31, 1994 totaled $33 million. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $16 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 1994, the Company issued $100 million of Monthly Income Preferred Securities (carried on the balance sheet as Preferred securities of subsidiary) through its special-purpose finance subsidiary, and an aggregate of $50 million principal amount of long-term debt. A portion of these proceeds was used to refinance long-term debt and redeem more costly preferred stock amounting to $26 million and $35 million, respectively.
GPU has requested regulatory authorization from the Securities and Exchange Commission (SEC) to issue up to five million shares of additional common stock through 1996. The proceeds from the sale of such additional common stock would be used to increase the Company and its affiliates' common equity ratios and reduce GPU short-term debt. GPU will monitor the capital markets as well as its capitalization ratios relative to its targets to determine whether, and when, to issue such shares.
The 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 1995. Under existing authorization, the Company may issue senior securities in the amount of $250 million, of which $100 million may consist of preferred stock. The Company, through its special-purpose finance subsidiary, has remaining regulatory authority to issue an additional $25 million of Monthly Income Preferred Securities. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
The Company's bond 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. As a result of the TMI-2 retirement costs write-offs, together with certain other costs recognized in the second quarter of 1994, the Company will be unable to meet the interest and preferred dividend coverage requirements of its indenture and charter, respectively, until the third quarter of 1995. Therefore, the Company's ability to issue senior securities through June 1995 will be limited to the issuance of FMBs on the basis of $65 million of previously issued and retired bonds. The Company's ability to issue its remaining authorized Monthly Income Preferred Securities, which have no such coverage restrictions, is not affected by these write-offs.
Metropolitan Edison Company and Subsidiary Companies
The Company's cost of capital and ability to obtain external financing is affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. Following a review that was prompted by the Commonwealth Court's order denying recovery of TMI-2 retirement costs, Moody's Investors Service (Moody's) and Standard & Poor's Corporation (S&P) downgraded the Company's security ratings in August 1994 citing, among other things, the Company's weakened financial flexibility resulting from the second quarter 1994 write-offs. The Company's FMBs are currently rated at an equivalent of a BBB+ or higher by the three major credit rating agencies, while the preferred stock issues and Monthly Income Preferred Securities 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. Although credit quality has been reduced, the Company's credit ratings remain above investment grade.
In 1994, the 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, was revised to "stable" from "negative" for the Company. The outlook reflects S&P's judgment that the Company has manageable construction spending, limited external financing requirements, regionally competitive rates, and an emphasis on cost cutting to offset base rate relief requirements during the next few years. Though its outlook was upgraded, S&P believed that the Company risked some deterioration in its competitive position due to S&P's judgment that there are substantial purchased power-related rate recovery needs. S&P also assigned the Company a "low average" business position, 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.
In June 1994, Moody's announced that it developed a new method to calculate the minimum price an electric utility must charge its customers in order to recover all of its generation costs. Moody's believes that an assessment of relative cost position will become increasingly critical to the credit analysis of electric utilities in a competitive marketplace. Specific rating actions are not anticipated, however, until the pace and implications of utility market deregulation are more certain.
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, make contributions to decommissioning trust funds and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION:
The Company targets capitalization ratios that should warrant sufficient credit quality ratings to permit capital market access at reasonable costs. Recent evaluations of the industry by credit rating agencies indicate that the Company may have to increase its equity ratio to maintain its current
Metropolitan Edison Company and Subsidiary Companies
credit ratings. GPU's financing plans contemplate security issuances in 1995 to strengthen the equity component of the Company and its affiliates' capital structures. The Company's targets and actual capitalization ratios are as follows:
Capitalization Target Range 1994 1993 1992 Common equity 46-49% 46% 48% 46% Preferred equity 8-10 10 5 12 Notes payable and long-term debt 46-41 44 47 42 100% 100% 100% 100%
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the continued development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of competition in Pennsylvania's electric utility industry and solicited comments on various issues. The Company and Pennsylvania Electric Company (Penelec) jointly filed responses in November 1994 suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investments, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on Pennsylvania utilities as compared with unregulated or out-of-state suppliers. At the end of the investigation, which is expected to be concluded in early 1995, the PaPUC will decide whether to conduct a rulemaking proceeding.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking regarding the recovery by utilities of legitimate and verifiable stranded costs. Costs incurred by a utility to provide integrated electric service to a franchise customer become stranded when that customer subsequently purchases power from another supplier using the utility's transmission services. Among other things, the FERC proposed that utilities be allowed under certain circumstances to recover such stranded costs associated with existing wholesale customer contracts, but not under new wholesale contracts unless expressly provided for in the contract. While it stated a "strong" policy preference that state regulatory agencies address recovery of stranded retail costs, the FERC also set forth alternative proposals for how it would address the matter if the states failed to do so. Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of Appeals for the District of Columbia, in an unrelated case, questioned the FERC's authority to permit utilities to recover stranded costs. The Court remanded the matter to the FERC for it to conduct an evidentiary hearing in the case to determine whether, among other things, permitting stranded cost
Metropolitan Edison Company and Subsidiary Companies
recovery was so inherently anticompetitive that it violates antitrust laws. While largely supported by the electric utility industry, the Proposed Rulemaking has been strongly opposed by other groups. There can be no assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing for electric transmission services. The policy statement contains five principles that will provide the foundation for the FERC's analyses of all subsequent transmission rate proposals. Recognizing the evolution of a more competitive marketplace, the FERC contends that it is critical that transmission services be priced in a manner that appropriately compensates transmission owners and creates adequate incentives for efficient system expansion.
In 1994, the SEC issued for public comment a Concept Release regarding modernization of the Public Utility Holding Company Act of 1935 (Holding Company Act). GPU regards the Holding Company Act as a significant impediment to competition and supports its repeal. In addition, GPU believes that the Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally reformed given the burdens being placed on electric utilities by PURPA mandated uneconomic long-term power purchase agreements with nonutility generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning activities. Responding to its assessment that competition in the electric utility industry is likely to accelerate, GPU proceeded to implement two major organizational changes as well as other programs designed to reduce costs and strengthen GPU's competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the non-nuclear generation facilities owned by the Company and its affiliates as well as undertake responsibility to construct any new non-nuclear generation facilities which the Company and its affiliates may need in the future. By forming GPU Generation Corporation (GPUGC), GPU will consolidate and streamline the management of these generation facilities, and seek to apply management and operating efficiency techniques similar to those employed in more competitive industries. This initiative is intended to bring the Company and its affiliates' generation costs more in line with projected market prices. GPU Nuclear Corporation is engaging in a search for parallel opportunities. The Company and its affiliates received regulatory approvals to enter into an operating agreement with GPUGC from the PaPUC and New Jersey Board of Public Utilities. SEC authorization is expected to be received in 1995.
The second part of the realignment includes the management combination of the Company and its affiliate, Penelec. This action is intended to increase effectiveness and lower costs of Pennsylvania customer operations and service functions.
Metropolitan Edison Company and Subsidiary Companies
Other organizational realignments, designed to streamline management and reduce costs, were also implemented throughout the GPU System in 1994. In addition, GPU expanded employee participation in its incentive compensation program to tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System workforce accepted the Voluntary Enhanced Retirement Programs. Future payroll and benefits savings, which are estimated to be $75 million annually (of which the Company's share is $18 million), began in the third quarter and reflect limiting the replacement of employees up to ten percent of those retired. Retirement benefits will be substantially paid from pension and postretirement plan trusts.
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the electric utility industry that calls into question the assumptions regarding the recovery of certain costs through ratemaking. As the utility industry continues to experience an increasingly competitive environment, GPU is attempting to assess the impact that these and other changes will have on the Company and its affiliates' financial position. For additional information regarding the other changes that may have an adverse effect on the Company, see the Competition and the Changing Regulatory Environment section of Note 1 to the Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term regional energy supply from existing facilities, as evidenced by the results of an all-source competitive supply solicitation conducted by the Company's New Jersey affiliate in 1994, is less than the rates in virtually all of the Company's nonutility generation agreements. In addition, the projected cost of energy from new supply sources is now lower than was expected in the recent past due to improvements in power plant technologies and reduced fuel prices.
The long-term nonutility generation agreements included in the Company's supply plan have been entered into pursuant to the requirements of PURPA and state regulatory directives. The Company intends to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company is also attempting to renegotiate, and in some cases buy out, existing high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility generation costs from customers by the PaPUC, there can be no assurance that the Company will continue to recover these costs throughout the terms of the related agreements. The Company currently estimates that in 1998, when substantially all of these nonutility generation projects are scheduled to be in-service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $90 million to $140 million annually.
Metropolitan Edison Company and Subsidiary Companies
THE SUPPLY PLAN:
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 Company's supply plan. As the Company prepares to operate in an increasingly competitive environment, its supply plan currently focuses on maintaining the existing customer base by offering competitively priced electricity.
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.
Over the next five years, the Company is projected to experience an average growth in sales to customers of about 2% annually. These increases are expected to result from continued economic growth in the service territory and a slight increase in customers. To meet this growth, assuming the continuation of existing retail electric regulation, the Company's plan consists of the continued utilization of existing generation facilities combined with present commitments for power purchases, and the continued promotion of economic energy-conservation and load-management programs.
The Company'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. The Company will take necessary actions to avoid adding new capacity at costs that may exceed future market prices. In addition, the Company will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected market prices.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility generators and the operation of a new company-owned peaking unit. Additional capacity needs are principally related to the expiration of existing commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility generators under which a total of 239 MW of capacity is currently in service and about an additional 607 MW are currently scheduled or anticipated to be in service by 1998.
In October 1994, the Company completed construction on a 134 MW gas- fired combustion turbine located adjacent to its Portland Generating Station at a cost of approximately $50 million. After completing operational testing, the new unit was placed in-service in January 1995 and is expected to produce power at a lower cost than similar peaking units now in operation.
