ITEM 1. BUSINESS.
Pennsylvania Electric Company (Company), a Pennsylvania corporation incorporated in 1919, is a subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935 (the 1935 Act). The Company's business is the generation, transmission, distribution and sale of electricity. The Company 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 General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc., which develops, owns and operates nonutility generating facilities. All of the Company's affiliates are wholly-owned subsidiaries of GPU. The Company and its affiliates own all of the common stock of the Saxton Nuclear Experimental Corporation which owns a small demonstration nuclear reactor that has been partially decommissioned. The Company and its affiliates, GPUSC, GPUN and GPC considered together are referred to as the "GPU System."
As a subsidiary of a registered holding company, the Company is subject to regulation by the Securities and Exchange Commission (SEC) under the 1935 Act. The Company's retail rates, conditions of service, issuance of securities and other matters of the Company are subject to regulation by the Pennsylvania Public Utility Commission (PaPUC). The Nuclear Regulatory Commission (NRC) regulates the construction, ownership and operation of nuclear generating stations. The Company is also subject to wholesale rate and other regulation by the Federal Energy Regulatory Commission (FERC) under the Federal Power Act.
INDUSTRY DEVELOPMENTS
The Energy Policy Act of 1992 (Energy Act) has made significant changes to the 1935 Act and the Federal Power Act. As a result of this legislation, the FERC is now authorized to order utilities to provide transmission or wheeling service to third parties for wholesale power transactions provided specified reliability and pricing criteria are met. In addition, the legislation amends the 1935 Act to permit the development and ownership of a broad category of independent power production facilities by utilities and nonutilities alike without subjecting them to regulation under the 1935 Act. These and other aspects of the Energy Act are expected to accelerate the changing character of the electric utility industry. (See "Regulation.")
The electric utility industry appears to be undergoing a major transition as it proceeds from a traditional rate regulated environment based on cost recovery to some combination of a competitive marketplace and modified regulation of certain market segments. The industry challenges resulting from various instances of competition, deregulation and restructuring thus far have been minor compared with the impact that is expected in the future.
The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry of competitors into the electric generation business. Since then, more competition has been introduced through various state actions to encourage cogeneration and, most recently, the Energy Act. The Energy Act is intended to promote competition among utility and nonutility generators in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. This legislation, coupled with increasing customer demands for lower-priced electricity, is generally expected to stimulate even greater competition in both the wholesale and retail electricity markets. These competitive pressures may create opportunities to compete for new customers and revenues, as well as increase risk which could lead to the loss of customers.
Operating in a competitive environment will place added pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than supportable in the marketplace may experience reduced earnings as they attempt to meet their customers' demands for lower- priced electricity. This prospect of increasing competition in the electric utility industry has already led the major credit rating agencies to address and apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the FERC, subject to certain criteria, to order owners of electric transmission systems, such as the Company and its affiliates, to provide third parties with transmission access for wholesale power transactions. The Energy Act did not give the FERC the authority, however, to order retail transmission access. Movement toward opening the transmission network to retail customers is currently under consideration in several states.
The competitive forces have also begun to influence some retail pricing in the industry. In a few instances, industrial customers, threatening to pursue cogeneration, self-generation or relocation to other service territories, have leveraged price concessions from utilities. Recent state regulatory actions, such as in New Jersey, suggest that utilities may have limited success with attempting to shift costs associated with such discounts to other customers. Utilities may have to absorb, in whole or part, the effects of price reductions designed to retain large retail customers. State regulators may put a limit or cap on prices, especially for those customers unable to pursue alternative supply options.
Insofar as the Company is concerned, unrecovered costs will most likely be related to generation investment, purchased power contracts, and "regulatory assets", which are deferred accounting transactions whose value rests on the strength of a state regulatory decision to allow future recovery from ratepayers. In markets where there is excess capacity (as there currently is in the region including Pennsylvania) and many available sources of power supply, the market price of electricity may be too low to support full recovery of capital costs of certain existing power plants, primarily the capital intensive plants such as nuclear units. Another significant exposure in the transition to a competitive market results if the prices of a utility's existing purchase power contracts, consisting primarily of contractual obligations with nonutility generators, are higher than future market prices. Utilities locked into expensive purchase power arrangements may be forced to value the contracts at market prices and recognize certain losses. A third source of exposure is regulatory assets which, if not
supported by regulators, would have no value in a competitive market. Financial Accounting Standard No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation", applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. If a portion of the Company's operations continues to be regulated, FAS 71 accounting may only be applied to that portion. Write- offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result. At this time, it is difficult for management to project the future level of stranded assets or other unrecoverable costs, if any, without knowing what the market price of electricity will be, or if regulators will allow recovery of industry transition costs from customers.
Corporate Realignment
In February 1994, GPU announced a corporate realignment and related actions as a result of its ongoing strategic planning studies. GPU Generation Corporation (GPU Generation) will be formed to operate and maintain the fossil-fueled and hydroelectric generating units of the Company and its affiliates; ownership of the generating assets will remain with the Company and its affiliates. GPU Generation will also build new generation facilities as needed by the Company and its affiliates in the future. Involvement in the independent power generation market will continue through Energy Initiatives, Inc. Additionally, the management and staff of the Company and Met-Ed will be combined but the two companies will not be merged and will retain their separate corporate existence. This action is intended to increase effectiveness and lower cost. Included in this effort will be a search for parallel opportunities at GPUN and JCP&L. Completion of these realignment initiatives will be subject to various regulatory reviews and approvals from the SEC, FERC, PaPUC and the New Jersey Board of Regulatory Commissioners (NJBRC). The GPU System is also developing a performance improvement and cost reduction program to help assure ongoing competitiveness, and, among other matters, will also address workforce issues in terms of compensation, size and skill mix. The GPU System is seeking annual cost savings of approximately $80 million by the end of 1996 as a result of these organizational changes.
Duquesne Transaction
In September 1990, the Company and its affiliates entered into a series of interdependent agreements with Duquesne Light Company (Duquesne) for the joint construction and ownership of associated high voltage bulk transmission facilities and the purchase by JCP&L and Met-Ed of a 50% ownership interest in Duquesne's 300 MW Phillips Generating Station. The Company and its affiliates' share of the total cost of these agreements was estimated to be $500 million (of which the Company's share of its participation in the transmission line was $117 million), the major part of which was expected to be incurred after 1994. In addition, JCP&L and Met-Ed simultaneously entered into a related agreement with Duquesne to purchase 350 MW of capacity and energy from Duquesne for 20 years beginning in 1997. The Company and its
affiliates and Duquesne filed several petitions with the PaPUC and the NJBRC seeking certain of the regulatory authorizations required for the transactions.
In December 1993, the NJBRC denied JCP&L's request to participate in the proposed transactions. As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Company wrote off the approximately $8 million it had invested in the project.
GENERAL
The Company provides 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. The Company owns all of the common stock of the Waverly Electric Light & Power Company, the owner of electric distribution facilities in the village of Waverly, New York. The Company, as lessee of the property of the Waverly Electric Light and Power Company, also serves a population of about 13,700 in Waverly, New York and vicinity. The Company's other wholly-owned subsidiary is Nineveh Water Company.
The electric generating and transmission facilities of the Company, Met-Ed and JCP&L are physically interconnected and are operated as a single integrated and coordinated system. The transmission facilities are physically interconnected with neighboring nonaffiliated utilities in Pennsylvania, New Jersey, Maryland, New York and Ohio. The Company and its affiliates are members of the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and the Mid-Atlantic Area Council, an organization providing coordinated review of the planning by utilities in the PJM area. The interconnection facilities are used for substantial capacity and energy interchange and purchased power transactions as well as emergency assistance.
During 1993, residential sales accounted for about 37% of the Company's operating revenues from customers and 30% of kilowatt-hour (KWH) sales to customers; commercial sales accounted for about 32% of operating revenues from customers and 30% of KWH sales to customers; industrial sales accounted for about 27% of operating revenues from customers and 35% of KWH sales to customers; and sales to rural electric cooperatives, municipalities (primarily for street and highway lighting) and others accounted for about 4% of operating revenues from customers and 5% of KWH sales to customers. The Company also makes interchange and spot market sales of electricity to other utilities. The revenues derived from the 25 largest customers in the aggregate accounted for approximately 12% of operating revenues from customers for the year 1993. Reference is made to "Company Statistics" on page for additional information concerning the Company's sales and revenues.
The Company and its affiliates along with the other members of the PJM power pool, experienced an electric emergency due to extremely cold temperature from January 18 through January 20, 1994. In order to maintain the electric system and to avoid a total black-out, intermittent black-outs
for periods of one to two hours were instituted on January 19, 1994 to control peak loads. In February 1994, the NJBRC, the PaPUC and the FERC initiated investigations of the energy emergency, and forwarded data requests to all affected utilities. In addition, the United States House of Representatives' Energy and Power Subcommittee, among others, held hearings on this matter. At this time, management is unable to estimate the impact, if any, from any conclusions that may be reached by the regulators.
In May 1993, the Pennsylvania Office of Consumer Advocate (Consumer Advocate) filed a petition for review of Met-Ed's rate order with the Pennsylvania Commonwealth Court seeking to set aside a March 1993 decision which allowed Met-Ed to (a) recover in the future certain Three Mile Island Unit 2 (TMI-2) retirement costs (radiological decommissioning and nonradiological cost of removal) and (b) defer the incremental costs associated with the adoption of the Statement of Financial Accounting Standards No. 106 (FAS 106) "Employers' Accounting for Postretirement Benefits Other Than Pensions." If the 1993 Met-Ed rate order is reversed, the Company would be required to write off a total of approximately $50 million for TMI-2 retirement costs. In addition, the Consumer Advocate is contesting utility deferral of FAS 106 costs in a proceeding involving another utility. The outcome of this proceeding may affect the Company's recovery of FAS 106 costs. This matter is pending before the court. (See "Rate Proceedings.")
Competition in the electric utility industry has already played a significant role in wholesale transactions, affecting the pricing of energy sales to electric cooperatives and municipal customers. During 1993, the Company successfully negotiated power supply agreements with several existing GPU System wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of Met-Ed or JCP&L. The Company has made similar offers to certain wholesale customers now being served by other utilities. Although wholesale customers represent a relatively small portion of Company sales, the Company will continue its efforts to retain and add customers.
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 TMI-2, which was damaged during the 1979 accident. At December 31, 1993, the Company's net investment in TMI-1, including nuclear fuel, was $165 million. 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.
Costs associated with the operation, maintenance and retirement of nuclear plants have continued to increase and become less predictable, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at their nuclear plants because of the design criteria prevailing at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now assumed lives cannot be assured. Also, not all risks associated with ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric
utilities to obtain adequate and timely recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of the plants' useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs described above through the ratemaking process, but recognizes that recovery is not assured.
TMI-1
TMI-1, a 786-MW pressurized water reactor, was licensed by the NRC in 1974 for operation through 2008. The NRC has extended the TMI-1 operating license through April 2014, in recognition of the plant's approximate six- year construction period. During 1993, TMI-1 operated at a capacity factor of approximately 87%. A scheduled refueling outage that year lasted 36 days; the next refueling outage is scheduled for late 1995.
TMI-2
The 1979 TMI-2 accident resulted in significant damage to, and contamination of, the plant and a release of radioactivity to the environment. The cleanup program was completed in 1990, and, after receiving NRC approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates. Approximately 2,100 of such claims are pending in the U.S. District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. Questions have not yet been resolved as to whether the punitive damage claims are (a) subject to the overall limitation of liability set by the Price-Anderson Act ($560 million at the time of the accident) and (b) outside the primary insurance coverage provided pursuant to that Act (remaining primary coverage of approximately $80 million as of December 1993). If punitive damages are not covered by insurance or are not subject to the Price-Anderson liability limitation, punitive damage awards could have a material adverse effect on the financial position of the GPU System.
In June 1993, the District Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of twelve allegedly representative cases is scheduled to begin in October 1994. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy. See Note 2 to consolidated financial statements for further information regarding nuclear fuel disposal costs.
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for TMI-1 by the end of the plant's license term, 2014. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long- term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1993 dollars) for TMI-1 is $143 million, of which the Company's share is $36 million. Based on NRC studies, a comparable funding target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 million, of which the Company's share would be $57 million. The NRC is currently studying the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not actual cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
In 1988, a consultant to GPUN performed 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 $205 to $285 million (adjusted to 1993 dollars), of which the Company's share would range between approximately $51 to $71 million. In addition, the study estimated the cost of removal of nonradiological structures and materials for TMI-1 at $72 million, of which the Company's share would be $18 million.
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 is charging to expense and contributing to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has
contributed to external trusts amounts written off for nuclear plant decommissioning in 1991.
TMI-1
Effective October 1993, the PaPUC approved a rate change for the Company which increased the collection of revenues for decommissioning costs for 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 decommissioning expenditures are deposited in external trusts. These external trust funds, including the interest earned, are classified as Decommissioning Funds on the balance sheet. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $4 million at December 31, 1993.
Management believes that TMI-1 retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the ratemaking process.
TMI-2
The Company has recorded a liability amounting to $57 million, as of December 31, 1993, for its share of the radiological decommissioning of TMI- 2, reflecting the NRC funding target (unadjusted for an immaterial decrease in 1993). The Company records escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company has also recorded a liability in the amount of $5 million, for its share of incremental costs specifically attributable to monitored storage. Such costs are expected to be incurred between 1994 and 2014, when decommissioning is forecast to begin. In addition, the Company has recorded a liability in the amount of $18 million, for its share of nonradiological cost of removal. The above amounts for retirement costs and monitored storage are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. The Company has made a nonrecoverable contribution of $20 million to an external decommissioning trust relating to its share of the accident-related portion of the decommissioning liability.
