-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Og4QDvw6eMqmj3kK7kJkAAr4tFtsur0LBB8EwyLlf4FMBYhgqeMJI/q7BZMfmlzH Z6y83pS8iCYaOKSMz9m0qQ== 0000053456-95-000031.txt : 19951109 0000053456-95-000031.hdr.sgml : 19951109 ACCESSION NUMBER: 0000053456-95-000031 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951108 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: JERSEY CENTRAL POWER & LIGHT CO CENTRAL INDEX KEY: 0000053456 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 210485010 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03141 FILM NUMBER: 95588293 BUSINESS ADDRESS: STREET 1: 300 MADISON AVE CITY: MORRISTOWN STATE: NJ ZIP: 079621911 BUSINESS PHONE: 2014558200 10-Q 1 JERSEY CENTRAL -10Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1995 OR ___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission file number 1-3141 Jersey Central Power & Light Company (Exact name of registrant as specified in its charter) New Jersey 21-0485010 (State or other jurisdiction of (I.R.S. Employer) incorporation or organization) Identification No.) 300 Madison Avenue Morristown, New Jersey 07962-1911 (Address of principal executive offices) (Zip Code) (201) 455-8200 (Registrant's telephone number, including area code) N/A (Former name, former address and former fiscal year, if changed since last report.) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No The number of shares outstanding of each of the issuer's classes of common stock, as of October 31, 1995, was as follows: Common stock, par value $10 per share: 15,371,270 shares outstanding. Jersey Central Power & Light Company Quarterly Report on Form 10-Q September 30, 1995 Table of Contents Page PART I - Financial Information Financial Statements: Balance Sheets 3 Statements of Income 5 Statements of Cash Flows 6 Notes to Financial Statements 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 20 PART II - Other Information 25 Signatures 26 _________________________________ The financial statements (not examined by independent accountants) reflect all adjustments (which consist of only normal recurring accruals) which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented, subject to the ultimate resolution of the various matters as discussed in Note 1 to the Consolidated Financial Statements. -2- JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY Consolidated Balance Sheets
In Thousands September 30, December 31, 1995 1994 (Unaudited) ASSETS Utility Plant: In service, at original cost $4 243 760 $4 119 617 Less, accumulated depreciation 1 630 308 1 499 405 Net utility plant in service 2 613 452 2 620 212 Construction work in progress 168 371 136 884 Other, net 112 357 123 349 Net utility plant 2 894 180 2 880 445 Other Property and Investments: Nuclear decommissioning trusts 208 274 165 511 Nuclear fuel disposal fund 92 799 82 920 Other, net 7 053 6 906 Total other property and investments 308 126 255 337 Current Assets: Cash and temporary cash investments 8 226 1 041 Special deposits 7 361 4 608 Accounts receivable: Customers, net 162 041 126 760 Other 14 686 16 936 Unbilled revenues 53 318 59 288 Materials and supplies, at average cost or less: Construction and maintenance 97 019 95 937 Fuel 18 523 18 563 Deferred energy costs 11 164 (148) Deferred income taxes 10 616 10 454 Prepayments 82 237 45 880 Total current assets 465 191 379 319 Deferred Debits and Other Assets: Regulatory assets: Three Mile Island Unit 2 deferred costs 126 831 138 294 Unamortized property losses 101 064 104 451 Income taxes recoverable through future rates 143 900 132 642 Other 312 533 309 230 Total regulatory assets 684 328 684 617 Deferred income taxes 126 494 122 944 Other 18 478 13 978 Total deferred debits and other assets 829 300 821 539 Total Assets $4 496 797 $4 336 640 The accompanying notes are an integral part of the consolidated financial statements. -3-
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY Consolidated Balance Sheets
In Thousands September 30, December 31, 1995 1994 (Unaudited) LIABILITIES AND CAPITAL Capitalization: Common stock $ 153 713 $ 153 713 Capital surplus 450 769 435 715 Retained earnings 834 721 772 240 Total common stockholder's equity 1 439 203 1 361 668 Cumulative preferred stock: With mandatory redemption 134 000 150 000 Without mandatory redemption 37 741 37 741 Company-obligated mandatorily redeemable preferred securities 125 000 - Long-term debt 1 192 890 1 168 444 Total capitalization 2 928 834 2 717 853 Current Liabilities: Securities due within one year 83 140 47 439 Notes payable 37 381 110 356 Obligations under capital leases 90 607 102 059 Accounts payable: Affiliates 30 186 34 283 Other 96 391 118 369 Taxes accrued 8 421 22 561 Interest accrued 30 285 29 765 Other 103 426 75 159 Total current liabilities 479 837 539 991 Deferred Credits and Other Liabilities: Deferred income taxes 615 709 598 843 Unamortized investment tax credits 68 642 72 928 Three Mile Island Unit 2 future costs 86 693 85 273 Regulatory liabilities 38 979 41 732 Other 278 103 280 020 Total deferred credits and other liabilities 1 088 126 1 078 796 Commitments and Contingencies (Note 1) Total Liabilities and Capital $4 496 797 $4 336 640 The accompanying notes are an integral part of the consolidated financial statements. -4-
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY Consolidated Statements of Income (Unaudited)