Metropolitan Edison Company and Subsidiary Companies
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially reduce above-market payments for energy supplied by nonutility generators. The Company will also continue to take legal, regulatory and legislative initiatives to avoid entering into any new power-supply agreements that are either not needed or, if needed, are not consistent with competitive market pricing. The following is a discussion of major nonutility generation activities involving the Company.
In 1994, a nonutility generator requested that the PaPUC order the Company to enter into a long-term agreement to buy capacity and energy. The Company sought to dismiss the request based on a May 1994 PaPUC order, which granted a Company petition to obtain additional nonutility purchases through competitive bidding until new PaPUC regulations have been adopted. In September 1994, the Commonwealth Court granted the PaPUC's application to revise its May 1994 order for the purpose of reevaluating the nonutility generator's right to sell power to the Company. The PaPUC subsequently ordered that hearings be held in this matter.
As part of the effort to reduce above-market payments under nonutility generation agreements, the Company and its affiliates are seeking to implement a program under which the natural gas fuel and transportation for the Company and its affiliates' gas-fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, would be pooled and managed by a nonaffiliated fuel manager. The Company and its affiliates believe the plan has the potential to provide substantial savings for their customers. The Company and its affiliates have begun initial discussions with the nonutility generators who would be eligible to participate. Requirements for approval of the plan by state and federal regulatory agencies are being reviewed.
Conservation and Load Management
The PaPUC continues to encourage the development of new conservation and load-management programs. Because the benefits of some of these programs may not offset program costs, the Company is working to mitigate the impacts these programs can have on the Company's competitive position in the marketplace.
In a December 1993 order, the PaPUC adopted guidelines for the recovery of DSM costs and directed utilities to implement DSM programs. The Company subsequently filed a DSM program that was expected to be approved by the PaPUC in the first quarter of 1995. However, an industrial intervenor had contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed the PaPUC order. As a result, the nature and scope of the Company's DSM program is uncertain at this time.
Metropolitan Edison Company and Subsidiary Companies
ENVIRONMENTAL ISSUES:
The 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 Company's current plan includes installing and operating emission control equipment at some of its coal-fired facilities as well as switching to lower sulfur coal at other coal-fired facilities.
To comply with the Clean Air Act, the Company expects to spend up to $145 million by the year 2000 for air pollution control equipment. During 1994, the first of two scrubbers was installed at the jointly owned Conemaugh Generating Station. The second scrubber is scheduled to be installed in November 1995. When operational, these scrubbers are expected to reduce sulfur dioxide emissions by 95%. The Company's share of the total project cost is estimated to be $55 million. Through December 31, 1994, the Company has made capital expenditures of approximately $88 million (including the first Conemaugh scrubber mentioned above) to comply with the Clean Air Act requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia proposed reductions in NOx emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Company expects that the U.S. Environmental Protection Agency will approve the proposal, and that as a result, the Company will spend an estimated $10 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Company is unable to determine what, if any, additional costs will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate the risk of recovering capital investments compared to increased participation in the emission allowance market and the use of low-sulfur coal or the early retirement of facilities. These and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected 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 the Consolidated Financial Statements.
Metropolitan Edison Company and Subsidiary Companies
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Company and its affiliates and GPU and are still pending. For more information, see Note 1 to the Consolidated Financial Statements.
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since the regulatory process results in a time lag during which increased operating expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry, the Company does not plan to take any actions that would increase customers' base rates over the next several years. Therefore, the control of operating and capital costs will be essential. As competition and deregulation accelerate, there can be no assurance as to the recovery of increased operating expense or utility plant investments.
The Company 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. Though currently operating in a regulated environment, the Company's focus will be less reliant on the ratemaking process, and geared toward continued performance improvement and cost reduction to facilitate the competitive pricing of its products and services.
Metropolitan Edison Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter 1994* 1993 1994** 1993
Operating revenues $213 159 212 399 $196 674 $191 773
Operating income 39 914 38 371 8 808 28 716
Net income 37 802 27 058 (75 109) 17 385
Earnings available for common stock 36 894 24 486 (76 017) 14 813
In Thousands
Third Quarter Fourth Quarter 1994 1993 1994 1993***
Operating revenues $204 903 $202 482 $186 567 $194 833
Operating income 32 258 36 166 30 516 24 681
Net income 20 453 24 696 17 585 8 736
Earnings available for common stock 19 545 23 788 17 349 7 828
* Results for the first quarter 1994 reflect an increase in earnings of $13.0 million after-tax for interest income from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of $92.9 million after-tax due to a write-off of certain TMI-2 future costs ($72.8 million); and charges for costs related to the Voluntary Enhanced Retirement Programs ($20.1 million).
*** Results for the fourth quarter of 1993 reflect a decrease in earnings of $5.1 million after-tax for the write-off of the Duquesne transactions.
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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Metropolitan Edison Company and Subsidiary Companies as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 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.
As more fully discussed in Note 1 to the consolidated financial statements, the Company and its affiliates are unable to determine the ultimate consequences of certain contingencies which have resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The matters which remain uncertain are (a) the extent to which the retirement costs of TMI-2 could exceed amounts currently recognized for ratemaking purposes or otherwise accrued, and (b) the excess, if any, of amounts which might be paid in connection with claims for damages resulting from the accident over available insurance proceeds.
As discussed in Notes 5 and 7 to the consolidated financial statements, the Company was required to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993.
COOPERS & LYBRAND L.L.P.
New York, New York February 1, 1995
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 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 general partner of Met-Ed Capital L.P., a special purpose finance subsidiary. The Company's business is the generation, transmission, distribution and sale of electricity. 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), and EI Power, Inc., which develop, own and operate nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in two major nuclear projects -- Three Mile Island Unit 1 (TMI-1) which is an operational generating facility, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by the Company, JCP&L and Penelec in the percentages of 50%, 25% and 25%, respectively. At December 31, the Company's net investment in TMI-1 and TMI-2, including nuclear fuel, was as follows:
Net Investment (Millions) TMI-1 TMI-2 1994 $311 $ 6 1993 $332 $11
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates 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
Metropolitan Edison Company and Subsidiary Companies
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 accident cleanup program was completed in 1990. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates and the suppliers of equipment and services to TMI- 2, and are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery on the basis of alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Company and its affiliates had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against GPU and the Company and its affiliates and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is likely to begin in 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with
Metropolitan Edison Company and Subsidiary Companies
applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals.
In an Order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against GPU and the Company and its affiliates; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for TMI-1 by 2014, the end of the plant's license term. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1994 dollars) for TMI-1 is $157 million, of which the Company's share is $79 million. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
Metropolitan Edison Company and Subsidiary Companies
In 1988, a consultant to GPUN performed a site-specific study of TMI-1 that considered various decommissioning plans and estimated the cost of decommissioning the radiological portions of TMI-1 to range from approximately $225 million to $309 million, of which the Company's share would range from $113 million to $155 million (adjusted to 1994 dollars). In addition, the study estimated the cost of removal of nonradiological structures and materials for TMI-1 at $74 million, of which the Company's share is $37 million (adjusted to 1994 dollars).
The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company and its affiliates charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1991 to TMI-2's external trust and will await resolution of the case pending before the Pennsylvania Supreme Court before making any further contributions for amounts written off by the Company in 1994. Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the balance sheet.
TMI-1:
In 1993, the Pennsylvania Public Utility Commission (PaPUC) granted the Company revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site-specific study. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditures of these funds has been made in accumulated depreciation, amounting to $21 million at December 31, 1994. TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the radiological decommissioning of TMI-2, reflecting the NRC funding target in 1994 dollars. The Company and its affiliates record escalations, when
Metropolitan Edison Company and Subsidiary Companies
applicable, in the liability based upon changes in the NRC funding target. The Company and its affiliates have also recorded a liability for incremental costs specifically attributable to monitored storage. In addition, the Company and its affiliates have recorded a liability for nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $2 million, of which the Company's share is $1 million, as of December 31, 1994. Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and 1993 for the Company are as follows:
(Millions) (Millions) 1994 1993
Radiological Decommissioning $125 $115 Nonradiological Cost of Removal 36 35 Incremental Monitored Storage 9 10 Total $170 $160
The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. At December 31, 1994, $43 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet.
In 1993, a PaPUC rate order for the Company allowed for the future recovery of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order. In December 1994, the Pennsylvania Supreme Court granted the Company's request to review that decision. As a consequence of the Commonwealth Court decision, the Company recorded pre-tax charges totaling $127.6 million during 1994. These charges appear in the Other Income and Deductions section of the Income Statement and are composed of $82.6 million for radiological decommissioning costs, $35 million for the nonradiological cost of removal and $10 million for incremental monitored storage costs. The Company will await resolution of the case pending before the Pennsylvania Supreme Court before making any nonrecoverable funding contributions to external trusts for its share of these costs. The Company will be similarly required to charge to expense its share of future increases in the estimate of the costs of retiring TMI-2. Future earnings on trust fund deposits for the Company will be recorded as income. Prior to the Commonwealth Court's decision, the Company expensed and contributed $40 million to external trusts relating to its nonrecoverable share of the accident-related portion of the decommissioning liability.
As a result of TMI-2's entering long-term monitored storage in late 1993, the Company and its affiliates are incurring incremental annual storage costs of approximately $1 million, of which the Company's share is $.50 million. The Company and its affiliates estimate that the remaining annual storage costs will total $19 million, of which the Company's share is $9 million, through 2014, the expected retirement date of TMI-1.