The PaPUC has granted Met-Ed decommissioning revenues for its share of the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials, although the PaPUC's order has been appealed by the Consumer Advocate (see "Rate Proceedings"). The Company intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. Management intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
As a result of TMI-2's entering long-term monitored storage, the Company is incurring incremental storage costs currently estimated at $.25 million annually. The Company has deferred the $5 million, for its share of the total estimated incremental costs attributable to monitored storage through 2014, the expected retirement date of TMI-1. The Company believes these costs should be recoverable through the ratemaking process.
INSURANCE
The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company.
The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station (TMI-1 and TMI-2 are considered one site for insurance purposes) 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 the stations.
The Price-Anderson Act limits the of GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $9.4 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's reactors, subject to an annual maximum payment of $10 million per incident per reactor. In 1993, GPUN requested an exemption from the NRC to eliminate the secondary protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at their nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the outage and continues for three years at decreasing levels beginning at a weekly amount of $2.6 million.
Under its insurance policies applicable to nuclear operations and facilities, the Company is subject to retrospective premium assessments of up to $7 million in any one year, in addition to those payable under the Price-Anderson Act.
NONUTILITY AND OTHER POWER PURCHASES
The Company has entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other
contract limitations. All of these facilities are must-run and generally obligate the Company to purchase all of the power produced up to the contract limits. The agreements have been approved by the PaPUC and permit the Company to recover energy and demand costs from customers through its energy clause. These agreements provide for the sale of approximately 412 MW of capacity and energy to the Company by the mid 1990s. As of December 31, 1993, facilities covered by these agreements having 293 MW of capacity were in service. Payments made pursuant to these agreements were $104 million for 1993 and are estimated to aggregate $121 million for 1994. The price of the energy and capacity to be purchased under these agreements is determined by the terms of the contracts. The rates payable under a number of these agreements are in excess of current market prices. While the Company has been granted full recovery of these costs from customers by the PaPUC, there can be no assurance that the Company will continue to be able to recover these costs throughout the term of the related contracts. The emerging competitive market has created additional uncertainty regarding the forecasting of the Company's energy supply needs which, in turn, has caused the Company to change its supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Company is attempting to renegotiate higher cost long-term nonutility generation contracts where opportunities arise. The extent to which the Company may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before the PaPUC, as well as to litigation, and may result in claims against the Company for substantial damages. There can be no assurance as to the outcome of these matters.
In July 1993, the PaPUC acted to initiate a rulemaking proceeding which, in general, would establish a mandatory all source competitive bidding program by which utilities would meet their future capacity and energy needs.
In November 1993, the Company filed an appeal with the Commonwealth Court seeking to overturn a PaPUC order which directs the Company to enter into two power purchase agreements with nonutility generators for a total of 160 MW under long-term contracts commencing in 1997 or later. The Company believes it does not need this additional capacity and believes the costs associated with these contracts are not in the economic interests of its customers. The matter is pending before the Commonwealth Court.
The Company and its affiliates have entered into agreements with other utilities for the purchase of capacity and energy for various periods through 1999. These agreements provide for up to 2,130 MW in 1994, declining to 1,307 MW in 1995 and 183 MW by 1999. Payments pursuant to these agreements are estimated to aggregate $244 million in 1994. The price of the energy purchased under these agreements is determined by contracts providing generally for the recovery by the sellers of their costs.
RATE PROCEEDINGS
Pennsylvania
In March 1993, in response to a petition filed by the Company's affiliate Met-Ed, the PaPUC modified portions of its January 1993 Met-Ed rate order to allow for the future recovery of certain TMI-2 retirement costs (radiological decommissioning and nonradiological cost of removal). (See
"Nuclear Plant Retirement Costs.") In addition, the PaPUC action on the Met-Ed petition allowed the Company to defer the incremental costs associated with the adoption of FAS 106. In May 1993, the Consumer Advocate filed a petition for review with the Pennsylvania Commonwealth Court seeking to set aside the PaPUC 1993 Met-Ed rate order. The matter is pending before the court. If the 1993 rate order is reversed, the Company would be required to write off a total of approximately $50 million for TMI-2 retirement costs. The Company intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials for TMI-2, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. Management intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
In March 1993, the PaPUC issued a generic policy statement that permitted the deferral of FAS 106 costs for review and recovery in subsequent base rate making. Consistent with the PaPUC's policy statement, the Company filed a petition with the PaPUC in July 1993 for deferral of FAS 106 costs. That petition was approved by the PaPUC in October 1993. The Consumer Advocate is contesting utility deferral of FAS 106 costs in a proceeding involving another utility. The outcome of this proceeding may affect the Company's future recovery of these costs.
The PaPUC has recently completed its generic investigation into demand- side management (DSM) cost recovery mechanisms and issued a cost recovery and ratemaking order in December 1993. The Company is currently developing plans which will reflect changes since its original plan was filed in 1991. In December 1993, the Pennsylvania Industrial Energy Coalition (PIEC) appealed to the Commonwealth Court to reverse the PaPUC Order. On February 4, 1994, the Company and Met-Ed filed a petition seeking a stay of the PaPUC's Order until the PIEC's appeal is resolved (See "Construction Program - Demand-Side Management").
In March 1994, the Company made its annual filing with the PaPUC for an increase in its Energy Cost Rate of $38.3 million. The new rate is expected to become effective April 1, 1994.
The PaPUC is considering generic nuclear performance standards for Pennsylvania utilities. In January 1994, the Company submitted a proposal which, along with proposals submitted by the other Pennsylvania utilities, may result in the PaPUC adopting a generic nuclear performance standard.
CONSTRUCTION PROGRAM General
During 1993, the Company had gross plant additions of approximately $168 million attributable principally to improvements and modifications to existing generating stations, additions to the transmission and distribution system and clean air requirements. During 1994, the Company contemplates gross plant additions of approximately $218 million. The Company's gross plant additions are expected to total approximately $242 million in 1995. The anticipated increase in construction expenditures during 1995 is principally attributable to expenditures associated with clean air requirements. The principal categories of the 1994 anticipated expenditures, which include an allowance for other funds used during construction, are as follows:
(In Millions)
Generation - Nuclear $ 6 Nonnuclear 111 Total Generation 117 Transmission & Distribution 86 Other 15 Total $218
In addition, expenditures for maturing debt are expected to be $70 million for 1994. The Company will have no expenditures for maturing debt in 1995. Subject to market conditions, the Company intends to redeem during these periods outstanding senior securities pursuant to optional redemption provisions thereof should it prove economical to do so.
Management estimates that approximately one-half of the Company's total capital needs for 1994 and 1995 will be satisfied through internally generated funds. The Company expects to obtain the remainder of these funds principally through the sale of first mortgage bonds and preferred stock, subject to market conditions. The Company's bond indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short-term debt the Company may issue. The Company's interest and preferred stock dividend coverage ratios are currently in excess of indenture or charter restrictions. (see "Limitations on Issuing Additional Securities"). Present plans call for the Company to issue long- term debt and preferred stock during the next three years to finance construction activities and, depending on the level of interest rates, refinance outstanding senior securities.
The Company's 1994 construction program includes $66 million in connection with the federal Clean Air Act Amendments of 1990 (Clean Air Act) requirements (see "Environmental Matters-Air"). The 1995 construction program currently includes approximately $62 million for Clean Air Act compliance.
The Company's gross plant additions exclude nuclear fuel requirements provided under capital leases that amounted to $11 million in 1993. When consumed, the presently leased material, which amounted to $21 million at December 31, 1993, is expected to be replaced by additional leased material at an average rate of approximately $9 million annually. In the event the replacement nuclear fuel needs cannot be leased, the associated capital requirements would have to be met by other means.
The Company has projected increases in peak loads of approximately 275 MW (summer rating) and 440 MW (winter rating) by the year 1998. The Company expects to experience an average growth in sales to customers during this period of about 2.3% annually. The Company expects to meet this growth through existing and contracted supply sources and the utilization of capacity of its affiliates.
In response to the increasingly competitive business climate and excess capacity of nearby utilities, the Company's supply plan places an emphasis on maintaining flexibility. Supply planning focuses increasingly on short to
intermediate term commitments, reliance on "spot" markets, and avoidance of long-term firm commitments. Through 1998, the Company's plan consists of the continued utilization of most existing generating facilities, power purchases and the continued promotion of economic energy conservation and load management programs. Given the future direction of the industry, the Company's present strategy includes minimizing the financial exposure associated with new long-term purchase commitments and the construction of new facilities by including projected market prices in the evaluation of these options. The Company will resist efforts to compel it to add or contract for new capacity at costs that may exceed future market prices. In addition, the Company is attempting to renegotiate higher cost long-term nonutility generation contracts where opportunities arise.
Demand-Side Management
The regulatory environment in Pennsylvania encourages the development of new conservation and load management programs as evidenced by recent approval of a cost recovery mechanism for DSM. DSM includes utility sponsored activities designed to improve energy efficiency in customer end-use, and includes load management programs (i.e., peak reduction) and conservation programs (i.e., energy and peak reduction).
In 1990, the Company and Met-Ed jointly filed a proposal with the PaPUC on DSM issues. The proposal recommends that the PaPUC preapprove DSM programs of utilities to enable the collection of their costs and that the PaPUC issue an order on a generic basis. In December 1993, the PaPUC issued an order adopting generic guidelines for recovery of DSM expenses. Also in December 1993, the Consumer Advocate and the Pennsylvania Energy Office filed separate petitions for clarification and reconsideration of the PaPUC's order and the PIEC appealed to the Commonwealth Court to reverse the PaPUC order. On February 4, 1994, the Company and Met-Ed filed a petition seeking a stay of the PaPUC's order until the PIEC's appeal is resolved.
FINANCING ARRANGEMENTS
The Company expects to have short-term debt outstanding from time to time throughout the year. The peak in short-term debt outstanding is expected to occur in the spring coinciding with normal cash requirements for revenue tax payments.
GPU and the Company and its affiliates have $398 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks that permits total borrowing of $150 million outstanding at any one time. The credit facilities generally provide for the payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually. Borrowings under these credit facilities generally bear interest based on the prime rate or money market rates. Notes issued under the Credit Agreement, which expires April 1, 1995, are subject to various covenants and acceleration under certain conditions.
In 1993, the Company refinanced higher cost long-term debt in the principal amount of $108 million resulting in an estimated annualized after- tax savings of $1 million. Total long-term debt issued during 1993 amounted to $120 million. In addition, the Company redeemed $25 million of high- dividend rate preferred stock. The funds for this redemption were derived from GPU through sales of its common stock.
In January 1994, the Company issued an aggregate of $90 million of first mortgage bonds, of which a portion of the net proceeds were used to redeem early $38 million principal amount of 6 5/8% series bonds in late February 1994.
The Company has regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock for various periods through 1995. Under existing authorization, the Company may issue senior securities in the amount of $330 million, of which $100 million may consist of preferred stock. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper.
Under the Company and its affiliates' nuclear fuel lease agreements with nonaffiliated fuel trusts, up to $125 million of TMI-1 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.
LIMITATIONS ON ISSUING ADDITIONAL SECURITIES
The Company's first mortgage bond indenture and/or articles of incorporation include provisions which limit the total amount of securities evidencing secured indebtedness, and/or unsecured indebtedness which the Company may issue, the more restrictive of which are described below.
The Company's first mortgage bond indenture restricts the ratio of first mortgage bonds issued to not more than 60 percent of qualified property additions. At December 31, 1993, the Company had qualified property additions sufficient to permit the Company to issue approximately $270 million of additional first mortgage bonds. In addition, the indenture generally permits the Company to issue first mortgage bonds against like principal amount of previously retired bonds, which at December 31, 1993 totalled approximately $50 million.
The Company's mortgage indenture requires that for a period of any twelve consecutive months out of the fifteen calendar months preceding the issuance of additional first mortgage bonds, the Company's net earnings (before income taxes, with other income limited to 10% of operating income before income taxes) available for interest on first mortgage bonds shall have been at least twice the annual interest requirements on all first mortgage bonds to be outstanding immediately after such issuance. At December 31, 1993, these provisions would have permitted the Company to issue approximately $798 million principal amount of first mortgage bonds at an assumed rate of 8.0 percent. However, as described above, under the
Company's first mortgage bond indenture the Company had qualified property additions along with previously retired bonds which would have permitted it to issue only approximately $320 million of additional first mortgage bonds at such date.
Among other restrictions, the Company's articles of incorporation provide that without the consent of the holders of two-thirds of the outstanding preferred stock, no additional shares of preferred stock may be issued, unless, for a period of any twelve consecutive months out of the fifteen calendar months preceding such issuance (a) the Company's 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, and (b) the Company's 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 (1) the annual interest charges on indebtedness and (2) the annual dividend requirements on all shares of preferred stock to be outstanding immediately after such issuance. At December 31, 1993, these provisions would have permitted the Company to issue approximately $353 million stated value of cumulative preferred stock at an assumed dividend rate of 8.0 percent.
Under the Company's articles of incorporation, without the consent of the holders of a majority of the total voting power of the Company's outstanding preferred stock, the Company may not issue or assume any securities representing unsecured indebtedness (except to refund certain outstanding unsecured securities issued or assumed by the Company 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 issued or assumed by the Company would exceed 10 percent of the aggregate of (a) the total principal amount of all outstanding secured indebtedness issued or assumed by the Company and (b) the capital and surplus of the Company. At December 31, 1993, these restrictions would have permitted the Company to have approximately $135 million of unsecured indebtedness outstanding.
The Company has obtained authorization from the SEC to incur short-term debt (including indebtedness under the Credit Agreement and commercial paper) up to the Company's charter limitation.