In Thousands Three Months Nine Months Ended September 30, Ended September 30, 1995 1994 1995 1994 Operating Revenues $625 479 $567 827 $1 546 594 $1 513 634 Operating Expenses: Fuel 33 454 25 950 74 263 80 597 Power purchased and interchanged: Affiliates 9 854 8 068 13 222 13 194 Others 182 420 157 519 493 698 437 082 Deferral of energy and capacity costs, net (355) 832 (10 746) (8 211) Other operation and maintenance 114 888 126 864 341 265 412 850 Depreciation and amortization 49 150 46 943 145 111 141 104 Taxes, other than income taxes 65 421 64 773 171 298 177 981 Total operating expenses 454 832 430 949 1 228 111 1 254 597 Operating Income Before Income Taxes 170 647 136 878 318 483 259 037 Income taxes 51 190 37 574 79 965 58 942 Operating Income 119 457 99 304 238 518 200 095 Other Income and Deductions: Allowance for other funds used during construction 399 70 856 179 Other income, net 3 728 3 557 10 713 23 154 Income taxes (1 491) (2 438) (4 273) (9 645) Total other income and deductions 2 636 1 189 7 296 13 688 Income Before Interest Charges and Dividends on Preferred Securities 122 093 100 493 245 814 213 783 Interest Charges and Dividends on Preferred Securities: Interest on long-term debt 23 461 23 579 69 421 70 981 Other interest 2 161 3 140 7 684 12 011 Allowance for borrowed funds used during construction (1 651) (799) (3 698) (2 054) Dividends on company-obligated mandatorily redeemable preferred securities 2 675 - 3 953 - Total interest charges and dividends on preferred securities 26 646 25 920 77 360 80 938 Net Income 95 447 74 573 168 454 132 845 Preferred stock dividends 3 586 3 698 10 871 11 096 Earnings Available for Common Stock $ 91 861 $ 70 875 $ 157 583 $ 121 749 The accompanying notes are an integral part of the consolidated financial statements. -5-
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY Consolidated Statements of Cash Flows (Unaudited)
In Thousands Nine Months Ended September 30, 1995 1994 Operating Activities: Net income $ 168 454 $ 132 845 Adjustments to reconcile income to cash provided: Depreciation and amortization 157 747 155 433 Amortization of property under capital leases 24 342 23 883 Voluntary enhanced retirement programs - 46 862 Nuclear outage maintenance costs, net 12 588 (1 507) Deferred income taxes and investment tax credits, net 16 733 11 860 Deferred energy and capacity costs, net (10 814) (8 008) Accretion income (9 390) (10 156) Allowance for other funds used during construction (856) (179) Changes in working capital: Receivables (27 061) 20 345 Materials and supplies (1 042) (1 890) Special deposits and prepayments (39 111) (141 905) Payables and accrued liabilities (55 906) 10 279 Other, net (32 120) (7 585) Net cash provided by operating activities 203 564 230 277 Investing Activities: Cash construction expenditures (158 272) (146 400) Contributions to decommissioning trusts (13 523) (12 719) Other, net (3 153) (9 757) Net cash used for investing activities (174 948) (168 876) Financing Activities: Issuance of long-term debt 49 625 - Increase (decrease) in notes payable, net (73 100) 99 100 Retirement of long-term debt (9) (40 008) Capital lease principal payments (21 978) (25 745) Redemption of preferred stock (6 049) - Issuance of company-obligated mandatorily redeemable preferred securities 121 063 - Dividends paid on common stock (95 000) (100 000) Dividends paid on preferred stock (10 983) (11 096) Contributions from parent corporation 15 000 - Net cash required by financing activities (21 431) (77 749) Net increase (decrease) in cash and temporary cash investments from above activities 7 185 (16 348) Cash and temporary cash investments, beginning of year 1 041 17 301 Cash and temporary cash investments, end of period $ 8 226 $ 953 Supplemental Disclosure: Interest paid $ 78 411 $ 85 400 Income taxes paid $ 78 675 $ 25 482 New capital lease obligations incurred $ 11 377 $ 34 935 The accompanying notes are an integral part of the consolidated financial statements. -6-
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Jersey Central Power & Light Company (the Company), which was incorporated under the laws of New Jersey in 1925, is a wholly owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company owns all of the common stock of JCP&L Preferred Capital, Inc., which is the general partner of JCP&L Capital L.P., a special purpose finance subsidiary. The Company's business is the generation, transmission, distribution and sale of electricity. The Company is affiliated with Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec are referred to herein as the "Company and its affiliates". The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Company and its affiliates; and Energy Initiatives, Inc., EI Power, Inc., and EI Energy, Inc. (collectively, EI), which develop, own and operate generating, transmission and distribution facilities in the United States and in foreign countries. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN and EI are referred to as the "GPU System." These notes should be read in conjunction with the notes to financial statements included in the 1994 Annual Report on Form 10-K. The year-end condensed balance sheet data contained in the attached financial statements was derived from audited financial statements. For disclosures required by generally accepted accounting principles, see the 1994 Annual Report on Form 10-K. 1. COMMITMENTS AND CONTINGENCIES NUCLEAR FACILITIES The Company has made investments in three major nuclear projects--Three Mile Island Unit 1 (TMI-1) and Oyster Creek, both of which are operational generating facilities, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by the Company, Met-Ed and Penelec in the percentages of 25%, 50% and 25%, respectively. Oyster Creek is owned by the Company. At September 30, 1995 and December 31, 1994, the Company's net investment in TMI-1 and Oyster Creek, including nuclear fuel, was as follows: Net Investment (Millions) TMI-1 Oyster Creek September 30, 1995 $167 $778 December 31, 1994 $162 $817 The Company's net investment in TMI-2 at September 30, 1995 and December 31, 1994 was $86 million and $89 million, respectively. The Company is collecting retail revenues for TMI-2 on a basis which provides for the recovery of its remaining investment in the plant by 2008. Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs -7- associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at their nuclear plants because of the prevailing design criteria at the time of construction and the age of the plants' systems and equipment. In addition, for economic or other reasons, operation of these plants for the full term of their now- assumed lives cannot be assured. Also, not all risks associated with the ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the ability of electric utilities to obtain adequate and timely recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of each plant's useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured (see NUCLEAR PLANT RETIREMENT COSTS). Management intends, in general, to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured (see COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT). TMI-2: The 1979 TMI-2 accident resulted in significant damage to, and contamination of, the plant and a release of radioactivity to the environment. The cleanup program was completed in 1990, and after receiving Nuclear Regulatory Commission (NRC) approval, TMI-2 entered into long-term monitored storage in December 1993. As a result of the accident and its aftermath, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, have been asserted against GPU and the Company and its affiliates. Approximately 2,100 of such claims are pending in the United States District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Company and its affiliates had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for up to an aggregate of $335 million in premium charges under such plan, and (c) an indemnity agreement with the NRC for up to $85 million, bringing their total primary, secondary and tertiary financial protection up to an aggregate of $560 million. Under the secondary level, the Company and its affiliates are subject to a retrospective premium charge of up to $5 million per reactor, or a total of $15 million, of which the Company's share is $7.5 million. The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against GPU and the Company and its affiliates and their suppliers (the defendants) under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights with respect to any award of punitive damages. In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative -8- cases is scheduled to begin in June 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price- Anderson Act to the extent that the funds to pay punitive damages do not come out of the U.S. Treasury. In an order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against GPU and the Company and its affiliates; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding. In October 1995, the U.S. Court of Appeals for the Third Circuit ruled that the Price-Anderson Act provides coverage under its primary and secondary levels for punitive as well as compensatory damages, but that punitive damages could not be recovered against the Federal Government. In so doing, the Court of Appeals referred to the "finite fund" (the $560 million of financial protection under the Price-Anderson Act) to which plaintiffs must resort to get compensatory as well as punitive damages. The Court of Appeals also found that the standard of care owed by the defendants to a plaintiff was determined by the specific level of radiation which was released into the environment, as measured at the site boundary, rather than as measured at the specific site where the plaintiff was located at the time of the accident (as GPU and the Company and its affiliates proposed). The Court of Appeals also held, however, that each plaintiff still must demonstrate exposure to radiation released during the TMI-2 accident and that such exposure had resulted in injuries. GPU and the Company and its affiliates believe that any liability to which they might be subject by reason of the TMI-2 accident and these Court of Appeals decisions will not exceed the financial protection under the Price- Anderson Act. GPU and the Company and its affiliates have filed a petition with the Third Circuit Court seeking a rehearing and en banc reconsideration of its decision that punitive damages are recoverable under the Price-Anderson Act. NUCLEAR PLANT RETIREMENT COSTS Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE). In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for Oyster Creek and TMI-1 by the end of the plants' license terms, 2009 and 2014, respectively. The TMI-2 funding completion date is 2014, consistent with TMI-2's remaining in long-term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding targets (in 1995 dollars) for TMI-1 are $157 million, of which the Company's share is $39 million, and $189 million for Oyster Creek. Based on -9- NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials. In 1988, a consultant to GPUN performed site-specific studies of TMI-1 and Oyster Creek that considered various decommissioning plans and estimated the cost of decommissioning the radiological portions of each plant to range from approximately $225 million to $309 million, of which the Company's share would range from $56 million to $77 million, and $239 million to $350 million, respectively (in 1995 dollars). In addition, the studies estimated the cost of removal of nonradiological structures and materials for TMI-1 and Oyster Creek at $74 million, of which the Company's share is $18 million, and $48 million, respectively (in 1995 dollars). The ultimate cost of retiring the Company's and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies. Such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company and its affiliates charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1990 to TMI-2's external trust (see TMI-2 Future Costs). Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the Balance Sheet. In August 1995, a consultant to GPUN commenced site specific studies of the TMI site, including both Units 1 and 2, and Oyster Creek. GPUN expects these studies to be completed in the fourth quarter of 1995. The Financial Accounting Standards Board (FASB) is reviewing the utility industry's accounting practices for nuclear plant retirement costs. If the FASB's tentative conclusions are adopted, Oyster Creek and TMI-1 future retirement costs will have to be recognized as a liability currently, rather than recorded over the life of the plants (as is currently the practice), with an offsetting asset recorded for amounts collectible through rates. Any amounts not collectible through rates will have to be charged to expense. The FASB is expected to release an Exposure Draft on decommissioning accounting practices in the fourth quarter of 1995. -10- TMI-1 and Oyster Creek: The Company is collecting revenues for decommissioning, which are expected to result in the accumulation of its share of the NRC funding target for each plant. The Company is also collecting revenues, based on its share ($3.83 million) of an estimate of $15.3 million for TMI-1 and $31.6 million for Oyster Creek adopted in previous rate orders issued by the New Jersey Board of Public Utilities (NJBPU), for its share of the cost of removal of nonradiological structures and materials. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditure of these funds has been made in accumulated depreciation, amounting to $19 million for TMI-1 and $110 million for Oyster Creek at September 30, 1995. Oyster Creek and TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant. Management believes that any TMI-1 and Oyster Creek retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable under the current ratemaking process. TMI-2 Future Costs: The Company and its affiliates have recorded a liability for the radiological decommissioning of TMI-2, reflecting the NRC funding target (in 1995 dollars). The Company and its affiliates record escalations, when applicable, in the liability based upon changes in the NRC funding target. The Company and its affiliates have also recorded a liability for incremental costs specifically attributable to monitored storage. In addition, the Company and its affiliates have recorded a liability for the nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $3 million, of which the Company's share is $0.8 million, as of September 30, 1995. Estimated TMI-2 Future Costs as of September 30, 1995 and December 31, 1994 are as follows: September 30, 1995 December 31, 1994 (Millions) (Millions) Radiological Decommissioning $ 64 $ 63 Nonradiological Cost of Removal 18 18 Incremental Monitored Storage 5 5 Total $ 87 $ 86 The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the Balance Sheet. At September 30, 1995, $47 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the Balance Sheet, and $41 million was recoverable from customers and included in Three Mile Island Unit 2 Deferred Costs on the Balance Sheet. In 1990, the Company made a contribution of $15 million to an external decommissioning trust. This contribution was not recovered from customers and has been expensed. Earnings on trust fund deposits collected from customers are included in amounts shown on the Balance Sheet under Three Mile Island Unit 2 Deferred Costs. The NJBPU has granted the Company decommissioning revenues for the remainder of the NRC funding target and allowances for the cost of removal of nonradiological structures and materials. The Company intends to seek recovery for any increases in TMI-2 retirement costs, but recognizes that recovery cannot be assured. -11- As a result of TMI-2's entering long-term monitored storage in late 1993, the Company and its affiliates are incurring incremental annual storage costs of approximately $1 million, of which the Company's share is $.25 million. The Company and its affiliates estimate that the remaining annual storage costs will total $19 million, of which the Company's share is $5 million, through 2014, the expected retirement date of TMI-1. The Company's rates reflect its $5 million share of these costs. INSURANCE The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company. The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station and for Oyster Creek totals $2.7 billion per site. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station. The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors, subject to an annual maximum payment of $10 million per incident per reactor. In addition to the retrospective premiums payable under Price-Anderson, the GPU System is also subject to retrospective premium assessments of up to $69 million, of which the Company's share is $41 million, in any one year under insurance policies applicable to nuclear operations and facilities. The Company and its affiliates have insurance coverage for incremental replacement power costs resulting from an accident-related outage at its nuclear plants. Coverage commences after the first 21 weeks of the outage and continues for three years beginning at $1.8 million for Oyster Creek and $2.6 million for TMI-1 per week for the first year, decreasing to 80 percent of such amounts for years two and three. -12- COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT Nonutility Generation Agreements: Pursuant to the requirements of the federal Public Utility Regulatory Policies Act (PURPA) and state regulatory directives, the Company has entered into power purchase agreements with nonutility generators for the purchase of energy and capacity for periods up to 25 years. The majority of these agreements contain certain contract limitations and subject the nonutility generators to penalties for nonperformance. While some of these facilities are dispatchable, most are must-run and generally obligate the Company to purchase, at the contract price, the net output up to the contract limits. As of September 30, 1995, facilities covered by these agreements having 892 MW of capacity were in service. Estimated payments to nonutility generators from 1995 through 1999, assuming that all facilities which have existing agreements, or which have obtained orders granting them agreements, enter service, are $380 million, $358 million, $389 million, $419 million, and $431 million, respectively. These agreements, in the aggregate, will provide approximately 1,002 MW of capacity and energy to the Company, at varying prices. The emerging competitive generation market has created uncertainty regarding the forecasting of the GPU System's energy supply needs which has caused the Company and its affiliates to change their supply strategy to seek shorter-term agreements offering more flexibility. Due to the current availability of excess capacity in the marketplace, the cost of near- to intermediate-term (i.e., one to eight years) energy supply from existing generation facilities is currently and expected to continue to be competitively priced at least for the near- to intermediate-term. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and reduced forecasted fuel prices. As a result of these developments, the rates under virtually all of the Company's and its affiliates' nonutility generation agreements are substantially in excess of current and projected prices from alternative sources. The Company and its affiliates are seeking to reduce the above market costs of these nonutility generation agreements by (1) attempting to convert must-run agreements to dispatchable agreements; (2) attempting to renegotiate prices of the agreements; (3) offering contract buy-outs while seeking to recover the costs through their energy clauses (see Managing Nonutility Generation, in Management's Discussion and Analysis of Financial Condition and Results of Operations) and (4) initiating proceedings before federal and state administrative agencies, and in the courts, where appropriate. In addition, the Company and its affiliates intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. These efforts may result in claims against the GPU System for substantial damages. There can, however, be no assurance as to what extent the Company's and its affiliates' efforts will be successful in whole or in part. While the Company and its affiliates thus far have been granted recovery of their nonutility generation costs from customers by the NJBPU and the Pennsylvania Public Utility Commission (PaPUC), there can be no assurance that the Company and its affiliates will continue to be able to recover these costs -13- throughout the term of the related agreements. The GPU System currently estimates that in 1998, when substantially all of these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $240 million to $350 million annually, of which the Company's share will range from $100 million and $150 million annually. Regulatory Assets and Liabilities: As a result of the Energy Policy Act of 1992 (Energy Act) and actions of regulatory commissions, the electric utility industry is moving toward a combination of competition and a modified regulatory environment. In accordance with Statement of Financial Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under FAS 71 requires that the following criteria be met: a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator; b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criteria requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs. A utility's operations can cease to meet those criteria for various reasons, including deregulation, a change in the method of regulation, or a change in the competitive environment for the utility's regulated services. Regardless of the reason, a utility whose operations cease to meet those criteria should discontinue application of FAS 71 and report that discontinuation by eliminating from its Balance Sheet the effects of any actions of regulators that had been recognized as assets and liabilities pursuant to FAS 71 but which would not have been recognized as assets and liabilities by enterprises in general. If a portion of the Company's operations continues to be regulated and meets the above criteria, FAS 71 accounting may only be applied to that portion. Write-offs of utility plant and regulatory assets may result for those operations that no longer meet the requirements of FAS 71. In addition, under deregulation, the uneconomical costs of certain contractual commitments for purchased power and/or fuel supplies may have to be expensed currently. Management believes that to the extent that the Company no longer qualifies for FAS 71 accounting treatment, a material adverse effect on its results of operations and financial position may result. In accordance with the provisions of FAS 71, the Company has deferred certain costs pursuant to actions of the NJBPU and Federal Energy Regulatory Commission (FERC) and are recovering or expects to recover such costs in -14- electric rates charged to customers. Regulatory assets are reflected