Metropolitan Edison Company 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 Company.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station totals $2.7 billion. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 is excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the outage and continues for three years beginning at $2.6 million per week for the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and facilities, the GPU System is subject to retrospective premium assessments of up to $69 million, of which the Company's share is $19 million, in any one year, in addition to those payable (up to $20 million, of which the Company's share is $5 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving
Metropolitan Edison Company and Subsidiary Companies
toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Company has entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Company to purchase at the contract price all of the power produced up to the contract limits. As of December 31, 1994, facilities covered by these agreements having 239 MW of capacity were in service and 28 MW were scheduled to commence operation in 1995. Payments made pursuant to these agreements were $101 million, $95 million and $78 million
Metropolitan Edison Company and Subsidiary Companies
for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated to aggregate $114 million, $170 million, $280 million, $415 million and $418 million, respectively. These agreements, together with those for facilities which are not yet in operation, provide for the purchase of approximately 846 MW of capacity and energy by the Company by the mid-to-late 1990s, at varying prices.
The emerging competitive generation market has created uncertainty regarding the forecasting of the GPU System's energy supply needs which has caused the Company and its affiliates to change their supply strategy to now seek shorter-term agreements offering more flexibility (see Management's Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current availability of excess capacity in the market place, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing generation facilities is currently competitively priced. 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 Company's and its affiliates' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources. These agreements have been entered into pursuant to the requirements of the federal Public Utility Regulatory Policies Act and state regulatory directives. The Company and its affiliates have initiated lawful actions which are intended to substantially reduce these above market payments. In addition, the Company and its affiliates intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company and its affiliates are also attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery of their nonutility generation costs from customers by the PaPUC and the New Jersey Board of Public Utilities (NJBPU), there can be no assurance that the Company and its affiliates will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that in 1998, when substantially all of the these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas- fired combined cycle facility) will range from $300 million to $450 million annually, of which the Company's share will range from $90 million to $140 million annually. Moreover, efforts to lower these costs have led to disputes before both the PaPUC and the NJPBU, as well as to litigation, and may result in claims against the Company and its affiliates for substantial damages. There can be no assurance as to the outcome of these matters.
Metropolitan Edison Company and Subsidiary Companies
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles and generating facilities, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of 1990, the Company expects to spend up to $145 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Company expects that the U.S. Environmental Protection Agency (EPA) will approve the proposal, and that as a result, the Company will spend an estimated $10 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Company and its affiliates are unable to determine what, if any, additional costs will be incurred.
The Company has been notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 5 hazardous and/or toxic waste sites. In addition, the Company has been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The Company has 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 Company.
Metropolitan Edison Company and Subsidiary Companies
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement Programs (VERP) to certain employees. The enhanced retirement programs were part of a corporate realignment undertaken in 1994. Approximately 82% of eligible GPU System employees accepted the retirement programs, resulting in a pre-tax charge to earnings of $127 million, of which the Company's share is $35 million. These charges are included as Other Operation and Maintenance on the income statement.
The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $115 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured.
The Company has entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which it has ownership interests. The contracts, which expire between 1995 and the end of the expected service lives of the generating stations, require the purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal under the contracts is based on adjustments of indexed cost components. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $27 million for 1995.
At the request of the PaPUC, the Company, as well as the other Pennsylvania utilities, has supplied the PaPUC with proposals for the establishment of a nuclear performance standard. The Company expects the PaPUC to adopt a generic nuclear performance standard as a part of its energy cost rate (ECR) clause in 1995.
During the normal course of the operation of its business, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these types of matters would have a material effect on the Company's financial position or results of operations.
Metropolitan Edison Company and Subsidiary Companies
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Certain reclassifications of prior years' data have been made to conform with current presentation. The Company's accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the PaPUC.
REVENUES The Company recognizes 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.
UTILITY PLANT It is the policy of the Company to record additions to utility plant (material, labor, overhead and an allowance for funds used during construction) at cost. The cost of current repairs and minor replacements is charged to appropriate operating and maintenance expense and clearing accounts, and the cost of renewals is capitalized. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.
DEPRECIATION The Company provides for depreciation at annual rates determined and revised periodically, on the basis of studies, to be sufficient to depreciate the original cost of depreciable property over estimated remaining service lives,which are generally longer than those employed for tax purposes. The Company used depreciation rates which, on an aggregate composite basis, resulted in annual rates of 3.04%, 2.91% and 2.80% for the years 1994, 1993 and 1992, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the 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
Metropolitan Edison Company and Subsidiary Companies
recognized in rates. On an aggregate composite basis, the annual rates utilized were 7.31%, 7.48% and 8.58% for the years 1994, 1993 and 1992, respectively.
AMORTIZATION POLICIES Nuclear Fuel:
Nuclear fuel is amortized on a unit-of-production basis. Rates are determined and periodically revised to amortize the cost over the useful life.
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1994 amounted to $10 million 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 Company made its initial payment to this fund in 1993, and is recovering the remaining amounts through its fuel clause. At December 31, 1994, $13 million is recorded on the balance sheet in Deferred Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS The Company accrues incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE The Company is providing for estimated future disposal costs for spent nuclear fuel at TMI-1 in accordance with the Nuclear Waste Policy Act of 1982. The Company entered into a contract in 1983 with the DOE for the disposal of spent nuclear fuel. The total liability under this contract, including interest, at December 31, 1994, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $26 million, and is reflected in Deferred Credits and Other Liabilities - Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over a remaining period of 13 years.
The Company is collecting one mill per kilowatt-hour from its customers for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. This amount is 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
Metropolitan Edison Company and Subsidiary Companies
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 and decommissioning funds, are provided for differences between book and taxable income. Investment tax credits (ITC) are amortized over the estimated service lives of the related facilities.
Effective January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes" which requires the use of the liability method of financial accounting and reporting for income taxes. Under FAS 109, deferred income taxes reflect the impact of temporary differences between the 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, 1994, the Company had no outstanding issues under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $528 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.
Metropolitan Edison Company and Subsidiary Companies
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of December 31, 1994 and 1993, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1994: Preferred securities of subsidiary $ 100 $ 98 Long-term debt 530 485
December 31, 1993: Long-term debt $ 546 $ 585
The fair values of the Company's long-term debt and preferred securities of subsidiary 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." In 1993, the cumulative effect on net income of this accounting change was immaterial. Also in 1993, the federal income tax rate changed from 34% to 35%, retroactive to January 1, 1993, resulting in an increase in the deferred tax assets of $2 million and an increase in the deferred tax liabilities of $12 million. The tax rate change did not have a material effect on net income as the changes in deferred taxes were substantially offset by the recording of regulatory assets and liabilities. As of December 31, 1994 and 1993, the balance sheet reflected $202 million and $199 million, respectively, of income taxes recoverable through future rates, (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $30 million and $29 million, respectively, (related to unamortized ITC), substantially due to the recognition of amounts not previously recorded.
Metropolitan Edison Company and Subsidiary Companies
A summary of the components of deferred taxes as of December 31, 1994 and 1993 is as follows: (In Millions)
Deferred Tax Assets Deferred Tax Liabilities 1994 1993 1994 1993 Noncurrent: Current: Liberalized Unbilled revenue $ 3 $ 4 depreciation: Deferred energy - 6 previously flowed Other 2 2 through $ 116 $ 114 Total $ 5 $ 12 future revenue Noncurrent: requirements 86 85 Unamortized ITC $ 30 $ 29 Decommissioning 71 19 Subtotal 202 199 Contribution in aid Liberalized of construction 2 2 depreciation 163 154 Other 47 19 Other 7 3 Total $150 $ 69 Total $ 372 $ 356
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) 1994 1993 1992
Net income $ 1 $ 78 $ 73 Income tax expense (9) 47 49 Book income subject to tax $ (8) $125 $122
Federal statutory rate 35% 35% 34% State tax, net of federal benefit 32 6 7 Amortization of ITC 22 (2) (2) Other 20 (1) 1 Effective income tax rate 109% 38% 40%
Metropolitan Edison Company and Subsidiary Companies
Federal and state income tax expense is comprised of the following:
(In Millions) 1994 1993 1992 Provisions for taxes currently payable $ 45 $ 35 $ 65
Deferred income taxes: Liberalized depreciation 6 8 3 Deferral of energy costs 6 4 (15) Accretion income - - 2 Decommissioning (52) - - VERP (15) - - Unbilled revenue 2 - 1 Other 2 3 (4) Deferred income taxes, net (51) 15 (13) Amortization of ITC, net (3) (3) (3) Income tax expense $ (9) $ 47 $ 49
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) 1994 1993 1992 Maintenance $ 59 $ 59 $ 56 Other taxes: Pennsylvania state gross receipts $ 32 $ 32 $ 32 Real estate and personal property 6 7 7 Capital stock 7 8 8 Other 7 6 4 Total $ 52 $ 53 $ 51
For the years 1994, 1993 and 1992, the cost to the Company of services rendered to it by GPUSC amounted to approximately $27 million, $23 million and $23 million, respectively, of which approximately $22 million, $19 million and $18 million, respectively, were charged to income. For the years 1994, 1993, and 1992, the cost to the company of services rendered to it by GPUN amounted to approximately $77 million, $88 million and $75 million, respectively, of which approximately $65 million, $74 million and $61 million, respectively, were charged to income.
Metropolitan Edison Company and Subsidiary Companies
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) 1994 1993 1992
Service cost-benefits earned during the period $ 4.7 $ 4.9 $ 4.4 Interest cost on projected benefit obligation 17.7 18.8 18.5 Less: Expected return on plan assets (19.1) (19.3) (18.3) Amortization (0.3) (0.3) (0.3) Net periodic pension cost $ 3.0 $ 4.1 $ 4.3
The above 1994 amounts do not include a pre-tax charge to earnings of $26 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992 were gains of $2.5 million, $29.2 million and $10.7 million, respectively.