REGULATION
As a registered holding company, GPU is subject to regulation by the SEC under the 1935 Act. The Company, as a subsidiary of GPU, is also subject to regulation under the 1935 Act with respect to accounting, the issuance of securities, the acquisition and sale of utility assets, securities or any other interest in any business, the entering into, and performance of, service, sales and construction contracts, and certain other matters. The SEC has determined that the electric facilities of the Company and its affiliates constitute a single integrated public utility system under the standards of the 1935 Act. The 1935 Act also limits the extent to which the Company may engage in nonutility businesses. The Company's retail rates for Pennsylvania customers, conditions of service, issuance of securities and
other matters are subject to regulation by the PaPUC. The Company's retail rates for New York customers are subject to regulation by the New York Public Service Commission (NYPSC). Moreover, with respect to wholesale rates, the transmission of electric energy, accounting, the construction and maintenance of hydroelectric projects and certain other matters, the Company is subject to regulation by the FERC under the Federal Power Act. The NRC regulates the construction, ownership and operation of nuclear generating stations and other related matters.
Although the Company does not render electric service in Maryland, the Public Service Commission of Maryland has jurisdiction over the portion of the Company's property located in that state. The Company has a levelized energy cost rate for Pennsylvania retail rates and current fuel adjustment clauses for wholesale rates and New York retail rates. The Company, as lessee, operates the facilities serving the Village of Waverly, New York, and the NYPSC has jurisdiction over such operations and property. (See "Electric Generation and the Environment - Environmental Matters" for additional regulation to which the Company is or may be subject.)
The rates charged by the Company for electric service are set by regulators under statutory requirements that they be "just and reasonable." As such, they are subject to adjustment, up or down, in the event they vary from that statutory standard. In 1992, as a result of a rulemaking proceeding, the PaPUC established quarterly financial reporting requirements to monitor public utility earnings.
ELECTRIC GENERATION AND THE ENVIRONMENT
Fuel
Of the portion of its energy requirements supplied by its own generation, the Company utilized fuels in the generation of electric energy during 1993 in approximately the following percentages: Coal--87%; Nuclear--12%; and Gas, Hydro and Oil--1%. For 1994, the Company estimates that its generation of electric energy will be supplied in approximately the same proportions. Approximately 8% of the Company's energy requirements in 1993 was supplied by purchases (including net interchange) from other utilities and nonutility generators. Approximately 13% of the Company's 1994 energy requirements are expected to be supplied by purchases (including net interchange) from other utilities and nonutility generators.
Fossil: The Company has entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for its Homer City generating station in which it has a fifty percent ownership interest. The contracts, which expire between 1995 and 2003, require the purchase of fixed amounts of coal. Under the contracts the price of coal is based on adjustments of indexed cost components. One contract also includes a provision for the payment of environmental and post-employment benefits. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $55 million for 1994.
The Company's coal-fired generating stations now in service are estimated to require an aggregate of 95 million tons of coal over the next twenty years. Of this total requirement, approximately 8 million tons are expected
to be supplied by a nonaffiliated mine-mouth coal company with the balance supplied through long-term contracts and spot market purchases.
At the present time, adequate supplies of fossil fuels are readily available to the Company, but this situation could change rapidly as a result of actions over which it has no control.
Nuclear: Preparation of nuclear fuel for generating station use involves various manufacturing stages for which the Company and its affiliates contract separately. Stage I involves the mining and milling of uranium ores to produce natural uranium concentrates. Stage II provides for the chemical conversion of the natural uranium concentrates into uranium hexafluoride. Stage III involves the process of enrichment to produce enriched uranium hexafluoride from the natural uranium hexafluoride. Stage IV provides for the fabrication of the enriched uranium hexafluoride into nuclear fuel assemblies for use in the reactor core at the nuclear generating station.
For TMI-1, under normal operating conditions, there is, with minor planned modifications, sufficient on-site storage capacity to accommodate spent nuclear fuel through the end of its licensed life while maintaining the ability to remove the entire reactor core.
Environmental Matters
The Company is subject to federal and state water quality, air quality, solid waste disposal and employee health and safety legislation and to environmental regulations issued by the U.S. Environmental Protection Agency (EPA), state environmental agencies and other federal agencies. In addition, the Company is subject to licensing of hydroelectric projects by the FERC and of nuclear power projects by the NRC. Such licensing and other actions by federal agencies with respect to projects of the Company are also subject to the National Environmental Policy Act.
As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material. The consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant are unknown. Management believes the costs described above should be recoverable through the ratemaking process but recognizes that recovery cannot be assured.
Water: The federal Water Pollution Control Act (Clean Water Act) generally requires, with respect to existing steam electric power plants, the application of the best conventional or practicable pollutant control technology available and compliance with state-established water quality
standards. With respect to future plants, the Clean Water Act requires the application of the "best available demonstrated control technology, processes, operating methods or other alternatives" to achieve, where practicable, no discharge of pollutants. Congress may amend the Clean Water Act during 1994.
The EPA has adopted regulations that establish thermal and other limitations for effluents discharged from both existing and new steam electric generating stations. Standards of performance are developed and enforcement of effluent limitations is accomplished through the issuance by the EPA, or states authorized by the EPA, of discharge permits that specify limitations to be applied. Discharge permits, which have been issued for all of the Company's generating stations, where required, have expiration dates ranging through 1996. Timely reapplications for such permits have been filed as required by regulations.
The Company is also subject to environmental and water diversion requirements adopted by the Delaware River Basin Commission and the Susquehanna River Basin Commission as administered by those commissions or the Pennsylvania Department of Environmental Resources (PaDER).
Nuclear: Reference is made to "Nuclear Facilities" for information regarding the TMI-2 accident, its aftermath and TMI-1.
Pennsylvania has established, in conjunction with several other states, a low level radioactive waste (radwaste) compact for the construction, licensing and operation of low level radwaste disposal facilities to service their respective areas by the year 2000. Pennsylvania, Delaware, Maryland and West Virginia have established the Appalachian Compact, which will build a single facility to dispose of low level radwaste in their areas, including low level radwaste from TMI-1. The estimated cost to license and build this facility is approximately $60 million, of which the Company and its affiliates' share is $12 million. These payments are considered advance waste disposal fees and will be recovered during the facility's operation.
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the Federal government. The Company's share of the total liability at December 31, 1993 amounted to $6 million. The Company made its initial payment in 1993. The remaining amounts recoverable from ratepayers is $7 million at December 31, 1993.
Air: The Company is subject to certain state environmental regulations of the PaDER. The Company is also subject to certain federal environmental regulations of the EPA.
The PaDER and the EPA have adopted air quality regulations designed to implement Pennsylvania and federal statutes relating to air quality.
Current Pennsylvania environmental regulations prescribe criteria that generally limit the sulfur dioxide content of stack gas emissions from generating stations constructed before 1972 and stations constructed after
1971 but before 1978, to 3.7 pounds and 1.2 pounds per million BTU of heat input, respectively. On a weighted average basis, the Company has been able to obtain coal having a sulfur content meeting these criteria. If, and to the extent that, the Company cannot continue to meet such limitations with processed coal, it may be necessary to retrofit operating stations with sulfur removal equipment that may require substantial capital expenditures as well as substantial additional operating costs. Such retrofitting, if it could be accomplished to permit continued reliable operation of the facilities concerned, would take approximately five years.
As a result of the Clean Air Act, which requires substantial reductions in sulfur dioxide and nitrogen oxide (NOx) emissions by the year 2000, it may be necessary for the Company to install and operate emission control equipment as well as switch to slightly lower sulfur coal at some of the Company's coal-fired plants in order to achieve compliance. To comply with Title IV of the Clean Air Act, the Company expects to expend up to $295 million by the year 2000, of which approximately $35 million has been spent as of December 31, 1993, for the installation of scrubbers, low NOx burner technology and various precipitator upgrades. The capital costs of this equipment and the increased operating costs of the affected stations are expected to be recoverable through the ratemaking process.
The Company's current strategy for Phase II compliance under the Clean Air Act is to evaluate the installation of scrubbers or fuel switching at the Homer City Unit 3 Station. Switching to lower sulfur coal is currently planned for the Seward and Warren Stations. Homer City Units 1 and 2 will use existing coal cleaning technology.
The Company continues to review available options to comply with the Clean Air Act, including those which may result from the development of an emission allowance trading market. The Company's compliance strategy, especially with respect to Phase II, could change as a result of further review, discussions with co-owners of jointly-owned stations and changes in federal and state regulatory requirements.
The ultimate impact of Title I of the Clean Air Act, which deals with the attainment of ambient air quality standards, is highly uncertain. In particular, this Title has established an ozone transport or emission control region that includes 11 northeast states. Pennsylvania is part of this transport region, and will be required to control NOx emissions to a level that will provide for the attainment of the ozone standard in the northeast. As an initial step, major sources of NOx will be required to implement Reasonably Available Control Technology (RACT) by May 31, 1995. This will affect the Company's steam generating stations. PaDER's RACT regulations have been approved by the Environmental Quality Board and became effective in January 1994. Large coal-fired combustion units are required to comply with a presumptive RACT emission limitation (technology) or may elect to use a case-by-case analysis to establish RACT requirements.
The ultimate impact of Title III of the Clean Air Act, which deals with emissions of hazardous air pollutants, is also highly uncertain. Specifically, the EPA has not completed a Clean Air Act study to determine whether it is appropriate to regulate emissions of hazardous air pollutants
from electric utility steam generating units. However, the Homer City Coal Processing Plant is being studied to determine if it is a major stationary source for air toxins.
Both the EPA and PaDER are questioning the attainment of National Ambient Air Quality Standards (NAAQS) for sulfur dioxide in the vicinity of the Chestnut Ridge Energy Complex (Homer City and Seward generating stations). The Homer City generating station is jointly owned with New York State Electric and Gas Corporation (NYSEG). The EPA and the PaDER have approved the use of a nonguideline air quality model. This model is more representative and less conservative than the EPA guideline model and will be used in the development of a compliance strategy for all generating stations in the Chestnut Ridge Energy Complex.
The area around the Warren generating station has been designated as nonattainment for sulfur dioxide. An air quality model evaluation study began in early 1993. The results of the study will be used to determine if a nonguideline model can be used. The study results will be available in 1994. A Consent Order and Agreement has been negotiated to allow PaDER to revise the implementation plan for Warren Station.
A model evaluation study is also being conducted at Shawville Station. The results of this study will be available in 1995.
Based on the results of the studies pursuant to NAAQS, significant sulfur dioxide reductions may be required at one or more of these stations which could result in material capital and additional operating expenditures.
Certain other environmental regulations limit the amount of particulate matter emitted into the environment. The Company has installed equipment at its coal-fired generating stations and may find it necessary to either upgrade or install additional equipment at certain of its stations to consistently meet particulate emission requirements.
In the fall of 1993, the Clinton Administration unveiled its climate change action plan which intends to reduce greenhouse gas emissions to 1990 levels by the year 2000. The climate action plan relies heavily on voluntary action by industry. The Company and its affiliates notified the Department of Energy (DOE) that they support the voluntary approach proposed by the President and expressed their intent to work with the DOE.
Title IV of the Clean Air Act requires Phase I and Phase II affected units to install a continuous emission monitoring system (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 all of the Company's affected units as required by EPA 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 the Company's generating stations for 1994, it is not anticipated that payments to be made to the Clean Air Fund will be material in amount.
The Clean Air Act has also expanded the enforcement options available to the EPA and the states and contains more stringent enforcement provisions and penalties. Moreover, citizen suits can seek civil penalties for violations of this act.
The EPA has established Best Available Retrofit Technology (BART) sulfur dioxide emission standards to be used for the Company's Shawville and Seward generating stations under the Good Engineering Practice stack height regulation. Dependent upon the Chestnut Ridge Compliance Strategy and the results of the Shawville model evaluation study mentioned above, lower sulfur coal purchases may be necessary for compliance. Discussions with the EPA regarding this matter are continuing.
In 1988, the Environmental Defense Fund (EDF), the New Jersey Conservation Foundation, the Sierra Club and Pennsylvanians for Acid Rain Control requested that the New Jersey Department of Environmental Protection and Energy (NJDEPE) and the NJBRC seek to reduce sulfur deposition in New Jersey, either by reducing emissions from both in-state and out-of-state sources, or by requiring that certain electricity imported into New Jersey be generated from facilities meeting minimum emission standards. The Company owns coal-fired generating facilities that supply electric energy to JCP&L and other New Jersey members of PJM. Hearings on the EDF petition were held during 1989 and 1990, and the matter is pending before the NJDEPE and the NJBRC.
In 1993, the Company made capital expenditures of approximately $32 million in response to environmental considerations and has included approximately $73 million for this purpose in its 1994 construction program. The operating and maintenance costs, including the incremental costs of low-sulfur fuel, for such equipment were approximately $40 million in 1993 and are expected to be approximately $39 million in 1994.
Electromagnetic Fields: There have been a number of scientific studies regarding the possibility of adverse health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. While some of the studies have indicated some association between exposure to EMF and cancer, other studies have indicated no such association. The studies have not shown any causal relationship between exposure to EMF and cancer, or any other adverse health effects. In 1990, the EPA issued a draft report that identifies EMF as a possible carcinogen, although it acknowledges that there is still scientific uncertainty surrounding these fields and their possible link to adverse health effects. On the other hand, a 1992 White House Office of Science and Technology policy report states that "there is no convincing evidence in the published literature to support the contention that exposures to extremely low frequency electric and magnetic fields generated by sources such as household appliances, video display terminals,
and local power lines are demonstrable health hazards." Additional studies, which may foster a better understanding of the subject, are presently underway.
Bills introduced in the Pennsylvania legislature could, if enacted, establish a framework under which the intensity of EMF produced by electric transmission and distribution lines would be limited or otherwise regulated.
The Company cannot determine at this time what effect, if any, this matter will have on it.
Residual Waste: PaDER has finalized the residual waste regulations which became effective in July 1992. These regulations impose additional restrictions on operating existing ash disposal sites and for siting future disposal sites and will increase the costs of establishing and operating these facilities. The main objective of these regulations is to prevent degradation of groundwater and to abate any existing degradation.