in the Deferred Debits and Other Assets section of the Consolidated Balance Sheet, and regulatory liabilities are reflected in the Deferred Credits and Other Liabilities section of the Consolidated Balance Sheet. Regulatory assets and liabilities, as reflected in the September 30, 1995 Consolidated Balance Sheet, were as follows: (In thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $ 143,900 $ 37,303 TMI-2 deferred costs 126,831 - Unamortized property losses 101,064 - NUG contract termination costs 16,400 - Other postretirement benefits 30,629 - N.J. unit tax 52,864 - Unamortized loss on reacquired debt 34,997 - Load and demand side management programs 47,643 - DOE enrichment facility decommissioning 25,529 - Manufactured gas plant remediation 30,720 - Storm damage 23,876 - Nuclear fuel disposal fee 24,117 - N.J. low-level radwaste disposal 15,572 - Oyster Creek deferred costs 8,084 - Other 2,102 1,676 Total $ 684,328 $ 38,979 Income taxes recoverable/refundable through future rates: Represents amounts deferred due to the implementation of FAS 109, "Accounting for Income Taxes", in 1993. TMI-2 deferred costs: Represents costs that are recoverable through rates for the Company's remaining investment in the plant and fuel core, radiological decommissioning in accordance with the NRC's funding target and allowances for the cost of removal of nonradiological structures and materials, and long-term monitored storage costs. For additional information, see TMI-2 Future Costs. Unamortized property losses: Consists mainly of costs associated with the Company's Forked River Project, which are included in rates. NUG contract termination costs: Represents one-time costs incurred for terminating power purchase contracts with nonutility generators (NUGs), for which rate recovery is probable (See Managing Nonutility Generation, in Management's Discussion and Analysis of Financial Condition and Results of Operations). Other postretirement benefits: Includes costs associated with the adoption of FAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", which are deferred in accordance with Emerging Issues Task Force Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises". N.J. unit tax: The Company received NJBPU approval in 1993 to recover, with interest, over a ten-year period on an annuity basis, $71.8 million of Gross Receipts and Franchise Tax not previously recovered from customers. -15- Unamortized loss on reacquired debt: Represents premiums and expenses incurred in the early redemption of long-term debt. In accordance with FERC regulations, reacquired debt costs are amortized over the remaining original life of the retired debt. Load and demand side management (DSM) programs: Consists of load management costs that are currently being recovered, with interest, through the Company's retail base rates pursuant to a 1993 NJBPU order, and other DSM program expenditures that are recovered annually. Also includes provisions for lost revenues between base rate cases and performance incentives. DOE enrichment facility decommissioning: These costs, representing payments to the DOE over a 15-year period beginning in 1994, are currently being collected through the Company's energy adjustment clause. Manufactured gas plant remediation: Consists of costs being recovered associated with the investigation and remediation of several gas manufacturing plants. For additional information, see ENVIRONMENTAL MATTERS. Storm damage: Relates to noncapital costs associated with various storms in the Company's service territory that are not recoverable through insurance. These amounts were deferred based upon past rate recovery precedent. An annual amount for recovery of storm damage expense is included in the Company's retail base rates. Nuclear fuel disposal fee: Represents amounts recoverable through rates for estimated future disposal costs for spent nuclear fuel at Oyster Creek and TMI-1 in accordance with the Nuclear Waste Policy Act of 1982. N.J. low-level radwaste disposal: Represents the accrual of the estimated assessment for a disposal facility for low-level waste from Oyster Creek, less amortization as allowed in the Company's rates. Oyster Creek deferred costs: Consists of replacement power and O&M costs deferred in accordance with orders from the NJBPU. The Company has been granted recovery of these costs through rates at an annual amount until fully amortized. Amounts related to the decommissioning of TMI-1 and Oyster Creek, which are not included in Regulatory Assets on the Balance Sheet, are separately disclosed in NUCLEAR PLANT RETIREMENT COSTS. The Company continues to be subject to cost-based ratemaking regulation. The Company is unable to estimate to what extent FAS 71 may no longer be applicable to its utility assets in the future. ENVIRONMENTAL MATTERS As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, the Company may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or clean up waste disposal and other sites currently -16- or formerly used by it, including formerly owned manufactured gas plants, mine refuse piles and generating facilities, and with regard to electromagnetic fields, postpone or cancel the installation of, or replace or modify, utility plant, the costs of which could be material. To comply with the federal Clean Air Act Amendments (Clean Air Act) of 1990, the Company expects to spend up to $58 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the Company will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. The Company has been notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 6 hazardous and/or toxic waste sites. In addition, the Company has been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The