The funded status of the plans and related assumptions at December 31, 1994 and 1993 were as follows: (In Millions) 1994 1993
Accumulated benefit obligation (ABO): Vested benefits $ 212.4 $ 201.1 Nonvested benefits 19.7 21.6 Total ABO 232.1 222.7 Effect of future compensation levels 30.9 36.6 Projected benefit obligation (PBO) $ 263.0 $ 259.3
PBO $ (263.0) $ (259.3) Plan assets at fair value 234.6 255.4 PBO in excess of plan assets (28.4) (3.9) Less: Unrecognized net loss 15.9 6.6 Unrecognized prior service cost 2.3 (1.1) Unrecognized net transition asset (1.4) (1.8) Accrued pension liability $ (11.6) $ (0.2)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5 Annual increase in compensation levels 6.0 5.0
Metropolitan Edison Company and Subsidiary Companies
In 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $9 million decrease in the PBO as of December 31, 1994. Also, in 1994, the PBO increased by $19 million as a result of the VERP. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net 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. 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 as a charge or credit to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1994, 1993 and 1992 were $2.2 million, $1.8 million and $1.6 million, respectively.
Postretirement Benefits Other than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. For 1992, the annual premium costs associated with providing these benefits totaled approximately $3.7 million.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1994 and 1993 follows: (In Millions) 1994 1993 Service cost-benefits attributed to service during the period $ 2.3 $ 2.2 Interest cost on the accumulated postretirement benefit obligation 7.1 7.4 Expected return on plan assets (1.2) (0.7) Amortization of transition obligation 3.4 3.9 Other amortization, net .5 - Net periodic postretirement benefit cost 12.1 12.8 Less, deferred for future recovery (8.3) (7.8) Postretirement benefit cost, net of deferrals $ 3.8 $ 5.0
Metropolitan Edison Company and Subsidiary Companies
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 $2.6 million of allocated postretirement benefit costs from the Company's affiliates for 1994.
The actual return on the plans' assets for the years 1994 and 1993 was a gain of $.4 million and $.7 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as follows: (In Millions) 1994 1993 Accumulated Postretirement Benefit Obligation: Retirees $ 65.0 $ 54.0 Fully eligible active plan participants 11.3 14.6 Other active plan participants 30.9 41.2 Total accumulated postretirement benefit obligation (APBO) $ 107.2 $ 109.8
APBO $(107.2) $(109.8) Plan assets at fair value 14.1 8.2 APBO in excess of plan assets (93.1) (101.6) Less: Unrecognized net loss 11.7 18.1 Unrecognized transition obligation 59.6 74.5 Accrued postretirement benefit liability $ (21.8) $ ( 9.0)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5
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 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $7 million decrease in the APBO as of December 31, 1994. Also, in 1994, the APBO increased by $7 million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for Medicare, then decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $9 million as of December 31, 1994 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $1 million.
The Company began 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
In 1994, the Pennsylvania Commonwealth Court reversed the PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of such costs, stating that FAS 106 expense incurred after January 1, 1993 (the effective date for the accounting change) but prior to its next base rate case could not be deferred for future recovery, and that to assure such future recovery constituted retroactive ratemaking. The Company believes that the Commonwealth Court ruling does not affect it because it received PaPUC authorization as part of its 1993 retail base rate order to defer incremental FAS 106 expense.
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, 1994:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation
Conemaugh 16.45 $138.9 $ 27.9 Three Mile Island Unit 1 50 412.1 139.9
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $33 million and $43 million, respectively (net of amortization of $29 million and $17 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. An aggregate of up to $125 million of nuclear fuel costs may be outstanding at any one time for TMI-1. 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 are renewable annually. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1994, 1993 and 1992 these amounts were $15 million, $25 million and $30 million, respectively. The leases may be terminated at any time with at least five months notice by either party prior to the end of the current period. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.
Metropolitan Edison Company and Subsidiary Companies
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 38 years, averages 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
In 1994, earnings available for common stock decreased $61.9 million to $28.9 million. The earnings decrease was principally attributable to a second quarter write-off of $32.1 million after-tax from an unfavorable Pennsylvania Commonwealth Court order disallowing the collection of revenues for certain Three Mile Island Unit 2 (TMI-2) retirement costs, a $25.6 million after-tax charge to earnings for costs related to the Voluntary Enhanced Retirement Programs, and a $10.6 million after-tax write-off of postretirement benefit costs not considered likely to be recovered through ratemaking. The effect of these charges was partially offset by first quarter interest income of $6.5 million after-tax from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
Also contributing to the 1994 earnings decrease was increased other operation and maintenance (O&M) expense, which included higher emergency and winter storm repairs.
In 1993, earnings available for common stock decreased $3.4 million to $90.7 million. The decrease in earnings was principally the result of higher other O&M expense, the write-off of approximately $4.4 million after-tax of costs related to the cancellation of proposed energy-related agreements, and increased depreciation expense. These decreases were partially offset by higher KWH revenues, the recovery of prior period transmission service revenues and lower reserve capacity expense.
The Company's return on average common equity was 4.2% for 1994 as compared to 13.5% for 1993.
OPERATING REVENUES:
Revenues increased 4.0% to $944.7 million in 1994 after increasing 1.3% in 1993 to $908.3 million. The components of these changes are as follows:
(In Millions) 1994 1993 Kilowatt-hour (KWH) revenues (excluding energy portion) $ 1.6 $ 6.3 Energy revenues 39.7 (5.2) Other revenues (4.9) 10.8 Increase in revenues $36.4 $11.9
Pennsylvania Electric Company and Subsidiary Companies
Kilowatt-hour revenues
The increase in KWH revenues was due principally to an increase in the average number of commercial and wholesale customers, and higher usage by wholesale customers. In 1993, the Company successfully negotiated power supply agreements with wholesale customers previously served by the Company's affiliates. This was in response to offers made by other utilities seeking to provide electric service at rates lower than those of Metropolitan Edison Company (Met-Ed) or Jersey Central Power & Light Company. These increases were mostly offset by decreased industrial customer usage and decreased capacity sales to affiliated companies.
KWH revenues increased primarily from higher KWH usage by residential and commercial customers and higher capacity sales to affiliated companies. Revenues also increased because of new sales to the Company's principal wholesale customer. These increases were partially offset by decreased industrial customer usage. One of the most significant reductions occurred because of the phase out of operations by the Company's largest industrial customer.
Energy revenues
Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues increased primarily from higher energy cost rates in effect and the reclassification in 1993 of certain transmission service revenues.
Energy revenues decreased as a result of decreased sales to other utilities and the reclassification of certain transmission service revenues to other revenues. The reclassification resulted from a favorable Pennsylvania Public Utility Commission (PaPUC) order allowing the Company to exclude these transmission service revenues from the Company's energy cost rate. Partially offsetting these decreases was increased energy revenues resulting from higher energy cost rates in effect.
Other revenues
Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes. The decrease in other revenues was primarily due to a one-time benefit resulting from the recognition in 1993 of prior period transmission service revenues.
Other revenues increased primarily from increased wheeling revenues and a one-time benefit resulting from the recognition of prior period transmission service revenues.
Pennsylvania Electric Company and Subsidiary Companies
OPERATING EXPENSES: Power purchased and interchanged
Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy cost rate. The increase in power purchased and interchanged was primarily attributable to increased nonutility generation purchases.
Power purchased and interchanged from affiliated companies decreased primarily as a result of lower reserve capacity costs. The decrease in expense favorably affected earnings because reserve capacity costs are not recovered through energy revenues. Power purchased and interchanged from nonaffiliated companies increased primarily from increased nonutility generation purchases. This increase was partially offset by lower purchases from other utilities.
Other operation and maintenance
The increase in other O&M expense was primarily attributable to a $44.9 million pre-tax charge for costs related to the Voluntary Enhanced Retirement Programs. Increases were 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.
The increase was due largely to higher outage activity at several of the Company's coal fired generating stations, and higher payroll and tree trimming expenses. These increases were partially offset by the recognition of proceeds from the settlement of a property insurance claim.
Depreciation and amortization
The decrease in depreciation and amortization expense was due largely to lower TMI-2 amortization and the recognition in 1993 of TMI-2 non-radiological 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.
Depreciation and amortization expense increased primarily from higher cost of removal charges and a $3.6 million pre-tax charge for TMI-2 non- radiological retirement costs not considered likely to be recovered through ratemaking.
Pennsylvania Electric Company and Subsidiary Companies
Taxes, other than income taxes
1994 and 1993 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS: Other income/(expense), net
The increase in other expense was principally related to the second quarter write-off of future TMI-2 retirement costs and postretirement benefit costs. The effect of these write-offs was partially offset by first quarter interest income resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
In mid 1994, the Pennsylvania Commonwealth Court overturned a 1993 PaPUC order that permitted Met-Ed to recover estimated TMI-2 retirement costs from customers. As a result, the Company recorded second quarter charges of $56.3 million pre-tax for its share of such costs. These charges were comprised of $51.6 million for retirement costs and $4.7 million for monitored storage costs.
Also in the second quarter of 1994, the Company wrote off $14.6 million pre-tax in deferred postretirement benefit costs related to the adoption of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." This was a result of a Commonwealth Court decision reversing a PaPUC order that allowed a nonaffiliated utility, outside a base rate case, to defer certain postretirement benefit costs for future recovery from customers. The Company had deferred such costs under a similar accounting order issued by the PaPUC. In addition, the Company recognized a $4 million pre-tax charge for the remaining transition obligation related to postretirement benefit costs for the employees who participated in the Voluntary Enhanced Retirement Programs.
The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. The effect on pre-tax earnings was an increase of $14.9 million in interest income.
The reduction in other income was due principally to the write-off of $7.3 million pre-tax which represents the Company's share of costs related to the cancellation of proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne Light Company.
INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES: Interest charges
Other interest expense was higher due primarily to the tax retirement of TMI-2, which resulted in a $3.5 million pre-tax increase in interest expense
Pennsylvania Electric Company and Subsidiary Companies
on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken.
Interest on long-term debt increased primarily from the issuance of additional long-term debt, offset partially by decreases associated with the refinancing of higher cost debt at lower interest rates. Other interest decreased primarily as a result of lower interest rates and lower interest on energy cost rate overcollections resulting from the reclassification in 1993 of certain transmission service revenues (See "Energy revenues").
Dividends on preferred securities of subsidiary
The increase was attributable to the payment of dividends on the Monthly Income Preferred Securities issued by the Company's special-purpose finance subsidiary, Penelec Capital L.P.
PREFERRED STOCK DIVIDENDS: 1994 and 1993 Preferred stock dividends decreased in 1994 and 1993 due to the redemption in both periods of $25 million stated value of preferred stock.
LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS:
The Company's capital needs were $244 million in 1994, consisting of cash construction expenditures of $174 million and amounts for maturing obligations of $70 million. During 1994, construction funds were used primarily to maintain and improve existing generation facilities and the transmission and distribution system, and proceed with various clean air compliance projects. For 1995, construction expenditures are estimated to be $144 million, consisting mainly of $103 million for ongoing system development, $20 million for the repowering of an existing generation facility, and $19 million for clean air compliance projects. The 1995 estimated reduction is largely due to the completion in 1994 of a significant portion of clean air compliance requirements. While the Company has no long-term debt maturing in 1995, expenditures for maturing debt are expected to be $75 million in 1996. In the late 1990s, construction expenditures are expected to include substantial amounts for clean air requirements and other Company needs. Management estimates that approximately three-fourths of the Company's 1995 capital needs will be satisfied through internally generated funds.
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $125 million of nuclear fuel costs may be outstanding at any one time for TMI-1. The Company's share of the nuclear fuel capital leases at December 31, 1994 totaled $16 million.
Pennsylvania Electric Company and Subsidiary Companies
When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $8 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 1994, the Company issued $105 million of Monthly Income Preferred Securities (carried on the balance sheet as Preferred securities of subsidiaries) through its special-purpose finance subsidiary, and an aggregate of $130 million principal amount of long-term debt. A portion of these proceeds was used to refinance long-term debt and redeem more costly preferred stock amounting to $38 million and $25 million, respectively. In addition, the Company issued $30 million of long-term debt in February 1995. The net proceeds from this issuance will be used to reduce short-term debt.
GPU has requested regulatory authorization from the Securities and Exchange Commission (SEC) to issue up to five million shares of additional common stock through 1996. The proceeds from the sale of such additional common stock would be used to increase the Company and its affiliates' common equity ratios and reduce GPU short-term debt. GPU will monitor the capital markets as well as its capitalization ratios relative to its targets to determine whether, and when, to issue such shares.
The 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 1995. Under existing authorization, the Company may issue senior securities in the amount of $260 million, of which $100 million may consist of preferred stock. The Company, through its special-purpose finance subsidiary, has remaining regulatory authority to issue an additional $20 million of Monthly Income Preferred Securities. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
The Company's bond 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. As a result of the TMI-2 retirement costs write-offs, together with certain other costs recognized in the second quarter of 1994, the Company has sufficient coverage to issue only approximately $49 million of FMBs through June 1995, depending on interest rates at the time of issuance, plus $38 million of FMBs on the basis of previously issued and retired bonds. In addition, the Company will be unable to meet coverage requirements for issuing preferred stock until the third quarter of 1995. The Company's ability to issue its remaining authorized Monthly Income Preferred Securities, which have no such coverage restrictions, is not affected by these write-offs.
The Company's cost of capital and ability to obtain external financing is affected by its security ratings, which are periodically reviewed by the three major credit rating agencies. Following a review that was prompted by the Commonwealth Court's order denying recovery of TMI-2 retirement costs, Moody's Investors Service (Moody's) and Standard & Poor's Corporation (S&P) downgraded
Pennsylvania Electric Company and Subsidiary Companies
the Company's security ratings in August 1994 citing, among other things, the Company's weakened financial flexibility resulting from the second quarter 1994 write-offs. The Company's FMBs are currently rated at an equivalent of an A- or higher by the three major credit rating agencies, while the preferred stock issues and Monthly Income Preferred Securities 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. Although credit quality has been reduced, the Company's credit ratings remain above investment grade.
In 1994, the 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, was revised to "stable" from "negative" for the Company. The outlook reflects S&P's judgment that the Company has manageable construction spending, limited external financing requirements, regionally competitive rates, and an emphasis on cost cutting to offset base rate relief requirements during the next few years. S&P also assigned the Company an "average" business position, 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.
In June 1994, Moody's announced that it developed a new method to calculate the minimum price an electric utility must charge its customers in order to recover all of its generation costs. Moody's believes that an assessment of relative cost position will become increasingly critical to the credit analysis of electric utilities in a competitive marketplace. Specific rating actions are not anticipated, however, until the pace and implications of utility market deregulation are more certain.
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, make contributions to decommissioning trust funds and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION: The Company targets capitalization ratios that should warrant sufficient credit quality ratings to permit capital market access at reasonable costs. Recent evaluations of the industry by credit rating agencies indicate that the Company may have to increase its equity ratio to maintain its current credit ratings. GPU's financing plans contemplate security issuances in 1995 to strengthen the equity component of the Company and its affiliates' capital structures. The Company's targets and actual capitalization ratios are as follows:
Capitalization Target Range 1994 1993 1992 Common equity 45-48% 43% 48% 46% Preferred equity 8-10 9 4 7 Notes payable and long-term debt 47-42 48 48 47 100% 100% 100% 100%
Pennsylvania Electric Company and Subsidiary Companies
COMPETITIVE ENVIRONMENT:
- Recent Regulatory Actions
The electric power markets have traditionally been served by regulated monopolies. Over the last few years, however, market forces combined with state and federal actions, have laid the foundation for the continued development of additional competition in the electric utility industry.
In April 1994, the PaPUC initiated an investigation into the role of competition in Pennsylvania's electric utility industry and solicited comments on various issues. The Company and Met-Ed jointly filed responses in November 1994 suggesting, among other things, that the PaPUC provide for the equitable recovery of stranded investments, enable utilities to offer flexible pricing to customers with competitive alternatives, and address regulatory requirements that impose costs unequally on Pennsylvania utilities as compared with unregulated or out-of-state suppliers. At the end of the investigation, which is expected to be concluded in early 1995, the PaPUC will decide whether to conduct a rulemaking proceeding.
In June 1994, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking regarding the recovery by utilities of legitimate and verifiable stranded costs. Costs incurred by a utility to provide integrated electric service to a franchise customer become stranded when that customer subsequently purchases power from another supplier using the utility's transmission services. Among other things, the FERC proposed that utilities be allowed under certain circumstances to recover such stranded costs associated with existing wholesale customer contracts, but not under new wholesale contracts unless expressly provided for in the contract. While it stated a "strong" policy preference that state regulatory agencies address recovery of stranded retail costs, the FERC also set forth alternative proposals for how it would address the matter if the states failed to do so. Subsequent to FERC's Notice of Proposed Rulemaking, however, the U.S. Court of Appeals for the District of Columbia, in an unrelated case, questioned the FERC's authority to permit utilities to recover stranded costs. The Court remanded the matter to the FERC for it to conduct an evidentiary hearing in the case to determine whether, among other things, permitting stranded cost recovery was so inherently anticompetitive that it violates antitrust laws. While largely supported by the electric utility industry, the Proposed Rulemaking has been strongly opposed by other groups. There can be no assurance as to the outcome of this proceeding.
In October 1994, the FERC issued a policy statement regarding pricing for electric transmission services. The policy statement contains five principles that will provide the foundation for the FERC's analyses of all subsequent transmission rate proposals. Recognizing the evolution of a more competitive marketplace, the FERC contends that it is critical that transmission services be priced in a manner that appropriately compensates transmission owners and creates adequate incentives for efficient system expansion.
Pennsylvania Electric Company and Subsidiary Companies
In 1994, the SEC issued for public comment a Concept Release regarding modernization of the Public Utility Holding Company Act of 1935 (Holding Company Act). GPU regards the Holding Company Act as a significant impediment to competition and supports its repeal. In addition, GPU believes that the Public Utility Regulatory Policies Act of 1978 (PURPA) should be fundamentally reformed given the burdens being placed on electric utilities by PURPA mandated uneconomic long-term power purchase agreements with nonutility generators.
- Managing the Transition
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning activities. Responding to its assessment that competition in the electric utility industry is likely to accelerate, GPU proceeded to implement two major organizational changes as well as other programs designed to reduce costs and strengthen GPU's competitive position.
First, GPU is forming a subsidiary to operate, maintain and repair the non-nuclear generation facilities owned by the Company and its affiliates as well as undertake responsibility to construct any new non-nuclear generation facilities which the Company and its affiliates may need in the future. By forming GPU Generation Corporation (GPUGC), GPU will consolidate and streamline the management of these generation facilities, and seek to apply management and operating efficiency techniques similar to those employed in more competitive industries. This initiative is intended to bring the Company and its affiliates' generation costs more in line with projected market prices. GPU Nuclear Corporation is engaging in a search for parallel opportunities. The Company and its affiliates received regulatory approvals to enter into an operating agreement with GPUGC from the PaPUC and New Jersey Board of Public Utilities. SEC authorization is expected to be received in 1995.
The second part of the realignment includes the management combination of the Company and its affiliate, Met-Ed. This action is intended to increase effectiveness and lower costs of Pennsylvania customer operations and service functions.