One of the first significant compliance requirements of the regulations is conducting groundwater assessments of landfills if existing groundwater monitoring indicates the possibility of degradation. The assessments require the installation of additional monitoring wells and the evaluation of one year's worth of data. All of the Company's active landfills require assessments. If the assessments show degradation of the groundwater, then the next step is to develop abatement plans. However, there is no specific timetable on the implementation of abatement activities, if required. The Company's landfills are to have preliminary permit modification applications submitted to the PaDER by July 1994, and complete permit applications under evaluation by July 1997. In addition, the regulations can also be enforced at sites closed since 1980 at the PaDER's option.
Other compliance requirements that will be implemented in the future include the lining of currently unlined disposal sites and storage impoundments. Impoundments also will eventually require groundwater monitoring systems and assessments of impact on groundwater. Groundwater abatement may be necessary at locations where pollution problems are identified. The removal of all the residual waste or "clean closed" will be done at some impoundments to eliminate the need for future monitoring and abatement requirements. Storage impoundments must have implemented groundwater monitoring plans by 2002, but PaDER can require this at any time prior to this date or defer full compliance beyond 2002 for some storage impoundments at their discretion. Also being evaluated are the exercising of beneficial use options authorized by the regulations, and source reductions.
There are also a number of issues still to be resolved regarding certain waivers related to the Company's existing landfill and storage impoundment compliance requirements. These waivers could significantly reduce the cost of many of the Company's facility compliance upgrades.
Another aspect of the regulations deals with the storage and disposal of polychlorinated biphenyl (PCB) wastes between 2 and 50 parts per million (ppm). Federal regulations only deal with wastes over 50 ppm. The compliance requirements for this regulation are currently being evaluated.
Hazardous/Toxic Wastes: Under the Toxic Substances Control Act (TSCA), the EPA has adopted certain regulations governing the use, storage, testing, inspection and disposal of electrical equipment that contains PCBs. Such regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs. The Company has met all requirements of the TSCA necessary to allow the continued use of equipment containing PCBs and has taken substantive voluntary actions to reduce the amount of PCB containing electrical equipment in its system.
Prior to 1947, the Company owned and operated manufactured gas plants in Pennsylvania. Wastes associated with the operation and dismantlement of these gas manufacturing plants may have been disposed of both on-site and off-site. Claims may be asserted against the Company for the cost of investigation and remediation of these waste disposal sites. The amount of such remediation costs and penalties may be significant and may not be covered by insurance.
The 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 has enacted legislation giving similar authority to the PaDER. Because of the nature of the Company's business, various by-products and substances are produced and/or handled that are classified as hazardous under one or more of these statutes. The Company generally provides for the treatment, disposal or recycling of such substances through licensed independent contractors, but these statutory provisions also impose potential responsibility for certain cleanup costs on the generators of the wastes. The Company has been notified by the EPA and 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 two hazardous and/or toxic waste sites. In addition, the Company has been requested to supply information to the EPA and state environmental authorities on several other sites for which the Company has not as 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 Company received notification in 1986 from the EPA that it is among the more than 800 PRPs under CERCLA who may be liable to pay for the cost associated with the investigation and remediation of the Maxey Flats disposal site, located in Fleming County, Kentucky. The Company is alleged to have contributed approximately .0003% of the total volume of waste shipped to the Maxey Flats site. On September 30, 1991, the EPA issued a Record of Decision (ROD) advising that a remedial alternative had been selected. The PRPs estimate the cost of the remedial alternative selected and associated activities identified in the ROD at more than $60 million, for which all responsible parties would be jointly and severally liable.
The EPA has initiated a suit under CERCLA and other laws for the initial cleanup of hazardous materials deposited at a waste disposal site at Harper Drive, Millcreek Township, Pennsylvania (Millcreek site). The Company is one of over 50 PRPs at this site. The Company 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 the Company and other PRPs. The Company'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.
The Company, 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. The Company, together with 22 others, has also been named as a third party defendant in an action under the CERCLA by the state of Ohio seeking to recover costs it has incurred and will incur in the future at the New Lyme landfill site.
The ultimate cost of remediation of these sites will depend upon changing circumstances as site investigations continue, including (a) the technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Company.
The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Management believes the costs described above should be recoverable through the ratemaking process.
FRANCHISES AND CONCESSIONS
The electric franchise rights of the Company 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 the Company 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 in clause (a) of the preceding sentence. The Company was granted a licensing exemption by the FERC for the operation of its Deep Creek hydroelectric project after its current license expired in December, 1993. Instead of reapplying for a FERC license, the Company is now able to negotiate with the Maryland Department of Natural Resources (DNR) for a permit to operate the plant. The DNR has agreed to permit the Company to continue operations at Deep Creek until an agreement is finalized. The Company also holds a license, which expires in 2002, for the continued operation and maintenance of the Piney hydroelectric project. In addition, the Company and the Cleveland Electric Illuminating Company hold a license expiring in 2015 for the Seneca pumped storage hydroelectric station, in which the Company has a 20% undivided interest. For the same station, the Company 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, the Company 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. The Company 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 the Company until it has recovered all capital invested in the project.
EMPLOYEE RELATIONS
At February 28, 1994, the Company had 3,532 full-time employees. The nonsupervisory production and maintenance employees of the Company and certain of its nonsupervisory clerical employees are represented for collective bargaining purposes by local unions of the International Brotherhood of Electrical Workers (IBEW) and the Utility Workers Union of America (UWUA).
The Company's five-year contracts with the IBEW and UWUA expire on May 14, 1998 and June 30, 1998, respectively.
ITEM 2.
ITEM 2. PROPERTIES
Generating Stations
At December 31, 1993, the Company's generating stations had an aggregate effective winter capability of 2,369,000 net kilowatts (KW), as follows:
Year of Name and Location of Station Installation Net KW
COAL-FIRED: Homer City, Homer City, Pa. (a) 1969-1977 942,000 Shawville, Shawville, Pa. 1954-1960 618,000 Seward, Seward, Pa. 1950-1957 199,000 Warren, Warren, Pa. 1948-1949 82,000
NUCLEAR: Three Mile Island Unit No. 1, Dauphin County, Pa. (b) 1974 203,000 GAS or OIL-FIRED: Other (c) 1960-1972 191,000 HYDROELECTRIC: Piney, Clarion, Pa. 1923-1926 28,000 Deep Creek, Oakland, Md. 1925 19,000 PUMPED STORAGE: Seneca, Warren, Pa. (d) 1969 87,000
Total 2,369,000
(a) Represents the Company's 50% interest in this station.
(b) Represents the Company's 25% interest in this unit.
(c) Consists of combustion turbine and internal combustion units, all of which are located in Pennsylvania.
(d) Represents the Company's 20% interest in this station which is a net user rather than a net producer of electric energy.
Substantially all of the Company's properties are subject to the lien of its first mortgage bond indenture.
The peak load of the Company, which occurred on January 18, 1994, was 2,514,000 KW.
Transmission and Distribution System
At December 31, 1993, the Company owned 649 transmission and distribution substations that had an aggregate installed transformer capacity of 16,008,712 kilovoltamperes (KVA), and 2,734 circuit miles of transmission lines, of which 235 miles were operated at 500 kilovolts (KV), 149 miles at 345 KV, 650 miles at 230 KV, 11 miles at 138 KV, 1,325 miles at 115 KV, and the balance of 364 miles at 46 KV. The Company's distribution system included 6,036,111 KVA of line transformer capacity, 22,145 pole miles of overhead lines and 1,704 trench miles of underground cables.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to "Nuclear Facilities - TMI-2", "Rate Proceedings" and "Environmental Matters" under Item 1 and to Note 1 of consolidated financial statements for a description of certain pending legal proceedings involving the Company. See page for reference to the Notes to Consolidated Financial Statements.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the Company's outstanding common stock is owned by GPU. During 1993, the Company paid $40 million in dividends on its common stock. On February 23, 1994, the Company paid $5 million in dividends on its common stock.
In accordance with the Company's mortgage indenture as supplemented, $10 million of the balance of retained earnings at December 31, 1993 is restricted as to the payment of dividends on its common stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
See page for reference to the Selected Financial Data required by this item.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
See page for reference to Management's Discussion and Analysis of Financial Condition and Results of Operations required by this item.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See page for reference to Financial Statements and Supplementary Data required by this item.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Identification of Directors
The present directors of the Company, their ages, positions held and business experience during the past five years are as follows:
Year First Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief 1992 Executive Officer R. L. Wise (b) 50 President 1986 J. G. Graham (c) 55 Vice President and Chief 1986 Financial Officer W. R. Stinson (d) 58 Vice President and 1985 Comptroller R. C. Arnold (e) 56 Director 1989 J. G. Herbein (f) 55 Vice President 1990 G. R. Repko (g) 48 Vice President 1993
(a) Mr. Leva became Chairman of the Board and Chief Executive Officer of the Company in 1992. He became Chairman, President and Chief Executive Officer of GPU in 1992. He is also Chairman, President, Chief Executive Officer and a director of GPUSC, Chairman of the Board, Chief Executive Officer and a director of JCP&L, Met-Ed and GPC, and Chairman of the Board and a director of GPUN. Prior to assuming his present positions, Mr. Leva served as President of JCP&L since 1986. He is also a director of Utilities Mutual Insurance Company, the New Jersey Utilities Association, Chemical Bank, NJ and Princeton Bank and Trust Company.
(b) Mr. Wise became President and a director in 1986. He is also a director of GPUSC and GPUN. Mr. Wise is also a director of USBANCORP, Inc. and U.S. National Bank.
(c) Mr. Graham became Senior Vice President in 1989 and Chief Financial Officer of GPU in 1987. He is also Executive Vice President, Chief Financial Officer and a director of GPUSC; Vice President, Chief Financial Officer and a director of JCP&L and Met-Ed; Vice President and Chief Financial Officer of GPUN; President and a director of GPC and a director of Energy Initiatives, Inc.
(d) Mr. Stinson has been Vice President and Comptroller since 1982.
(e) Mr. Arnold became Executive Vice President-Power Supply of GPUSC in 1990. He was Senior Vice President-Power Supply from 1987 to 1989. He is also a director of GPUSC, JCP&L and Met-Ed.
(f) Mr. Herbein became Vice President, Generation in December 1992. He was Vice President, Station Operations from 1982 to December 1992.
(g) Mr. Repko became Vice President, Customer Operations in April 1993. Prior to that time he served as Vice President, Division Operations since 1986.
The Company's directors are elected each year at the annual meeting of shareholders to serve until the next annual meeting of shareholders and until their respective successors are duly elected and qualified. There are no family relations among the directors and/or executive officers of the Company.
Identification of Executive Officers
The executive officers of the Company, their ages, positions held and business experience during the past five years are as follows:
Year First Name Age Position Elected
J. R. Leva (a) 61 Chairman and Chief 1992 Executive Officer R. L. Wise (b) 50 President 1980 T. N. Elston (c) 61 Vice President 1990 J. F. Furst (d) 47 Vice President 1984 J. G. Graham (e) 55 Vice President and Chief 1987 Financial Officer J. G. Herbein (f) 55 Vice President 1982 W. C. Matthews (g) 41 Secretary and Corporate 1990 Counsel D. W. Myers (h) 49 Vice President and 1993 Treasurer G. R. Repko (i) 48 Vice President 1982 W. R. Stinson (j) 58 Vice President and 1982 Comptroller
(a) See footnote (a) on page 29.
(b) See footnote (b) on page 29.
(c) Mr. Elston has been Vice President, Human Resources since March 1990. Prior to that time he served as Personnel Services Director since 1983.
(d) Mr. Furst became Vice President, Customer Services and Communication in April 1993. Prior to that time he served as Vice President, Customer Services since 1984.
(e) See footnote (c) on page 29.
(f) See footnote (f) above.
(g) Mr. Matthews has been Secretary and Corporate Counsel since November 1990. He served as Chief Counsel to the Independent Regulatory Review Commission of the State of Pennsylvania from October 1987 to November 1990.
(h) Mr. Myers became a Vice President and Treasurer of GPU in 1993. He is also Vice President and Treasurer of GPUSC, JCP&L, Met-Ed, GPUN and GPC. Prior to assuming his present positions, Mr. Myers served as Vice President and Comptroller of GPUN since 1986.
(i) See footnote (g) on page 30.
(j) See footnote (d) on page 29.
The Company's executive officers are elected each year at the first meeting of the Board of Directors held following the annual meeting of shareholders. Executive officers hold office until the next meeting of directors following the annual meeting of shareholders and until their respective successors are duly elected and qualified. There are no family relationships among the Company's executive officers.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
(1) "Other Annual Compensation" is composed entirely of the above-market interest accrued on the pre-retirement portion of deferred compensation.
(2) Number and value of aggregate restricted shares/units at the end of 1993 (dividends are paid or accrued on these restricted shares/units and reinvested):
Aggregate Shares/Units Aggregate Value Robert L. Wise 6,260 $159,160 John G. Herbein 1,990 $ 51,206 Willard R. Stinson 1,770 $ 45,655 George R. Repko 1,710 $ 44,094 Thomas N. Elston 1,570 $ 40,201
(3) As noted above, Mr. Leva is Chairman and Chief Executive Officer of the Company and its affiliates, as well as Chairman and Chief Executive Officer of GPU and GPUSC. Mr. Leva is compensated by GPUSC for his overall service on behalf of the GPU System and accordingly is not compensated directly by the Company for his services. Information with respect to Mr. Leva's compensation is included on pages 13 through 15 in GPU's 1994 definitive proxy statement, which are incorporated herein by reference.
(4) Consists of the Company's matching contributions under the Savings Plan ($9,434), matching contributions under the non-qualified deferred compensation plan ($1,696), the imputed interest on employer paid premiums for split-dollar life insurance ($5,286), and above-market interest accrued on the retirement portion of deferred compensation ($12,337).
(5) Consists of the Company's matching contributions under the Savings Plan ($4,368) and above-market interest accrued on the retirement portion of deferred compensation ($10,970).
(6) Consists of the Company's matching contributions under the Savings Plan ($5,330) and above-market interest accrued on the retirement portion of deferred compensation ($2,264).
(7) Consists of the Company's matching contributions under the Savings Plan.