Company has also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Company. The Company has entered into agreements with the New Jersey Department of Environmental Protection for the investigation and remediation of 17 formerly owned manufactured gas plant sites. The Company has also entered into various cost-sharing agreements with other utilities for most of the sites. As of September 30, 1995, the Company has an estimated environmental liability of $32 million recorded on its Balance Sheet relating to these sites. The estimated liability is based upon ongoing site investigations and remediation efforts, including capping the sites and pumping and treatment of ground water. If the periods over which the remediation is currently expected to be performed are lengthened, the Company believes that it is reasonably possible that the ultimate costs may range as high as $60 million. Estimates of these costs are subject to significant uncertainties because the Company does not presently own or control most of these sites; the environmental standards have changed in the past and are subject to future change; the accepted technologies are subject to further development; and the related costs for these technologies are uncertain. If the Company is required to utilize different remediation methods, the costs could be materially in excess of $60 million. In 1993, the NJBPU approved a mechanism similar to the Company's Levelized Energy Adjustment Clause (LEAC) for the recovery of future manufactured gas plant remediation costs when expenditures exceed prior collections. The NJBPU decision also provided for interest on any overrecovery to be credited to customers until the overrecovery is eliminated and for future costs to be amortized over seven years with interest. A final 1994 NJBPU order indicated that interest is to be accrued retroactive to June 1993. The Company is pursuing reimbursement of the remediation costs from its insurance carriers. In 1994, the Company filed a complaint with the Superior Court of New Jersey against several of its insurance carriers, relative to these manufactured gas plant sites. The Company requested the Court to order -17- the insurance carriers to reimburse it for all amounts it has paid, or may be required to pay, in connection with the remediation of the sites. Pretrial discovery has begun in this case. The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant. OTHER COMMITMENTS AND CONTINGENCIES The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $226 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured. The Company has entered into a long-term contract with a nonaffiliated mining company for the purchase of coal for the Keystone generating station in which the Company has a one-sixth ownership interest. This contract, which expires in 2004, requires the purchase of minimum amounts of the station's coal requirements. The price of the coal under the contract is based on adjustments of indexed cost components. The Company's share of the cost of coal purchased under this agreement is expected to aggregate $23 million for 1995. The Company and its affiliates have entered into agreements with other utilities to purchase capacity and energy for various periods through 2004. These agreements will provide for up to 1,308 MW in 1995, declining to 1,096 MW in 1997 and 696 MW by 2004. For the years 1995 through 1999, the Company's share of payments pursuant to these agreements are estimated to aggregate $202 million, $175 million, $162 million, $145 million, and $128 million, respectively. The Company has commenced construction of a 141 MW gas-fired combustion turbine at its Gilbert generating station. The new facility, coupled with the retirement of two older units, will result in a net capacity increase of approximately 95 MW. This estimated $50 million project (of which $32 million has already been spent) is expected to be in-service by mid-1996. In February 1995, the NJDEP issued an air permit for the facility based, in part, on the NJBPU's December 1994 order which found that New Jersey's Electric Facility Need Assessment Act is not applicable to this combustion turbine and that construction of this facility, without a market test, is consistent with New Jersey energy policies. An industry trade group representing nonutility generators has appealed the NJDEP's issuance of the air permit and the NJBPU's order to the Appellate Division of the New Jersey Superior Court. The Company has moved to dismiss the appeal. There can be no assurance as to the outcome of this proceeding. -18- The NJBPU has instituted a generic proceeding to address the appropriate recovery of capacity costs associated with electric utility power purchases from nonutility generation projects. The proceeding was initiated, in part, to respond to contentions of the Division of the Ratepayer Advocate (Ratepayer Advocate), that by permitting utilities to recover such costs through the LEAC, an excess or "double" recovery may result when combined with the recovery of the utilities' embedded capacity costs through their base rates. In 1994, the NJBPU ruled that the 1991 LEAC period was considered closed but subsequent LEAC periods remain open for further investigation. This matter is pending before a NJBPU Administrative Law Judge. The Company estimates that the potential refund liability from the 1992 LEAC period through February 1996, the end of the current LEAC period, is $56 million. There can be no assurance as to the outcome of this proceeding. The Company's two operating nuclear units are subject to the NJBPU's annual nuclear performance standard. Operation of these units at an aggregate annual generating capacity factor below 65% or above 75% would trigger a charge or credit based on replacement energy costs. At current cost levels, the maximum annual effect on net income of the performance standard charge at a 40% capacity factor would be approximately $11 million before tax. While a capacity factor below 40% would generate no specific monetary charge, it would require the issue to be brought before the NJBPU for review. The annual measurement period, which begins in March of each year, coincides with that used for the LEAC. 