Other organizational realignments, designed to streamline management and reduce costs, were also implemented throughout the GPU System in 1994. In addition, GPU expanded employee participation in its incentive compensation program to tie pay increases more closely to business results and enhance productivity.
During 1994, approximately 1,350 employees or about 11% of the GPU System workforce accepted the Voluntary Enhanced Retirement Programs. Future payroll and benefits savings, which are estimated to be $75 million annually (of which the Company's share is $26 million), began in the third quarter and reflect limiting the replacement of employees up to ten percent of those retired. Retirement benefits will be substantially paid from pension and postretirement plan trusts.
Pennsylvania Electric Company and Subsidiary Companies
- Nonutility Generation Agreements
Competitive pricing of electricity is a significant issue facing the electric utility industry that calls into question the assumptions regarding the recovery of certain costs through ratemaking. As the utility industry continues to experience an increasingly competitive environment, GPU is attempting to assess the impact that these and other changes will have on the Company and its affiliates' financial position. For additional information regarding the other changes that may have an adverse effect on the Company, see the Competition and the Changing Regulatory Environment section of Note 1 to the Consolidated Financial Statements.
Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term regional energy supply from existing facilities, as evidenced by the results of an all source competitive supply solicitation conducted by the Company's New Jersey affiliate in 1994, is less than the rates in virtually all of the Company's nonutility generation agreements. In addition, the projected cost of energy from new supply sources is now lower than was expected in the recent past due to improvements in power plant technologies and reduced fuel prices.
The long-term nonutility generation agreements included in the Company's supply plan have been entered into pursuant to the requirements of PURPA and state regulatory directives. The Company intends to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company is also attempting to renegotiate, and in some cases buy out, existing high cost long-term nonutility generation agreements.
While the Company thus far has been granted recovery of its nonutility generation costs from customers by the PaPUC, there can be no assurance that the Company will continue to recover these costs throughout the terms of the related agreements. The Company currently estimates that in 1998, when substantially all of these nonutility generation projects are scheduled to be in-service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $90 million to $120 million annually.
THE SUPPLY PLAN:
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 Company's supply plan. As the Company prepares to operate in an increasingly competitive environment, its supply plan currently focuses on maintaining the existing customer base by offering competitively priced electricity.
Pennsylvania Electric Company and Subsidiary Companies
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.
Over the next five years, the Company is projected to experience an average growth in sales to customers of about 2% annually. These increases are expected to result from continued economic growth in the service territory and a slight increase in customers. To meet this growth, assuming the continuation of existing retail electric regulation, the Company's plan consists of the continued utilization of existing generation facilities combined with present commitments for power purchases, and the continued promotion of economic energy-conservation and load-management programs.
The Company'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. The Company will take necessary actions to avoid adding new capacity at costs that may exceed future market prices. In addition, the Company will seek regulatory support to renegotiate or buy out contracts with nonutility generators where the pricing is in excess of projected market prices.
New Energy Supplies
The Company's supply plan includes contracted capacity from nonutility generators and the repowering of an existing generation facility. Additional capacity needs are principally related to the expiration of existing commitments rather than new customer load.
The Company has contracts and anticipated commitments with nonutility generators under which a total of 295 MW of capacity is currently in service and about an additional 279 MW are currently scheduled or anticipated to be in service by 1999.
The Company's supply plan also includes a repowering project at its Warren Generating Station that combines a coal-fueled combustion turbine with an existing generator. The repowering project will enable the station to comply with state and federal standards for reduced emissions and increase electrical output to approximately 100 MW. While the U.S. Department of Energy has agreed to fund 50% of the $146 million project cost as part of its Clean Coal Technology Program, management is unable to determine what effect recent federal budget cut proposals will have on Congressional appropriation of this funding. The project is in the early stages of development and is estimated to be in-service in 1996.
Managing Nonutility Generation
The Company is pursuing actions to either eliminate or substantially reduce above-market payments for energy supplied by nonutility generators. The Company will also continue to take legal, regulatory and legislative
Pennsylvania Electric Company and Subsidiary Companies
initiatives to avoid entering into any new power-supply agreements that are either not needed or, if needed, are not consistent with competitive market pricing. The following is a discussion of major nonutility generation activities involving the Company.
In November 1994, the Company requested the Pennsylvania Supreme Court to review a Commonwealth Court decision upholding a PaPUC order requiring the Company to purchase a total of 160 MW from two nonutility generators. The PaPUC had ordered the Company in 1993 to enter into power purchase agreements with the nonutility generators for 80 MW of power each under long-term contracts commencing in 1997 or later. In August 1994, the Commonwealth Court denied the Company's appeal of the PaPUC order. The Company's petition to the Supreme Court contends that the Commonwealth Court imposed unnecessary and excessive costs on the Company's customers by finding that the Company had a need for capacity. The petition also questions the Commonwealth Court's upholding of the PaPUC's determination that the nonutility generators had incurred a legal obligation entitling them to payments under PURPA.
As part of the effort to reduce above-market payments under nonutility generation agreements, the Company and its affiliates are seeking to implement a program under which the natural gas fuel and transportation for the Company and its affiliates' gas-fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, would be pooled and managed by a nonaffiliated fuel manager. The Company and its affiliates believe the plan has the potential to provide substantial savings for their customers. The Company and its affiliates have begun initial discussions with the nonutility generators who would be eligible to participate. Requirements for approval of the plan by state and federal regulatory agencies are being reviewed.
Conservation and Load Management
The PaPUC continues to encourage the development of new conservation and load-management programs. Because the benefits of some of these programs may not offset program costs, the Company is working to mitigate the impacts these programs can have on the Company's competitive position in the marketplace.
In a December 1993 order, the PaPUC adopted guidelines for the recovery of DSM costs and directed utilities to implement DSM programs. The Company subsequently filed a DSM program that was expected to be approved by the PaPUC in the first quarter of 1995. However, an industrial intervenor had contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed the PaPUC order. As a result, the nature and scope of the Company's DSM program is uncertain at this time.
ENVIRONMENTAL ISSUES:
The 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 Company's current plan includes installing and operating emission control equipment at some of its coal-fired facilities as well as switching to lower sulfur coal at other coal-fired facilities.
Pennsylvania Electric Company and Subsidiary Companies
To comply with the Clean Air Act, the Company expects to spend up to $177 million by the year 2000 for air pollution control equipment. Through December 31, 1994, the Company has made capital expenditures of approximately $75 million to comply with the Clean Air Act requirements.
In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia proposed reductions in NOx emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Company expects that the U.S. Environmental Protection Agency will approve the proposal, and that as a result, the Company will spend an estimated $50 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Company is unable to determine what, if any, additional costs will be incurred.
In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate the risk of recovering capital investments compared to increased participation in the emission allowance market and the use of low-sulfur coal or the early retirement of facilities. These and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected 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 the Consolidated Financial Statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Company and its affiliates and GPU and are still pending. For more information, see Note 1 to the Consolidated Financial Statements.
EFFECTS OF INFLATION:
Under traditional ratemaking, the Company is affected by inflation since the regulatory process results in a time lag during which increased operating expenses are not fully recovered.
Given the competitive pressures facing the electric utility industry, the Company does not plan to take any actions that would increase customers' base rates over the next several years. Therefore, the control of operating and capital costs will be essential. As competition and deregulation accelerate, there can be no assurance as to the recovery of increased operating expense or utility plant investments.
Pennsylvania Electric Company and Subsidiary Companies
The Company 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. Though currently operating in a regulated environment, the Company's focus will be less reliant on the ratemaking process, and geared toward continued performance improvement and cost reduction to facilitate the competitive pricing of its products and services.
Pennsylvania Electric Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (Unaudited)
In Thousands
First Quarter Second Quarter
1994* 1993 1994** 1993
Operating revenues $247 180 $231 148 $227 122 $219 232
Operating income 46 017 45 279 8 749 32 357
Net income 38 965 33 212 (46 671) 20 246
Earnings available for common stock 38 057 31 796 (47 580) 18 830
In Thousands
Third Quarter Fourth Quarter
1994 1993 1994 1993***
Operating revenues $240 267 $229 447 $230 175 $228 453
Operating income 38 238 42 835 33 228 26 566
Net income 24 351 31 714 15 154 10 556
Earnings available for common stock 23 617 30 467 14 768 9 648
* Results for the first quarter 1994 reflect an increase in earnings of $6.5 million after-tax for income from refunds of previously paid federal income taxes related to the tax retirement of TMI-2.
** Results for the second quarter 1994 reflect a decrease in earnings of $68.3 million after-tax due to a write-off of certain TMI-2 future costs ($32.1 million); charges for costs related to the Voluntary Enhanced Retirement Programs ($25.6 million); and a write-off of postretirement benefit costs not considered likely to be recovered in rates ($10.6 million).
*** Results for the fourth quarter of 1993 reflect a decrease in earnings of $4.6 million after-tax for the write-off of the Duquesne transactions.
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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pennsylvania Electric Company and Subsidiary Companies as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 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.
As more fully discussed in Note 1 to consolidated financial statements, the Company and its affiliates are unable to determine the ultimate consequences of certain contingencies which have resulted from the accident at Unit 2 of the Three Mile Island Nuclear Generating Station ("TMI-2"). The matters which remain uncertain are (a) the extent to which the retirement costs of TMI-2 could exceed amounts currently recognized for ratemaking purposes or otherwise accrued, and (b) the excess, if any, of amounts which might be paid in connection with claims for damages resulting from the accident over available insurance proceeds.
As discussed in Notes 5 and 7 to the consolidated financial statements, the Company was required to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes", and the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993.
Coopers & Lybrand L.L.P.
New York, New York February 1, 1995
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 owns all of the common stock of Penelec Preferred Capital, Inc., which is the general partner of Penelec Capital L.P., a special purpose finance subsidiary. 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), and EI Power, Inc., which develop, own and operate nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. are referred to as the "GPU System."