(8) Consists of the Company's matching contributions under the Savings Plan ($4,657) and above-market interest accrued on the retirement portion of deferred compensation ($1,450).
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All of the Company's 5,290,596 outstanding shares of common stock are owned beneficially and of record by the Company's parent, General Public Utilities Corporation, 100 Interpace Parkway, Parsippany, New Jersey 07054.
The following table sets forth, as of February 1, 1994, the beneficial ownership of equity securities of the Company and other GPU System companies of each of the Company's directors, each of the named executive officers in the Summary Compensation Table and all directors and officers of the Company as a group. The shares owned by all directors and officers as a group constitute less than one percent of the total shares outstanding.
Amount and Nature of Name Title of Security Beneficial Ownership
R. C. Arnold GPU Common Stock 6,751 shares-Direct
J. G. Graham GPU Common Stock 6,411 shares-Direct 1,780 shares-Indirect
J. G. Herbein GPU Common Stock 1,071 shares-Direct
J. R. Leva GPU Common Stock 3,912 shares-Direct 100 shares-Indirect
G. R. Repko GPU Common Stock 897 shares-Direct
W. R. Stinson GPU Common Stock 1,132 shares-Direct
R. L. Wise GPU Common Stock 5,092 shares-Direct
All Directors and Officers as a Group GPU Common Stock 29,174 shares-Direct 1,880 shares-Indirect
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 the financial statement schedules required by this item.
1. Exhibits:
10-A 1990 Stock Plan for Employees of General Public Utilities Corporation and Subsidiaries, incorporated by reference to Exhibit 10-B of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
10-B Form of Restricted Units Agreement under the 1990 Stock Plan, incorporated by reference to Exhibit 10-C of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
10-C Incentive Compensation Plan for Officers of GPU System Companies, incorporated by reference to Exhibit 10-E of the GPU Annual Report on Form 10-K for 1993 - SEC File No. 1-6047.
12 Statements Showing Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
23 Consent of Independent Accountants
(b) Reports on Form 8-K:
For the month of December 1993, dated December 10, 1993, under Item 5 (Other Events).
For the month of February 1994, dated February 16 and February 28, 1994, under Item 5 (Other Events).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PENNSYLVANIA ELECTRIC COMPANY
Dated: March 10, 1994 BY: /s/ R. L. Wise R. L. Wise, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature and Title Date
/s/ J. R. Leva March 10, 1994 J. R. Leva, Chairman (Principal Executive Officer) and Director
/s/ R. L. Wise March 10, 1994 R. L. Wise, President and Director
/s/ J. G. Graham March 10, 1994 J. G. Graham, Vice President (Principal Financial Officer) and Director
/s/ W. R. Stinson March 10, 1994 W. R. Stinson, Vice President and Comptroller (Principal Accounting Officer) and Director
/s/ R. C. Arnold March 10, 1994 R. C. Arnold, Director
/s/ J. G. Herbein March 10, 1994 J. G. Herbein, Vice President, Generation and Director
/s/ G. R. Repko March 10, 1994 G. R. Repko, Vice President, Customer
Operations and Director
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
INDEX TO SUPPLEMENTARY DATA, CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
PAGE
Supplementary Data
Company Statistics
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quarterly Financial Data
Consolidated Financial Statements
Report of Independent Accountants
Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991
Consolidated Balance Sheets as of December 31, 1993 and 1992
Consolidated Statements of Retained Earnings for the years ended December 31, 1993, 1992 and 1991
Consolidated Statement of Long-Term Debt as of December 31, 1993
Consolidated Statement of Capital Stock as of December 31, 1993
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
Financial Statement Schedules
V - Property, Plant and Equipment for the Years 1991 to 1993
VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Years 1991 to 1993
VIII - Valuation and Qualifying Accounts for the Years 1991 to 1993
IX - Short-Term Borrowings for the Years 1991 to 1993
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.
Pennsylvania Electric Company and Subsidiary Companies
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
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 operation and maintenance expense, the write-off of approximately $8 million of costs related to the cancellation of proposed energy-related agreements, and increased depreciation expense. These items which decreased earnings were partially offset by higher KWH revenues, the recovery of prior period transmission service revenues and lower reserve capacity expense.
In 1992, earnings available for common stock decreased $6.3 million to $94.1 million. The decrease in earnings was principally because of lower kilowatt-hour revenues and decreased other income. These items which decreased earnings were offset somewhat by the effects of tax surcharge revenues for the 1991 state tax increases, lower interest charges on long- term debt and lower depreciation and amortization expenses. The earnings comparison also reflects the absence in 1992 of a nonrecurring credit with respect to a change in accounting policy resulting in the recognition of unbilled revenues in 1991 and a charge for certain TMI-2 costs in 1991.
The Company's return on average common equity was 13.5% for 1993 as compared to 14.5% for 1992.
REVENUES:
Total revenues increased 1.3% to $908 million in 1993 after increasing 3.6% in 1992 to $896 million. The components of these changes are as follows:
(In Millions) 1993 1992
Kilowatt-hour (KWH) revenues $ 6.3 $(3.4) (excluding energy portion) Energy revenues (5.2) 22.5 Other revenues 10.8 11.7 Increase in revenues $11.9 $30.8
Pennsylvania Electric Company and Subsidiary Companies
Kilowatt-hour revenues
KWH revenues increased in 1993 primarily from higher KWH usage by residential and commercial customers and higher capacity sales to associated companies. Revenues also increased because of new sales to the Company's principal wholesale customer. Wholesale purchases by this customer are now resold to consumers both inside and outside the Company's service territory. The 1992 federal Energy Policy Act (Energy Act) which allows transmission access and competition for wholesale customers made this possible. These out of service territory sales began during the third quarter of 1993 (See "Recent Events"). These increases were partially offset by decreased usage of industrial customers. One of the most significant reductions occurred because of the phase out of operations by the Company's largest industrial customer.
KWH revenues decreased in 1992 primarily from decreased KWH sales to one principal wholesale customer and the phase out of operations of the Company's largest industrial customer. The Company's largest industrial customer accounted for approximately 5% of total KWH sales to customers in 1991, its last full year of operation. These decreases were partially offset by increased KWH sales to residential and commercial customers.
Energy revenues
1993 and 1992 Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates (ECR's) billed to customers and expensed. Energy revenues decreased in 1993 as a result of decreased sales to non-associated utilities and the reclassification of certain transmission service revenues to Other revenues. The reclassification resulted from a favorable PaPUC Order allowing the Company to exclude these transmission service revenues from the Company's ECR. Partially offsetting these decreases were increased energy revenues resulting from higher energy cost rates in effect during the current periods. Energy revenues also increased in 1992 as a result of increased KWH sales to other utilities.
Other revenues
1993 and 1992 Earnings were favorably affected in 1993 primarily from the reclassification of the transmission service revenues mentioned above. Earnings were also favorably affected in 1992 as a result of a timing difference in the receipt of Pennsylvania tax surcharge revenues received during 1992 for state tax increases enacted in the third quarter of 1991. For both periods other revenues reflect increased wheeling revenues.
Pennsylvania Electric Company and Subsidiary Companies
OPERATING EXPENSES:
Power purchased and interchanged
Power purchased and interchanged with affiliated companies decreased in 1993 primarily as a result of lower capacity costs. The decrease in expense favorably affected earnings because capacity costs are not recovered through energy revenues. Power purchased and interchanged with nonaffiliated companies increased in 1993 primarily from increased nonutility generation purchases. This increase was partially offset by lower purchases from other utilities. The increase in expense related to nonaffiliated purchases had little effect on earnings in 1993 because this increase was primarily comprised of energy costs which are generally recovered through energy revenues.
Power purchased and interchanged increased in 1992 as a result of an increase in nonutility generation purchases and purchases from other utilities. This increase in expense had little effect on earnings in 1992 because it was comprised primarily of energy costs.
Other operation and maintenance
The increase in other operation and maintenance expense is due largely to higher outage activity at several of the Company's coal fired generating stations, higher payroll and higher tree trimming expenses. These increases were partially offset by the recognition of proceeds from the settlement of a property insurance claim.
The decrease in other operation and maintenance expense is due largely to the absence of $9.0 million of estimated costs recognized in 1991 for preparing the TMI-2 plant for long-term monitored storage. Excluding that amount, other operation and maintenance expense remained relatively stable in 1992.
Depreciation and amortization
Depreciation and amortization expense increased in 1993 primarily from higher cost of removal charges and a $3.6 million charge for TMI-2 non- radiological costs not considered likely to be recovered through ratemaking.
Pennsylvania Electric Company and Subsidiary Companies
Depreciation and amortization expense decreased $3.9 million in 1992 primarily because of a change in depreciation rates for the year, exclusive of a $20 million charge in 1991 for the Company's share of radiological TMI-2 decommissioning costs which are not considered likely to be recovered through ratemaking.
Taxes, other than income taxes
1993 and 1992 Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues.
OTHER INCOME AND DEDUCTIONS:
Other income, net
The reduction in Other income, net is principally because of the write- off of approximately $8 million 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 (Duquesne).
The decrease is mainly attributable to a reduction in interest income resulting from the 1991 collection of federal income tax refunds.
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt increased in 1993 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 ECR overcollections resulting from the reclassification in 1993 of certain transmission service revenues (See "Energy revenues").
Interest on long-term debt decreased primarily because of the refinancing of higher cost debt at lower available interest rates in 1992.
Preferred dividends decreased for both periods as a result of redemptions of preferred stock in 1993 and 1991 of $25 million and $35 million, respectively.
Pennsylvania Electric Company and Subsidiary Companies
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS:
The Company's capital needs were $150 million in 1993, consisting of cash construction expenditures. During 1993, construction funds were primarily used to continue to maintain and improve existing generating facilities, add to the transmission and distribution system and clean air act requirements. Construction expenditures are estimated to be $218 million in 1994, consisting mainly of $136 million for ongoing system development and $66 million for clean air requirements. Expenditures for maturing debt are expected to be $70 million for 1994. The Company will not have expenditures for maturing debt in 1995. In the mid 1990s, construction expenditures may include substantial amounts for clean air requirements and other system needs. Management estimates that approximately one-half of the Company's 1994 capital needs will be satisfied through internally generated funds.
The Company and its affiliates' capital leases consist primarily of leases for nuclear fuel. These nuclear fuel leases are renewable annually, subject to certain conditions. An aggregate of up to $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, 1993 totaled $21 million. When consumed, portions of the presently leased material will be replaced by additional leased material at a rate of approximately $9 million annually. In the event these nuclear fuel needs cannot be leased, the associated capital requirements would have to be met by other means.
FINANCING:
In 1993, the Company refinanced higher cost long-term debt in the principal amount of $108 million resulting in an estimated annualized after- tax savings of $1 million. Total long-term debt issued during 1993 amounted to $120 million. In addition, the Company redeemed $25 million of high- dividend rate preferred stock.
In January 1994, the Company issued an aggregate of $90 million of first mortgage bonds, of which a portion of the net proceeds were used to redeem early $38 million principal amount of 6 5/8% series bonds in late February 1994.
The Company has regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock for various periods through 1995. Under existing authorization, the Company may issue senior securities in the amount of $330 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.
Pennsylvania Electric Company and Subsidiary Companies
The Company's cost of capital and ability to obtain external financing is affected by its security ratings, which continue to remain well above minimum investment grade. The Company's first mortgage bonds are currently rated at an equivalent of an A rating by the three major credit rating agencies, while an equivalent of an A- rating is assigned to the preferred stock issues. In addition, the Company's commercial paper is rated as having a high credit quality.
During 1993, Standard & Poor's revised its financial benchmarking standards for rating the debt of electric utilities to reflect the changing risk profiles resulting primarily from the intensifying competitive pressures in the industry. These guidelines now include an assessment of each company's business risk. Standard & Poor's new rating structure changed the business outlook for the debt ratings of approximately one-third of the industry, which moved from "A-stable" to "A-negative", meaning their credit ratings may be lowered. The Company was classified as having an "average" business risk position. Moody's announced that it expects to reduce its average credit ratings for the electric utility industry within the next three years to take into account the effects of the new competitive environment. Duff & Phelps also indicated that it intends to introduce a forecast element to its quantitative analysis to, among other things, "alert investors to the possibility of equity value reduction and credit quality deterioration."
The Company's bond indenture and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt it may issue. The Company's interest and preferred stock coverage ratios are currently in excess of indenture or charter restrictions. The ability to issue securities in the future will depend on coverages at that time. Present plans call for the Company to issue long-term debt and preferred stock during the next three years to finance construction activities and, depending on the level of interest rates, refinance outstanding senior securities.
CAPITALIZATION:
The Company supports its credit quality rating by maintaining capitalization ratios that permit access to capital markets at a competitive cost. 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 rating. The targets and actual capitalization ratios are as follows:
Capitalization Target Range 1993 1992 1991 Common equity 44-47% 48% 46% 49% Preferred stock 8-10 4 7 7 Notes payable and long-term debt 48-43 48 47 44 100% 100% 100% 100%
Pennsylvania Electric Company and Subsidiary Companies
COMPETITIVE ENVIRONMENT:
The Push Toward Competition
The electric utility industry appears to be undergoing a major transition as it proceeds from a traditional rate regulated environment based on cost recovery to some combination of competitive marketplace and modified regulation of certain market segments. The industry challenges resulting from various instances of competition, deregulation and restructuring thus far have been minor compared with the impact that is expected in the future. The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the entry of competitors into the electric generation business. Since then, more competition has been introduced through various state actions to encourage cogeneration and, most recently, the Energy Act. The Energy Act is intended to promote competition among utility and nonutility generators in the wholesale electric generation market, accelerating the industry restructuring that has been underway since the enactment of PURPA. This legislation, coupled with increasing customer demands for lower-priced electricity, is generally expected to stimulate even greater competition in both the wholesale and retail electricity markets. These competitive pressures may create opportunities to compete for new customers and revenues, as well as increase risk which could lead to the loss of customers.
Operating in a competitive environment will place added pressures on utility profit margins and credit quality. Utilities with significantly higher cost structures than supportable in the marketplace may experience reduced earnings as they attempt to meet their customers' demands for lower- priced electricity. This prospect of increasing competition in the electric utility industry has already led the credit rating agencies to address and apply more stringent guidelines in making credit rating determinations.
Among its provisions, the Energy Act allows the Federal Energy Regulatory Commission (FERC), subject to certain criteria, to order owners of electric transmission systems, such as the Company, to provide third parties transmission access for wholesale power transactions. The Energy Act did not give the FERC the authority, however, to order retail transmission access. That authority lies with the individual states and movement toward opening the transmission network to retail customers is currently under consideration in several states.
Recent Events
Competition in the electric utility industry has already played a significant role in wholesale transactions, affecting the pricing of energy sales to electric cooperatives and municipal customers. During 1993, the Company successfully negotiated power supply agreements with several existing GPU System wholesale customers in response to offers made by other utilities seeking to provide electric service at rates lower than those of Met-Ed or JCP&L. The Company has made similar offers to certain wholesale customers now being served by other utilities. Although wholesale customers represent a relatively small portion of Company's sales, the Company will continue its efforts to retain and add customers by offering competitive rates.
Pennsylvania Electric Company and Subsidiary Companies
The competitive forces have also begun to influence some retail pricing in the industry. In a few instances, industrial customers, threatening to pursue cogeneration, self-generation or relocation to other service territories, have leveraged price concessions from utilities. Recent state regulatory actions, such as in New Jersey, suggest that utilities may have limited success with attempting to shift costs associated with such discounts to other customers. Utilities may have to absorb, in whole or part, the effects of price reductions designed to retain large retail customers. State regulators may put a limit or cap on prices, especially for those customers unable to pursue alternative supply options.
Financial Exposure
In the transition from a regulated to competitive environment, there can be a significant change in the economic value of a utility's assets. Traditional utility regulation provides an opportunity for recovery of the cost of plant assets, along with a return on investment, through ratemaking. In a competitive market, the value of an asset may be determined by the market price of the services derived from that asset. If the cost of operating existing assets results in above market prices, a utility may be unable to recover all of its costs, resulting in "stranded assets" and other unrecoverable costs. This may result in write-downs to remove stranded assets from a utility's balance sheet in recognition of their reduced economic value and the recognition of other losses.
Unrecovered costs will most likely be related to generation investment, purchase power contracts, and "regulatory assets", which are deferred accounting transactions whose value rests on the strength of a state regulatory decision to allow future recovery from ratepayers. In markets where there is excess capacity (as there currently is in the region including Pennsylvania) and many available sources of power supply, the market price of electricity may be too low to support full recovery of capital costs of certain existing power plants, primarily the capital intensive plants such as nuclear units. Another significant exposure in the transition to a competitive market results if the prices of a utility's existing purchase power contracts, consisting primarily of contractual obligations with nonutility generators, are higher than future market prices. Utilities locked into expensive purchase power arrangements may be forced to value the contracts at market prices and recognize certain losses. A third source of exposure is regulatory assets which if not supported by regulators would have no value in a competitive market. Financial Accounting Standard No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation", applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. If a portion of the Company's operations continues to be regulated, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on
Pennsylvania Electric Company and Subsidiary Companies
its results of operations and financial position may result. At this time, it is difficult for management to project the future level of stranded assets or other unrecoverable costs, if any, without knowing what the market price of electricity will be, or if regulators will allow recovery of industry transition costs from customers.
Positioning the GPU System
The typical electric utility today is vertically integrated, operating its plant assets to serve all customers within a franchised service territory. In the future, franchised service territories may be replaced by markets whose boundaries are defined by price, available capacity and transmission access. This may result in changes to the organizational structure of utilities and an emphasis on certain segments of the business among generation, transmission and distribution.
In order to achieve a strong competitive position in a less regulated future, the GPU System has in place a strategic planning process. In the initial phases of the program, task forces are defining the principal challenges facing GPU, exploring opportunities and risks, and defining and evaluating strategic alternatives.
Management is now analyzing issues associated with various competition and regulatory scenarios to determine how best to position the GPU System for a competitive environment. An initial outcome of the GPU System ongoing strategic planning process was a realignment proposed in February 1994, of certain system operations. Subject to necessary regulatory approval, a new subsidiary, GPU Generation Corporation, will be formed to operate and maintain the GPU System's fossil-fueled and hydroelectric generating stations, which are now owned and operated by the Company and its affiliates. It is also intended to combine the remaining operations of the Company and Met-Ed without merging the two companies. GPU is also developing a performance improvement and cost reduction program to help assure ongoing competitiveness, and, among other matters, will also address workforce issues in terms of compensation, size and skill mix.
MEETING ENERGY DEMANDS:
In response to the increasingly competitive business climate and excess capacity of nearby utilities, the Company's supply plan places an emphasis on maintaining flexibility. Supply planning focuses increasingly on short to intermediate term commitments, reliance on "spot" markets, and avoidance of long-term firm commitments. The Company is expected to experience an average growth rate in sales to customers through 1998 of about 1.7% annually. The Company will also have higher sales as a result of adding former JCP&L municipal customers and other load formerly serviced by JCP&L and Met-Ed, resulting in a total average growth of 2.3%. The Company also expects to experience peak load growth although at a somewhat lesser rate. Through 1998, the Company's plan consists of the continued utilization of existing
Pennsylvania Electric Company and Subsidiary Companies
generating facilities combined with present commitments for power purchases and the utilization of capacity of its affiliates. The plan also includes the continued promotion of economic energy conservation and load management programs. Given the future direction of the industry, the Company's present strategy includes minimizing the financial exposure associated with new long- term purchase commitments and the construction of new facilities by evaulating these options in terms of an unregulated power market. The Company will resist efforts to compel it to add new capacity at costs that may exceed future market prices. The Company is attempting to renegotiate higher cost long- term nonutility generation contracts where opportunities arise.
New Energy Supplies
The Company's supply plan includes the addition of 119 MW of presently contracted capacity by 1998 from nonutility generation suppliers.
In July 1993, the Pennsylvania Public Utility Commission (PaPUC) acted to initiate a rulemaking proceeding which, in general, would establish a mandatory all source competitive bidding program by which utilities would meet their future capacity and energy needs.
In November 1993, the Company filed an appeal with the Commonwealth Court seeking to overturn a PaPUC order which directs the Company to enter into two power purchase agreements with nonutility generators for a total of 160 MW under long-term contracts commencing in 1997 or later. The Company does not need this additional capacity and believes the costs associated with these contracts are not in the economic interests of its customers.
In December 1993, the New Jersey Board of Regulatory Commissioners (NJBRC) denied JCP&L's petition to participate in the proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne. As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. The capital costs of these transactions would have totaled approximately $500 million, of which the Company's share would have been approximately $117 million.
Conservation and Load Management
The regulatory environment in Pennsylvania encourages the development of new conservation and load management programs as evidenced by recent approval of a cost recovery mechanism for demand-side management (DSM) incentive regulations. DSM includes utility sponsored activities designed to improve energy efficiency in customer end-use, and includes load management programs (i.e., peak reduction) and conservation programs (i.e., energy and peak reduction).
Pennsylvania Electric Company and Subsidiary Companies
The PaPUC has recently completed its generic investigation into DSM cost recovery mechanisms and issued a cost recovery and ratemaking order in December 1993. The Company is currently developing plans which will reflect changes since its original plan was filed in 1991. New targets for DSM initiatives are currently being determined and will be identified when the new DSM plan is filed in the first quarter of 1994.
ENVIRONMENTAL ISSUES:
The Company is committed to complying with all applicable environmental regulations in a responsible manner. Compliance with the federal Clean Air Act Amendments of 1990 (Clean Air Act) and other environmental needs will present a major challenge to the Company through the late 1990s.
The Clean Air Act will require substantial reductions in sulfur dioxide and nitrogen oxide emissions by the year 2000. The Company's current plan includes installing and operating emission control equipment at some of its coal-fired plants as well as switching to lower sulfur coal at other coal- fired plants. To comply with the Clean Air Act, the Company expects to expend up to $295 million by the year 2000 for air pollution control equipment. The Company reviews its plans and alternatives to comply with the Clean Air Act on a least-cost basis taking into account advances in technology and the emission allowance market and assesses the risk of recovering capital investments in a competitive environment. The Company may be able to defer substantial capital investments while attaining the required level of compliance if an alternative such as increased participation in the emission allowance market is determined to result in the least-cost plan. This and other compliance alternatives may result in the substitution of increased operating expenses for capital costs. At this time, costs associated with the capital invested in this pollution control equipment and the increased operating costs of the affected stations are expected to be recoverable through the ratemaking process, but management recognizes that recovery is not assured.
For more information, see the Environmental Matters section of Note 1 to the consolidated financial statements.
LEGAL MATTERS - TMI-2 ACCIDENT CLAIMS:
As a result of the TMI-2 accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against the Company and its affiliates and GPU and are still pending. For more information, see Note 1 to the consolidated financial statements.
Pennsylvania Electric Company and Subsidiary Companies
EFFECTS OF INFLATION:
The Company is affected by inflation since the regulatory process results in a time lag during which increased operating expenses are not fully recovered in rates. Inflation may have an even greater effect in a period of increasing competition and deregulation as the Company and the utility industry attempt to keep rates competitive.
Inflation also affects the Company in the form of higher replacement costs of utility plant. In the past, the Company anticipated the recovery of these cost increases through the ratemaking process. However, as competition and deregulation accelerate throughout the industry, there can be no assurance of the recovery of these increased costs.
The Company is committed to long-term cost control and is continuing to seek measures to reduce or limit the growth in operating expenses. The prudent expenditure of capital and debt refinancing programs have kept down increases in debt levels and capital costs.
ACCOUNTING ISSUES:
In May 1993, the Financial Accounting Standards Board issued FAS 115, "Accounting for Certain Investments in Debt and Equity Securities", which is effective for fiscal years beginning after December 15, 1993. FAS 115 requires the recording of unrealized gains and losses with a corresponding offsetting entry to earnings or shareholder's equity. The impact on the Company's financial position is expected to be immaterial and there will be no impact on the results of operations. FAS 115 will be implemented in 1994.
Pennsylvania Electric Company and Subsidiary Companies
QUARTERLY FINANCIAL DATA (UNAUDITED)
First Quarter Second Quarter In Thousands 1993 1992 1993 1992
Operating revenues $231,148 $237,784 $219,232 $214,108 Operating income 45,279 40,832 32,357 29,356 Net income 33,212 29,832 20,246 17,870 Earnings available for common stock 31,796 28,416 18,830 16,454
Third Quarter Fourth Quarter In Thousands 1993 1992 1993 * 1992
Operating revenues $229,447 $215,750 $228,453 $228,695 Operating income 42,835 38,013 26,566 39,107 Net income 31,714 25,281 10,556 26,761 Earnings available for common stock 30,467 23,865 9,648 25,345
* Results for the fourth quarter of 1993 reflect a decrease in earnings of $4.6 million (net of income taxes of $2.7 million) for the write-off of the Duquesne transactions.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Pennsylvania Electric Company
We have audited the accompanying consolidated financial statements and the financial statement schedules of Pennsylvania Electric Company and Subsidiary Companies listed in the Index on page and set forth on pages to, inclusive, of this Form 10-K. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining on a test basis, evidence supporting the amounts and the 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 consolidated 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, 1993 and 1992 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As more fully discussed in Note 1 to 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. Also, as discussed in Note 2 to the financial statements, the Company changed its method of accounting for unbilled revenues in 1991.
Coopers & Lybrand
2400 Eleven Penn Center Philadelphia, Pennsylvania February 2, 1994
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES Consolidated Statements of Retained Earnings
(In Thousands) For The Years Ended December 31, 1993 1992 1991
Balance, beginning of year $278 482 $289 402 $265 358 Add, net income 95 728 99 744 106 595
Total 374 210 389 146 371 953
Deduct, cash dividends on capital stock:
Cumulative preferred stock (at the annual rates indicated below):
4.40% Series B ($ 4.40 a share) 250 250 250 3.70% Series C ($ 3.70 a share) 359 359 359 4.05% Series D ($ 4.05 a share) 258 258 258 4.70% Series E ($ 4.70 a share) 135 135 135 4.50% Series F ($ 4.50 a share) 193 194 194 4.60% Series G ($ 4.60 a share) 349 348 348 8.36% Series H ($ 8.36 a share) 2 090 2 090 2 090 8.12% Series I ($ 8.12 a share) 1 353 2 030 2 030 9.00% Series L ($ 2.25 a share) - - 525 Common stock (not declared on a per share basis) 40 000 105 000 75 000
Total 44 987 110 664 81 189
Deduct, other adjustments 933 - 1 362
Balance, end of year $328 290 $278 482 $289 402
The accompanying notes are an integral part of the consolidated financial statements.
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES Consolidated Statement of Long-Term Debt
December 31, 1993 (In Thousands)
First Mortgage Bonds-Series as noted (a)(b): 9.35 %, due 1994 $40 000 7.92 %, due 2002 $10 000 8.50 %, due 1994 30 000 7.40 %, due 2003 10 000 7.45 %, due 1996 30 000 6.60 %, due 2003 30 000 6 1/4%, due 1996 25 000 7.48 %, due 2004 40 000 6.80 %, due 1996 20 000 6.10 %, due 2004 30 000 6 1/4%, due 1997 26 000 7 3/4%, due 2006 12 000 6 5/8%, due 1998 38 000 8.05 %, due 2006 10 000 8.72 %, due 1999 30 000 6 1/8%, due 2007 16 420 6.15 %, due 2000 30 000 8 3/8%, due 2015 20 000 (c) 8.70 %, due 2001 30 000 6 1/2%, due 2016 25 000 (c) 7.40 %, due 2002 10 000 8.33 %, due 2022 20 000 7.43 %, due 2002 30 000 7.49 %, due 2023 30 000
Subtotal $592 420
Maturities and sinking fund requirements due within one year (70 000) 522 420
Other long-term debt 3 084 Other current obligations (8) Subtotal 3 076
Unamortized net discount on long-term debt (1 005) Total long-term debt $524 491
(a) Substantially all of the properties owned by the Company are subject to the lien of the mortgage.