1. COMMITMENTS AND CONTINGENCIES
NUCLEAR FACILITIES
The Company has made investments in two major nuclear projects -- Three Mile Island Unit 1 (TMI-1) which is an operational generating facility, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by the Company, JCP&L and Met-Ed in the percentages of 25%, 25% and 50%, respectively. At December 31, the Company's net investment in TMI-1 and TMI-2, including nuclear fuel, was as follows:
Net Investment (Millions) TMI-1 TMI-2 1994 $154 $8 1993 $165 $9
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates 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
Pennsylvania Electric Company and Subsidiary Companies
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 accident cleanup program was completed in 1990. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, approximately 2,100 individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates and the suppliers of equipment and services to TMI- 2, and are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery on the basis of alleged emissions of radioactivity before, during and after the accident.
If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Company and its affiliates had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million.
The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against GPU and the Company and its affiliates and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages.
In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is likely to begin in 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not
Pennsylvania Electric Company and Subsidiary Companies
breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals.
In an Order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against GPU and the Company and its affiliates; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for TMI-1 by 2014, the end of the plant's license term. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1994 dollars) for TMI-1 is $157 million, of which the Company's share is $39 million. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
In 1988, a consultant to GPUN performed a site-specific study of TMI-1 that considered various decommissioning plans and estimated the cost of decommissioning the radiological portions of TMI-1 to range from approximately $225 million to $309 million, of which the Company's share would range from
Pennsylvania Electric Company and Subsidiary Companies
$56 million to $77 million (adjusted to 1994 dollars). In addition, the study estimated the cost of removal of nonradiological structures and materials for TMI-1 at $74 million, of which the Company's share is $19 million (adjusted to 1994 dollars).
The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies and cannot now be more reasonably estimated than the level of the NRC funding target because such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company and its affiliates charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1991 to TMI-2's external trust and will await resolution of the case pending before the Pennsylvania Supreme Court before making any further contributions for amounts written off by the Company in 1994. Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the balance sheet.
TMI-1:
In 1993, the Pennsylvania Public Utility Commission (PaPUC) approved a rate change for the Company that increased the collection of revenues for decommissioning costs for TMI-1 based on its share of the NRC funding target. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditures of these funds has been made in accumulated depreciation, amounting to $8 million, at December 31, 1994. TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant.
Management believes that any TMI-1 retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the current ratemaking process.
TMI-2 Future Costs:
The Company and its affiliates have recorded a liability for the radiological decommissioning of TMI-2, reflecting the NRC funding target in 1994 dollars. The Company and its affiliates record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company and its affiliates have also recorded a liability for incremental costs specifically attributable to monitored storage. In addition, the Company and its affiliates have recorded a liability for nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $2 million, of which the Company's share is $.5 million, as of December 31, 1994. Estimated Three Mile Island Unit 2 Future Costs as of December 31, 1994 and 1993 for the Company are as follows:
Pennsylvania Electric Company and Subsidiary Companies
(Millions) (Millions) 1994 1993
Radiological Decommissioning $ 62 $ 57 Nonradiological Cost of Removal 18 18 Incremental Monitored Storage 5 5 Total $ 85 $ 80
The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. At December 31, 1994, $21 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet, and $5 million was recoverable from wholesale customers and included in Three Mile Island Unit 2 Deferred Costs on the balance sheet.
In 1993, a PaPUC rate order for Met-Ed allowed for the future recovery of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order. In December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to review that decision. The Company, 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 Income Statement and are composed of $38.4 million for radiological decommissioning costs, $13.2 million for the nonradiological cost of removal and $4.7 million for incremental monitored storage costs. The Company will await resolution of the case pending before the Pennsylvania Supreme Court before making any nonrecoverable funding contributions to external trusts for its share of these costs. The Company will be similarly required to charge to expense its share of future increases in the estimate of the costs of retiring TMI-2. Future earnings on trust fund deposits for the Company will be recorded as income. Prior to the Commonwealth Court's decision, the Company expensed and contributed $20 million to external trusts relating to its nonrecoverable share of the accident-related portion of the decommissioning liability.
As a result of TMI-2's entering long-term monitored storage in late 1993, the Company and its affiliates are incurring incremental annual storage costs of approximately $1 million, of which the Company's share is $.25 million. The Company and its affiliates estimate that the remaining annual storage costs will total $19 million, of which the Company's share is $5 million, through 2014, the expected retirement date of TMI-1.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company.
Pennsylvania Electric Company and Subsidiary Companies
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station totals $2.7 billion. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 is excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the outage and continues for three years beginning at $2.6 million per week for the first year, decreasing by 20 percent for years two and three.
Under its insurance policies applicable to nuclear operations and facilities, the GPU System is subject to retrospective premium assessments of up to $69 million, of which the Company's share is $9 million, in any one year, in addition to those payable (up to $20 million, of which the Company's share is $2 million, annually per incident) under the Price-Anderson Act.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
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c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its balance sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general.
If a portion of the Company's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result.
The Company has entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. While a few of these facilities are dispatchable, most are must-run and generally obligate the Company to purchase at the contract price all of the power produced up to the contract limits. As of December 31, 1994, facilities covered by these agreements having 295 MW of capacity were in service and 102 MW were scheduled to commence operation in 1995. Payments made pursuant to these agreements were $123 million, $104 million and $77 million for 1994, 1993 and 1992, respectively. For the years 1995, 1996, 1997, 1998, and 1999, payments pursuant to these agreements are estimated to aggregate $185 million, $192 million, $237 million, $302 million and $312 million, respectively. These agreements, together with those for facilities which are not yet in operation, provide for the purchase of approximately 574 MW of capacity and energy by the Company by the mid-to-late 1990s, at varying prices.
The emerging competitive generation market has created uncertainty regarding the forecasting of the GPU System's energy supply needs which has caused the Company and its affiliates to change their supply strategy to now seek shorter-term agreements offering more flexibility (see Management's Discussion and Analysis - COMPETITIVE ENVIRONMENT). Due to the current availability of excess capacity in the market place, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing
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generation facilities is currently competitively priced. 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 Company's and its affiliates' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources. These agreements have been entered into pursuant to the requirements of the federal Public Utility Regulatory Policies Act and state regulatory directives. The Company and its affiliates have initiated lawful actions which are intended to substantially reduce these above market payments. In addition, the Company and its affiliates intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing. The Company and its affiliates are also attempting to renegotiate, and in some cases buy out, high cost long-term nonutility generation agreements.
While the Company and its affiliates thus far have been granted recovery of their nonutility generation costs from customers by the PaPUC and the New Jersey Board of Public Utilities (NJBPU), there can be no assurance that the Company and its affiliates will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that in 1998, when substantially all of the these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas- fired combined cycle facility) will range from $300 million to $450 million annually, of which the Company's share will range from $90 million to $120 million annually. Moreover, efforts to lower these costs have led to disputes before both the PaPUC and the NJBPU, as well as to litigation, and may result in claims against the Company and its affiliates for substantial damages. There can be no assurance as to the outcome of these matters.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles and generating facilities, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material.
To comply with the federal Clean Air Act Amendments (Clean Air Act) of 1990, the Company expects to spend up to $177 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. In September
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1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Company expects that the U.S. Environmental Protection Agency (EPA) will approve the proposal, and that as a result, the Company will spend an estimated $50 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Company and its affiliates are unable to determine what, if any, additional costs will be incurred.
The Company has been notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 3 hazardous and/or toxic waste sites. In addition, the Company has been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The Company has 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 Company.
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant.
OTHER COMMITMENTS AND CONTINGENCIES
During 1994, the GPU System offered Voluntary Enhanced Retirement Programs (VERP) to certain employees. The enhanced retirement programs were part of a corporate realignment undertaken in 1994. Approximately 82% of eligible GPU System employees accepted the retirement programs, resulting in a pre-tax charge to earnings of $127 million, of which the Company's share is $45 million. These charges are included as Other Operation and Maintenance on the income statement.
The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $144 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured.
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The Company has entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which it has ownership interests. The contracts, which expire between 1995 and the end of the expected service lives of the generating stations, require the purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal under the contracts is based on adjustments of indexed cost components. One contract also includes a provision for the payment of environmental and postretirement benefits. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $50 million for 1995.
At the request of the PaPUC, the Company, as well as the other Pennsylvania utilities, has supplied the PaPUC with proposals for the establishment of a nuclear performance standard. The Company expects the PaPUC to adopt a generic nuclear performance standard as a part of its energy cost rate (ECR) clause in 1995.
During the normal course of the operation of its business, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these types of matters would have a material effect on the Company's financial position or results of operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS The consolidated financial statements include the accounts of the Company and its subsidiaries. Certain reclassifications of prior years' data have been made to conform with current presentation. The Company's accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the PaPUC.
REVENUES The Company recognizes 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.
UTILITY PLANT It is the policy of the Company to record additions to utility plant (material, labor, overhead and an allowance for funds used during
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construction) at cost. The cost of current repairs and minor replacements is charged to appropriate operating and maintenance expense and clearing accounts, and the cost of renewals is capitalized. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.
DEPRECIATION The Company provides for depreciation at annual rates determined and revised periodically, on the basis of studies, to be sufficient to depreciate the original cost of depreciable property over estimated remaining service lives,which are generally longer than those employed for tax purposes. The Company used depreciation rates which, on an aggregate composite basis, resulted in annual rates of 2.49%, 2.74% and 2.86% for the years 1994, 1993 and 1992, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the 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 7.19%, 4.91% and 4.15% for the years 1994, 1993 and 1992, respectively.