(b) For the years 1994, 1996, 1997 and 1998, the Company has total long-term debt maturities of $70.0 million, $75.0 million, $26.0 million and $38.0 million, respectively. The Company has no long-term debt maturities in 1995.
(c) Effective as of any June 1 or December 1, the interest rate may be converted, at the option of the registered holder thereof, to a variable rate.
The accompanying notes are an integral part of the consolidated financial statements.
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARY COMPANIES Consolidated Statement of Capital Stock
December 31, 1993 (In Thousands)
Cumulative preferred stock, without par value, 11,435,000 shares authorized, 615,000 shares issued and outstanding, without mandatory redemption (a)&(b):
56 810 shares, 4.40% Series B (callable at $108.25 per share) $ 5 681 97 054 shares, 3.70% Series C (callable at $105.00 per share) 9 705 63 696 shares, 4.05% Series D (callable at $104.53 per share) 6 370 28 739 shares, 4.70% Series E (callable at $105.25 per share) 2 874 42 969 shares, 4.50% Series F (callable at $104.27 per share) 4 297 75 732 shares, 4.60% Series G (callable at $104.25 per share) 7 573 250 000 shares, 8.36% Series H (callable at $104.09 per share) 25 000
Subtotal - Cumulative preferred stock issued 61 500
Premium on cumulative preferred stock 342
Total cumulative preferred stock $ 61 842
Common stock, par value $20 per share, 5,400,000 shares authorized, 5,290,596 shares issued and outstanding $105 812
(a) If dividends upon any shares of preferred stock are in arrears in an amount equal to the annual dividend, the holders of preferred stock, voting as a class, are entitled to elect a majority of the board of directors until all dividends in arrears have been paid. No redemptions of preferred stock may be made unless dividends on all preferred stock for all past quarterly dividend periods have been paid or declared and set aside for payment. Stated value of the Company's cumulative preferred stock is $100 per share.
(b) No shares of capital stock have been sold during the three years ended December 31, 1993. All of the issued and outstanding shares of the 9% Series L (1,400,000 shares, stated value $35,000,000) and the 8.12% Series I (250,000 shares, stated value $25,000,000) cumulative preferred stock were redeemed on May 1, 1991 and September 17, 1993, respectively. The 1991 redemption of the 9% Series L and the 1993 redemption of the 8.12% Series I cumulative preferred stock resulted in charges to Retained Earnings of $1.4 million and $.9 million, respectively. No shares of capital stock were redeemed or repurchased during 1992.
The accompanying notes are an integral part of the consolidated financial statements.
Pennsylvania Electric Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pennsylvania Electric Company (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 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 General Portfolios Corporation (GPC), parent of Energy Initiatives, Inc., which develops, owns, and operates nonutility generating facilities. The Company and its affiliates, GPUSC, GPUN and GPC considered together 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. At December 31, 1993, the Company's net investment in TMI-1, including nuclear fuel, was $165 million. 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.
Costs associated with the operation, maintenance and retirement of nuclear plants have continued to increase and become less predictable, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at their nuclear plants because of the design criteria prevailing at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now assumed lives cannot be assured. Also, not all risks associated with ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric utilities to obtain adequate and timely recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of the plants' useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. Management intends, in general, to seek recovery of any such costs described above through the ratemaking process, but recognizes that recovery is not assured.
Pennsylvania Electric Company and Subsidiary Companies
TMI-2:
The 1979 TMI-2 accident resulted in significant damage to, and contamination of, the plant and a release of radioactivity to the environment. The cleanup program was completed in 1990. After receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993.
As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates. Approximately 2,100 of such claims are pending in the U.S. District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. Questions have not yet been resolved as to whether the punitive damage claims are (a) subject to the overall limitation of liability set by the Price-Anderson Act ($560 million at the time of the accident) and (b) outside the primary insurance coverage provided pursuant to that Act (remaining primary coverage of approximately $80 million as of December 31, 1993). If punitive damages are not covered by insurance or are not subject to the Price-Anderson liability limitation, punitive damage awards could have a material adverse effect on the financial position of the GPU System.
In June 1993, the District Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of twelve allegedly representative cases is scheduled to begin in October 1994. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price-Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. The Court also denied the defendants' motion seeking a dismissal of all cases on the grounds that the defendants complied with applicable federal safety standards regarding permissible radiation releases from TMI-2 and that, as a matter of law, the defendants therefore did not breach any duty that they may have owed to the individual plaintiffs. The Court stated that a dispute about what radiation and emissions were released cannot be resolved on a motion for summary judgment.
NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. As described in the Nuclear Fuel Disposal Fee section of Note 2, the disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE).
In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for TMI-1 by the end of the plant's license term, 2014. 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
Pennsylvania Electric Company and Subsidiary Companies
the NRC regulations, the funding target (in 1993 dollars) for TMI-1 is $143 million, of which the Company's share is $36 million. Based on NRC studies, a comparable funding target for TMI-2 (in 1993 dollars), which takes into account the accident, is $228 million, of which the Company's share would be $57 million. The NRC is currently studying the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not actual cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials.
In 1988, a consultant to GPUN performed 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 $205 to $285 million (adjusted to 1993 dollars), of which the Company's share would range between approximately $51 to $71 million. In addition, the study estimated the cost of removal of nonradiological structures and materials for TMI-1 at $72 million, of which the Company's share would be $18 million.
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 is charging to expense and contributing to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed to external trusts amounts written off for nuclear plant decommissioning in 1991.
TMI-1:
Effective October 1993, the Pennsylvania Public Utility Commission (PaPUC) approved a rate change for the Company which increased the collection of revenues for decommissioning costs for 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 decommissioning expenditures are deposited in external trusts and are classified as Decommissioning Funds on the balance sheet, which includes the interest earned on these funds. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $4 million at December 31, 1993.
Pennsylvania Electric Company and Subsidiary Companies
Management believes that any TMI-1 retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable through the ratemaking process.
TMI-2:
The Company and its affiliates have recorded a liability amounting to $229 million (of which the Company's share was $57 million) as of December 31, 1993, for the radiological decommissioning of TMI-2, reflecting the NRC funding target (unadjusted for an immaterial decrease in 1993). The Company and its affiliates record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company and its affiliates have also recorded a liability in the amount of $20 million (of which the Company's share was $5 million) for incremental costs specifically attributable to monitored storage. Such costs are expected to be incurred between 1994 and 2014, when decommissioning is forecast to begin. In addition, the Company and its affiliates have recorded a liability in the amount of $71 million (of which the Company's share was $18 million) for nonradiological cost of removal. The above amounts for retirement costs and monitored storage are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. The Company has made a nonrecoverable contribution of $20 million to an external decommissioning trust relating to its share of the accident-related portion of the decommissioning liability.
The PaPUC has granted Met-Ed decommissioning revenues for its share of the remainder of the NRC funding target and allowances for its share of the cost of removal of nonradiological structures and materials. In March 1993, a PaPUC rate order for Met-Ed allowed for the future recovery of certain TMI-2 retirement costs. In May 1993, the Pennsylvania Office of Consumer Advocate filed a petition for review with the Pennsylvania Commonwealth Court seeking to set aside the PaPUC's 1993 Met-Ed rate order. The matter is pending before the court. If the 1993 rate order is reversed, the Company would be required to write off a total of approximately $50 million for retirement costs. The Company intends to request decommissioning revenues and an allowance for the cost of removal of nonradiological structures and materials, equivalent to its share of the amounts granted to Met-Ed, in its next retail base rate filing. Management intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured.
Upon TMI-2's entering long-term monitored storage, the Company and its affiliates will incur currently estimated incremental annual storage costs of $1 million (of which the Company's share will be $.25 million). The Company and its affiliates have deferred the $20 million (of which the Company's share was $5 million) for the total estimated incremental costs attributable to monitored storage. The Company believes these costs should be recoverable through the ratemaking process.
Pennsylvania Electric 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 (TMI-1 and TMI-2 are considered one site for insurance purposes) 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 the stations.
The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $9.4 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's reactors, subject to an annual maximum payment of $10 million per incident per reactor. In 1993, GPUN requested an exemption from the NRC to eliminate the secondary protection requirements for TMI-2. This matter is pending before the NRC.
The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at their nuclear plants. Coverage for TMI-1 commences after the first 21 weeks of the outage and continues for three years at decreasing levels beginning at a weekly amount of $2.6 million.
Under its insurance policies applicable to nuclear operations and facilities, the Company and its affiliates are subject to retrospective premium assessments of up to $52 million in any one year (of which the Company's share is $7 million), in addition to those payable under the Price-Anderson Act.
Pennsylvania Electric 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 or clean up waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants and mine refuse piles, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material. Management intends to seek recovery through the ratemaking process for any additional costs, but recognizes that recovery cannot be assured.
To comply with the federal Clean Air Act Amendments of 1990, the Company expects to expend up to $295 million for air pollution control equipment by the year 2000. Costs associated with the capital invested in this equipment and the increased operating costs of the affected stations should be recoverable through the ratemaking process.
The Company has been notified by the Environmental Protection Agency (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 two hazardous and/or toxic waste sites. In addition, the Company has been requested to supply information to the EPA and state environmental authorities on several other sites for which it has not as yet been named 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. Management believes the costs described above should be recoverable through the ratemaking process.
OTHER COMMITMENTS AND CONTINGENCIES
The PaPUC is considering generic nuclear performance standards for Pennsylvania utilities. At the request of the PaPUC, the Company,
Pennsylvania Electric Company and Subsidiary Companies
as well as the other Pennsylvania utilities, have supplied the PaPUC with proposals which may result in the PaPUC adopting a generic nuclear performance standard in the future.
In December 1993, the NJBRC denied JCP&L's request to participate in the proposed power supply and transmission facilities agreements between the Company and its affiliates and Duquesne Light Company (Duquesne). As a result of this action and other developments, the Company and its affiliates notified Duquesne that they were exercising their rights under the agreements to withdraw from and thereby terminate the agreements. Consequently, the Company wrote off the approximately $8 million it had invested in the project.
The Company's construction program, for which substantial commitments have been incurred and which extends over several years, contemplate expenditures of approximately $218 million during 1994. As a consequence of reliability, licensing, environmental and other requirements, substantial additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of any such costs through the ratemaking process, but recognizes that recovery is not assured.
As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry appears to be moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71), the Company's financial statements reflect assets and costs based on current cost- based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator;
b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.
Pennsylvania Electric Company and Subsidiary Companies
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. 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 long-term contracts with nonaffiliated mining companies for the purchase of coal for its Homer City generating station in which it has a fifty percent ownership interest. The contracts, which expire between 1995 and 2003, require the purchase of fixed amounts of coal. Under the contracts the price of coal is based on adjustments of indexed cost components. One contract also includes a provision for the payment of environmental and post-employment benefits. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $55 million for 1994.
The Company and its affiliates have entered into agreements with other utilities for the purchase of capacity and energy for various periods through 1999. These agreements provide for up to 2,130 MW in 1994, declining to 1,307 MW in 1995 and 183 MW by 1999. Payments pursuant to these agreements are estimated to aggregate $244 million in 1994. The price of the energy purchased under these agreements is determined by contracts providing generally for the recovery by the sellers of their costs.
The Company has also entered into power purchase agreements with independently owned power production facilities (nonutility generators) for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements are subject to penalties for nonperformance and other contract limitations. All of these facilities are must-run and generally obligate the Company to purchase all of the power produced up to the contract limits. The agreements have been approved by the PaPUC and permit the Company to recover energy and demand costs from customers through its energy clause. These agreements provide for the sale of approximately 412 MW of capacity and energy to the Company by the mid 1990s. As of December 31, 1993, facilities covered by these agreements having 293 MW of capacity were in service.
Pennsylvania Electric Company and Subsidiary Companies
Payments made pursuant to these agreements were $104 million, $77 million and $61 million for 1993, 1992 and 1991, respectively, and are estimated to aggregate $121 million for 1994. The price of the energy and capacity to be purchased under these agreements is determined by the terms of the contracts. The rates payable under a number of these agreements are in excess of current market prices. While the Company has been granted full recovery of these costs from customers by the PaPUC, there can be no assurance that the Company will continue to be able to recover these costs throughout the term of the related contracts. The emerging competitive market has created additional uncertainty regarding the forecasting of the Company's energy supply needs which, in turn, has caused the Company to change its supply strategy to seek shorter term agreements offering more flexibility. At the same time, the Company is attempting to renegotiate presently higher cost long-term nonutility generation contracts where opportunities arise. The extent to which the Company may be able to do so, however, or recover associated costs through rates, is uncertain. Moreover, these efforts have led to disputes before the PaPUC, as well as to litigation, and may result in claims against the Company for substantial damages. There can be no assurance as to the outcome of these matters.
During the normal course of the operation of its business, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as defendants in litigation in which compensatory damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these matters will have a material effect on the 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 and, beginning in 1991, an estimate of unbilled revenues to record services provided to the end of the respective accounting period.
DEFERRED ENERGY COSTS
Energy costs are recognized in the period in which the related energy clause revenues are billed.
Pennsylvania Electric Company and Subsidiary Companies
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 2.74%, 2.86% and 3.08% for the years 1993, 1992 and 1991, respectively.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The Uniform System of Accounts defines AFUDC as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to construction work in progress, and the equivalent credits are to interest charges for the pretax cost of borrowed funds and to other income for the allowance for other funds. While AFUDC results in an increase in utility plant and represents current earnings, it is realized in cash through depreciation or amortization allowances only when the related plant is recognized in rates. On an aggregate composite basis, the annual rates utilized were 4.91%, 4.15% and 8.50% for the years 1993, 1992 and 1991, respectively.
AMORTIZATION POLICIES
Accounting for TMI-2 Investment: The Company has collected all of its TMI-2 investment attributable to its retail customers. Because the Company had not been provided revenues for a return on the unamortized balance of its share of the damaged TMI-2 facility, this investment was carried at its discounted present value. The related annual accretion, which represents the carrying charges that are accrued as the asset is written up from its discounted value, is recorded in Other Income, Net.
Nuclear Fuel: Nuclear fuel is amortized on a unit of production basis. Rates are determined and periodically revised to amortize the cost over the useful life.
Pennsylvania Electric Company and Subsidiary Companies
The Company has provided for future contributions to the Decontamination and Decommissioning Fund (part of the Energy Act) for the cleanup of enrichment plants operated by the federal government. The total liability at December 31, 1993 amounted to $6 million and is primarily reflected in Deferred Credits and Other Liabilities - Other. Utilities with nuclear plants will contribute a total of $150 million annually, based on an assessment computed on prior enrichment purchases, over a 15 year period up to a total of $2.3 billion (in 1993 dollars). The Company made its initial payment to this fund in 1993. The Company has recorded an asset for remaining amounts recoverable from ratepayers of $7 million at December 31, 1993 in Deferred Debits and Other Assets - Other.
NUCLEAR OUTAGE MAINTENANCE COSTS
The Company accrues its share of incremental nuclear outage maintenance costs anticipated to be incurred during scheduled nuclear plant refueling outages.
NUCLEAR FUEL DISPOSAL FEE
The Company is providing for its share of the 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, 1993, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounts to $12 million, and is reflected in Deferred Credits and Other Liabilities- Other. As the actual liability is in excess of the amount recovered to date from ratepayers, the Company has reflected such excess of $.5 million at December 31, 1993 in Deferred Debits and Other Assets-Other. The rates presently charged to customers provide for the collection of these costs, plus interest, over a remaining period of four years.
The Company is collecting 1 mill per kilowatt-hour from its customers for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. These amounts are remitted quarterly to the DOE.
INCOME TAXES
The GPU System files a consolidated federal income tax return and all participants are jointly and severally liable for the full amount of any tax, including penalties and interest, 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.
Pennsylvania Electric Company and Subsidiary Companies
Deferred income taxes, which result primarily from liberalized depreciation methods and deferred energy costs, are provided for differences between book and taxable income. Investment tax credits (ITC) are amortized over the estimated service lives of the related facilities.
Effective January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes" which requires the use of the liability method of financial accounting and reporting for income taxes. Under FAS 109, deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amounts recognized for tax purposes.
STATEMENTS OF CASH FLOWS
For the purpose of the consolidated statements of cash flows, temporary investments include all unrestricted liquid assets, such as cash deposits and debt securities, with maturities generally of three months or less.
3. SHORT-TERM BORROWING ARRANGEMENTS
At December 31, 1993, the Company had $102 million of short-term notes outstanding, of which $37 million was commercial paper and the remainder was issued under bank lines of credit (credit facilities).
GPU and the Company and its affiliates have $398 million of credit facilities, which includes a Revolving Credit Agreement (Credit Agreement) with a consortium of banks that permits total borrowing of $150 million outstanding at any one time. The credit facilities generally provide for the payment of a commitment fee on the unborrowed amount of 1/8 of 1% annually. Borrowings under these credit facilities generally bear interest based on the prime rate or money market rates. Notes issued under the Credit Agreement which expires April 1, 1995, are subject to various covenants and acceleration under certain conditions.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value of the Company's long-term debt, as of December 31, 1993 and 1992 is as follows:
(In Thousands)
Carrying Fair Amount Value 1993 $524,491 $550,751 1992 582,647 601,810
The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities.
Pennsylvania Electric Company and Subsidiary Companies
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 $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. The balance sheet effect as of December 31, 1993 of implementing FAS 109 resulted in a regulatory asset for income taxes recoverable through future rates of $234 million (related to liberalized depreciation), and a regulatory liability for income taxes refundable through future rates of $39 million (related to unamortized ITC), substantially due to the recognition of amounts not previously recorded.
A summary of the components of deferred taxes as of December 31, 1993 follows:
(In Millions)
Deferred Tax Assets Deferred Tax Liabilities
Current: Current: Unbilled revenue $ 1 Deferred energy $ 7
Noncurrent: Noncurrent: Unamortized ITC $39 Liberalized Decommissioning 11 depreciation: Contribution in aid previously flowed of construction 3 through $134 Other 12 future revenue Total $65 requirements 100 $234
Liberalized depreciation 205 Other 16 Total $455
Pennsylvania Electric Company and Subsidiary Companies
The reconciliations from net income to book income subject to tax and from the federal statutory rate to combined federal and state effective tax rates are as follows: (In Millions) 1993 1992 1991
Net income $ 96 $ 99 $106 Income tax expense 69 71 59 Book income subject to tax $165 $170 $165
Federal statutory rate 35% 34% 34% Effect of difference between tax and book depreciation for which deferred taxes were not provided 2 3 4 Amortization of ITC (2) (2) (3) State tax, net of federal benefit 7 7 6 Other - (1) (5) Effective income tax rate 42% 41% 36%
Federal and state income tax expense is comprised of the following:
(In Millions) 1993 1992 1991
Provisions for taxes currently payable $ 51 $ 60 $ 59
Deferred income taxes: Liberalized depreciation 8 7 9 Decommissioning - - (8) Deferral of energy costs 11 (1) 1 Accretion income - 1 1 Unbilled revenues (1) 2 8 Nuclear outage maintenance costs 1 (1) - TMI-2 pre-monitored storage costs - 2 (4) Interest on prior years' taxes - - (4) Other 3 4 2 Deferred income taxes, net 22 14 5 Amortization of ITC, net (4) (3) (5) Income tax expense $ 69 $ 71 $ 59
The Internal Revenue Service has completed its examinations of the GPU System's federal income tax returns through 1986. The GPU System and the Internal Revenue Service have reached an agreement to settle GPU's claim that TMI-2 has been retired for tax purposes. When approved by the Joint Congressional Committee on Taxation, this settlement will provide refunds for previously paid taxes. GPU estimates that the Company would receive net refunds totaling $4 million, which would be credited to its customers. The Company would also be entitled to receive net interest estimated to total $11 million (before income taxes) through December 31, 1993, which would be credited to income. The years 1987, 1988 and 1989 are currently under audit.
Pennsylvania Electric Company and Subsidiary Companies
6. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Maintenance expense and other taxes charged to operating expenses consisted of the following:
(In Millions) 1993 1992 1991
Maintenance $81 $70 $66 Other taxes: State gross receipts $36 $35 $35 Capital stock 9 10 10 Real estate and personal property 8 8 8 Other 9 8 8 Total $62 $61 $61
For the years 1993, 1992, and 1991, the cost to the Company of services rendered to it by GPUSC amounted to approximately $37 million, $35 million and $33 million, respectively, of which approximately $25 million, $24 million and $23 million, respectively, were charged to income. For the years 1993, 1992, and 1991, the cost to the Company of services rendered to it by GPUN amounted to approximately $46 million, $40 million and $42 million, respectively, of which approximately $38 million, $31 million and $34 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) 1993 1992 1991
Service cost-benefits earned during the period $ 8.0 $ 6.9 $ 8.7 Interest cost on projected benefit obligation 29.9 29.5 26.8 Less: Expected return on plan assets (30.4) (28.9) (27.2) Add: Amortization .1 - - Net periodic pension cost $ 7.6 $ 7.5 $ 8.3
The actual return on the plans' assets for the years 1993, 1992 and 1991 were gains of $46.1 million, $16.9 million and $61.3 million, respectively.
Pennsylvania Electric Company and Subsidiary Companies
The funded status of the plans and related assumptions at December 31, 1993 and 1992 were as follows:
(In Millions) 1993 1992
Accumulated benefit obligation (ABO): Vested benefits $ 315.8 $ 272.0 Nonvested benefits 40.5 33.6 Total ABO 356.3 305.6 Effect of future compensation levels 63.6 57.8 Projected benefit obligation (PBO) $ 419.9 $ 363.4
PBO $ (419.9) $ (363.4) Plan assets at fair value 402.9 369.4 PBO (in excess of) less than plan assets (17.0) 6.0 Unrecognized net loss (gain) 10.7 (7.9) Unrecognized prior service credits (costs) 1.7 (4.2) Unrecognized net transition obligation 4.0 4.4 Accrued pension liability $ (.6) $ (1.7)
Principal actuarial assumptions(%): Annual long-term rate of return on plan assets 8.5 8.5 Discount rate 7.5 8.5 Annual increase in compensation levels 5.0 6.0
Changes in assumptions in 1993 primarily due to reducing the discount rate assumption from 8.5% to 7.5%, resulted in a $38 million change in the PBO as of December 31, 1993. The assets of the plans are held in a Master Trust and generally invested in common stocks, fixed income securities and real estate equity investments. The unrecognized net 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 credit or cost resulting from retroactive changes in benefits is being amortized as a charge or credit, respectively, to pension cost over the average remaining service periods for covered employees. The unrecognized net transition obligation arising out of the adoption of Statement of Financial Accounting Standards No. 87 is being amortized as a charge to pension cost over the average remaining service periods for covered employees.
Savings Plans:
The Company also maintains savings plans for substantially all employees. These plans provide for employee contributions up to specified limits. The Company's savings plans provide for various levels of matching contributions. The matching contributions for the Company for 1993, 1992 and 1991 were $3.0 million, $2.8 million and $2.6 million, respectively.
Pennsylvania Electric Company and Subsidiary Companies
Postretirement Benefits Other than Pensions:
The Company provides certain retiree health care and life insurance benefits for substantially all employees who reach retirement age while working for the Company. Health care benefits are administered by various organizations. A portion of the costs are borne by the participants. For 1992 and 1991, the annual premium costs associated with providing these benefits totaled approximately $6.2 million and $5.8 million, respectively.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 (FAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS 106 requires that the estimated cost of these benefits, which are primarily for health care, be accrued during the employee's active working career. The Company has elected to amortize the unfunded transition obligation existing at January 1, 1993, over a period of 20 years.
A summary of the components of the net periodic postretirement benefit cost for 1993 follows: (In Millions) Service cost-benefits attributed to service during the period $ 3.6 Interest cost on the accumulated postretirement benefit obligation 12.2 Expected return on plan assets (1.2) Amortization of transition obligation 6.5 Net periodic postretirement benefit cost 21.1 Less, deferred for future recovery (10.1) Postretirement benefit cost, net of deferrals $ 11.0
The actual return on the plans' assets for the year 1993 was a gain of $1.3 million.
The funded status of the plans at December 31, 1993, was as follows: (In Millions) Accumulated Postretirement Benefit Obligation: Retirees $ 83.8 Fully eligible active plan participants 23.0 Other active plan participants 75.7 Total accumulated postretirement benefit obligation (APBO) $ 182.5
APBO $(182.5) Plan assets at fair value 18.6 APBO (in excess of) plan assets (163.9) Less: Unrecognized net loss 25.3 Unrecognized prior service cost 2.9 Unrecognized transition obligation 123.7 Accrued postretirement benefit liability $ (12.0)
Principal actuarial assumptions (%): Annual long-term rate of return on plan assets 8.5 Discount rate 7.5
Pennsylvania Electric Company and Subsidiary Companies
The Company intends to fund amounts for postretirement benefits with an independent trustee, as deemed appropriate from time to time. The plan assets include equities and fixed income securities.
The Company has begun to defer the incremental postretirement benefit costs, charged to expense, associated with the adoption of FAS 106 and in accordance with Emerging Issues Task Force (EITF) Issue Number 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises", as authorized by the PaPUC in 1993. A portion of the increase in annual costs recognized under FAS 106 of $10.1 million is being deferred and should be recoverable through the ratemaking process. The Consumer Advocate in Pennsylvania is contesting utility deferral of FAS 106 costs in a proceeding involving another utility. The outcome of this proceeding may affect the Company's recovery of deferred FAS 106 costs.
The accumulated postretirement benefits obligation was determined by application of the terms of the medical and life insurance plans, including the effects of established maximums on covered costs, together with relevant actuarial assumptions and health-care cost trend rates of 14% for those not eligible for Medicare and 11% for those eligible for Medicare for 1994, decreasing gradually to 7% in 2000 and thereafter. These costs also reflect the implementation of a cost cap of 6% for individuals who retire after December 1, 1995. The effect of a 1% annual increase in these assumed cost trend rates would increase the accumulated postretirement benefit obligation by approximately $18 million and the aggregate of the service and interest cost components of net postretirement health-care cost for 1994 by approximately $2 million.
Postemployment Benefits:
In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (FAS 112) which addresses accounting by employers who provide benefits to former or inactive employees after employment but before retirement, which is effective for fiscal years beginning after December 15, 1993. The Company adopted the accrual method required under FAS 112 during 1993, which did not have a material impact on the financial position or results of operations of the Company.
Pennsylvania Electric Company and Subsidiary Companies
8. JOINTLY OWNED STATIONS
Each participant in a jointly owned station finances its portion of the investment and charges its share of operating expenses to the appropriate expense accounts. The Company participated with affiliated and nonaffiliated utilities in the following jointly owned stations at December 31, 1993:
Balance (In Millions) % Accumulated Station Ownership Investment Depreciation
Homer City 50 $428.9 $151.3 Three Mile Island Unit 1 25 206.2 64.4 Seneca 20 16.5 4.4
9. LEASES
The Company's capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital leases at December 31, 1993 and 1992 totaled $21 million and $17 million, respectively (net of amortization of $20 million and $15 million, respectively). The recording of capital leases has no effect on net income because all leases, for ratemaking purposes, are considered operating leases.
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, 1993, 1992 and 1991 the Company's share of these amounts were $7 million, $8 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.