AMORTIZATION POLICIES
Nuclear Fuel:
Nuclear fuel is amortized on a unit-of-production basis. Rates are determined and periodically revised to amortize the cost over the useful life.
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1994 amounted to $5 million 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 Company made its initial payment to this fund in 1993, and is recovering the remaining amounts through its fuel clause. At December 31, 1994, $6 million is recorded on the balance sheet in Deferred Debits and Other Assets - Other.
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NUCLEAR OUTAGE MAINTENANCE COSTS The Company accrues incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE The Company is providing for estimated future disposal costs for spent nuclear fuel at TMI-1 in accordance with the Nuclear Waste Policy Act of 1982. The Company entered into a contract in 1983 with the DOE for the disposal of spent nuclear fuel. The total liability under this contract, including interest, at December 31, 1994, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $10 million, and is reflected in Deferred Credits and Other Liabilities - Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over a remaining period of 3 years.
The Company is collecting one mill per kilowatt-hour from its customers for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. This amount is 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 and decommissioning funds, are provided for differences between book and taxable income. Investment tax credits (ITC) are amortized over the estimated service lives of the related facilities.
Effective January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes" which requires the use of the liability method of financial accounting and reporting for income taxes. Under FAS 109, deferred income taxes reflect the impact of temporary differences between the amounts of assets and liabilities recognized for financial reporting purposes and the amounts recognized for tax purposes.
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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, 1994, the Company had $111 million of short-term notes outstanding, of which $27 million was commercial paper and the remainder was issued under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $528 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, 1994 and 1993, are as follows:
(In Millions) Carrying Fair Amount Value December 31, 1994: Preferred Securities of subsidiary $ 105 $ 101 Long-term debt 616 577
December 31, 1993: Long-term debt $ 524 $ 551
The fair values of the Company's long-term debt and preferred securities of subsidiary 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." In 1993, the cumulative effect on net income of this accounting change was immaterial. Also in 1993, the federal income tax rate changed from 34% to 35%, retroactive to January 1, 1993, resulting in an
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increase in the deferred tax assets of $2 million and an increase in the deferred tax liabilities of $16 million. The tax rate change did not have a material effect on net income as the changes in deferred taxes were substantially offset by the recording of regulatory assets and liabilities. As of December 31, 1994 and 1993, the balance sheet reflected $228 million and $234 million, respectively, of income taxes recoverable through future rates, (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $36 million and $39 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, 1994 and 1993 is as follows: (In Millions)
Deferred Tax Assets Deferred Tax Liabilities
1994 1993 1994 1993 Current: Current: Unbilled revenue $ 3 $ 1 Other - - Deferred energy $ 4 $ 8 Total $ 3 $ 1 Total $ 4 $ 8 Noncurrent: Noncurrent: Unamortized ITC $ 36 $ 39 Liberalized Decommissioning 35 11 depreciation: Contribution in aid previously flowed of construction 3 3 through $ 131 $ 134 Other 40 12 future revenue Total $114 $ 65 requirements 97 100 Subtotal 228 234 Liberalized depreciation 217 205 Other 9 16 Total $ 454 $ 455
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) 1994 1993 1992
Net income $ 32 $ 96 $ 99 Income tax expense 11 69 71 Book income subject to tax $ 43 $165 $170
Federal statutory rate 35% 35% 34% State tax, net of federal benefit 1 7 7 Other (10) - - Effective income tax rate 26% 42% 41%
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Federal and state income tax expense is comprised of the following:
(In Millions) 1994 1993 1992 Provisions for taxes currently payable $ 61 $ 51 $ 60
Deferred income taxes: Liberalized depreciation 12 8 7 Deferral of energy costs (3) 11 (1) Accretion income 5 - 1 Decommissioning (24) - - VERP (21) - - Other (15) 3 7 Deferred income taxes, net (46) 22 14 Amortization of ITC, net (4) (4) (3) Income tax expense $ 11 $ 69 $ 71
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) 1994 1993 1992
Maintenance $ 80 $ 81 $ 70 Other taxes: Pennsylvania state gross receipts $ 38 $ 36 $ 35 Real estate and personal property 8 8 8 Capital stock 9 9 10 Other 11 9 8 Total $ 66 $ 62 $ 61
For the years 1994, 1993 and 1992, the cost to the Company of services rendered to it by GPUSC amounted to approximately $40 million, $37 million and $35 million, respectively, of which approximately $31 million, $25 million and $24 million, respectively, were charged to income. For the years 1994, 1993 and 1992, the cost to the Company of services rendered to it by GPUN amounted
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to approximately $40 million, $46 million and $40 million, respectively, of which approximately $33 million, $38 million and $31 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) 1994 1993 1992 Service cost-benefits earned during the period $ 10.2 $ 8.0 $ 6.9 Interest cost on projected benefit obligation 30.6 29.9 29.5 Less: Expected return on plan assets (32.4) (30.4) (28.9) Amortization .5 0.1 - Net periodic pension cost $ 8.9 $ 7.6 $ 7.5
The above 1994 amounts do not include a pre-tax charge to earnings of $33 million relating to the VERP.
The actual return on the plans' assets for the years 1994, 1993 and 1992 were gains of $4.2 million, $46.1 million and $16.9 million, respectively.
The funded status of the plans and related assumptions at December 31, 1994 and 1993 were as follows: (In Millions) 1994 1993 Accumulated benefit obligation (ABO): Vested benefits $ 358.0 $ 315.8 Nonvested benefits 38.6 40.5 Total ABO 396.6 356.3 Effect of future compensation levels 57.0 63.6 Projected benefit obligation (PBO) $ 453.6 $ 419.9
PBO $( 453.6) $( 419.9) Plan assets at fair value 401.3 402.9 PBO in excess of plan assets (52.3) (17.0) Less: Unrecognized net loss 27.3 10.7 Unrecognized prior service cost 1.8 1.7 Unrecognized net transition obligation 3.5 4.0 Accrued pension liability $ (19.7) $ (.6) Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5 Annual increase in compensation levels 6.0 5.0
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In 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the PBO as of December 31, 1994. Also, in 1994, the PBO increased by $37 million as a result of the VERP. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net 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. 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 as a charge or credit to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1994, 1993 and 1992 were $3.0 million, $3.0 million and $2.8 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. For 1992, the annual premium costs associated with providing these benefits totaled approximately $6.2 million.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993 over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1994 and 1993 follows: (In Millions) 1994 1993 Service cost-benefits attributed to service during the period $ 4.6 $ 3.6 Interest cost on the accumulated postretirement benefit obligation 13.4 12.2 Expected return on plan assets (2.3) (1.2) Amortization of transition obligation 6.5 6.5 Other amortization, net .8 - Net periodic postretirement benefit cost 23.0 21.1 Net write-off (deferral) 9.0 (10.1) Total postretirement benefit cost $32.0 $ 11.0
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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 1994 and 1993 was a gain of $.8 million and $1.3 million, respectively.
The funded status of the plans at December 31, 1994 and 1993, was as follows:
(In Millions) 1994 1993 Accumulated Postretirement Benefit Obligation: Retirees $ 111.3 $ 83.8 Fully eligible active plan participants 21.4 23.0 Other active plan participants 67.2 75.7 Total accumulated postretirement benefit obligation (APBO) $ 199.9 $ 182.5
APBO $(199.9) $(182.5) Plan assets at fair value 53.1 18.6 APBO in excess of plan assets (146.8) (163.9) Less: Unrecognized net loss 15.9 25.3 Unrecognized prior service cost 2.5 2.9 Unrecognized transition obligation 112.4 123.7 Accrued postretirement benefit liability $ (16.0) $ (12.0)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 8.0 7.5
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 1994, changes in assumptions, primarily the increase in the discount rate assumption from 7.5% to 8%, resulted in a $14 million decrease in the APBO as of December 31, 1994. Also, in 1994, the APBO increased by $13 million as a result of the VERP. 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 13% for those not eligible for Medicare and 10% for those eligible for Medicare, then decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 31, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $19 million as of December 31, 1994 and the aggregate of the service and interest cost components of net periodic postretirement health-care cost by approximately $2 million.
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In 1993, the Company began deferring its FAS 106 incremental expense in accordance with the PaPUC's generic policy statement permitting the deferral of such costs. In 1994, the Pennsylvania Commonwealth Court reversed the PaPUC's decision concerning an unaffiliated Pennsylvania utility's deferral of such costs, stating that FAS 106 expense incurred after January 1, 1993 (the effective date for the accounting change) but prior to its next base rate case could not be deferred for future recovery, and that to assure such future recovery constituted retroactive ratemaking. As a result of the Court's decision, in the second quarter of 1994, the Company determined that deferred incremental FAS 106 expense was not likely to be recovered and wrote off $14.6 million deferred since January 1993. 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 during the second quarter of 1994. During the remainder of 1994, the Company continued to expense FAS 106 costs ($4.2 million) and anticipates annual charges to income of approximately $9 million, beginning in 1995, 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, 1994:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation
Homer City 50 $441.2 $158.7 Three Mile Island Unit 1 25 206.5 71.6 Seneca 20 16.4 4.5
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1994 and 1993 totaled $16 million and $21 million, respectively (net of amortization of $15 million and $8 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
The Company and its affiliates have nuclear fuel lease agreements with nonaffiliated fuel trusts. An aggregate of up to $125 million of nuclear fuel costs may be outstanding at any one time for TMI-1. 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
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for the disposal costs of nuclear fuel leased under these agreements. These nuclear fuel leases are renewable annually. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1994, 1993 and 1992 these amounts were $7 million, $7 million and $8 million, respectively. The leases may be terminated at any time with at least five months notice by either party prior to the end of the current period. Subject to certain conditions of termination, the Company and its affiliates are required to purchase all nuclear fuel then under lease at a price that will allow the lessor to recover its net investment.