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 and punitive damages are sought by the public, customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. While management does not expect that the outcome of these matters will have a material effect on the Company's financial position or results of operations, there can be no assurance that this will continue to be the case. -19- Jersey Central Power & Light Company and Subsidiary Company Management's Discussion and Analysis of Financial Condition and Results of Operations The following is management's discussion of significant factors that affected the Company's interim financial condition and results of operations. This should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations included in the Company's 1994 Annual Report on Form 10-K. RESULTS OF OPERATIONS Earnings for the third quarter of 1995 were $91.9 million, compared to $70.9 million for the same period ended 1994. The increase in third quarter earnings was due primarily to lower operation and maintenance expense (O&M), higher sales resulting from hotter summer temperatures compared to last year, and new residential and commercial customer growth. For the nine months ended September 30, 1995, earnings were $157.6 million, compared to $121.7 million for the same period last year. The same factors affecting the quarterly results also affected the results for the nine month period. In addition, the increase in earnings for the nine month period was due primarily to a one-time charge of $30.4 million (after-tax) resulting from early retirement programs offered in 1994, and lower O&M expense, which included payroll and benefit savings from the early retirement programs. These increases for the nine month period were partially offset by lower sales due to warmer winter and cooler spring weather, and one-time net interest income in 1994 of $7.4 million (after-tax) resulting from refunds of previously paid federal income taxes related to the tax retirement of TMI-2. OPERATING REVENUES: Total revenues for the third quarter of 1995 increased 10.2% to $625.5 million, as compared to the third quarter of 1994. For the nine months ended September 30, 1995 revenues increased 2.2% to $1.5 billion, as compared to the same period last year. The components of the changes are as follows: (In Millions) Three Months Nine Months Ended Ended September 30, 1995 September 30, 1995 Kilowatt-hour (KWH) revenues (excluding energy portion) $ 22.1 $ (3.2) Energy revenues 33.8 39.1 Other revenues 1.8 (2.9) Increase in revenues $ 57.7 $ 33.0 Kilowatt-hour revenues The increase in KWH revenues for the three month period was due primarily to higher sales from hotter summer temperatures in 1995, and new customer additions in the residential and commercial sectors. The decrease in KWH -20- revenues for the nine month period was due to lower residential sales from milder winter and cooler spring weather in 1995. Energy revenues Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues increased in both the three and nine month periods primarily from higher energy cost rates and increased sales to other utilities. The nine month period increase was partially offset by lower sales to customers. Other revenues Generally, changes in other revenues do not affect earnings as they are offset by corresponding changes in expense, such as taxes other than income taxes. OPERATING EXPENSES: Power purchased and interchanged Generally, changes in the energy component of power purchased and interchanged expense do not significantly affect earnings since these cost increases are substantially recovered through the Company's energy clause. However, earnings for the nine month period were negatively impacted by higher reserve capacity expense resulting primarily from a 1995 Pennsylvania-New Jersey-Maryland Interconnection (PJM) prior year adjustment, and one-time net charges of $3.6 million (pre-tax) from another utility. Fuel and Deferral of energy and capacity costs, net Generally, changes in fuel expense and deferral of energy and capacity costs do not affect earnings as they are offset by corresponding changes in energy revenues. However, first quarter 1994 earnings benefitted from the recognition of a performance award for the efficient operation of the Company's nuclear generating stations. Other operation and maintenance The decrease in other O&M expense for the three month period was primarily attributable to lower storm activity than in the third quarter of 1994, and lower nuclear expenses due to a refueling outage occurring at Oyster Creek during the third quarter of 1994. The decrease in other O&M expense for the nine month period was primarily attributable to a one-time $46.9 million (pre-tax) charge in 1994 related to the early retirement programs. Also contributing to the nine month O&M reduction were payroll and benefits savings from the early retirement programs, and lower 1995 winter storm repair costs. Depreciation and Amortization The increase in depreciation and amortization expense for the nine month period was due primarily to additions to plant in service, partially offset by lower amortization of regulatory assets. -21- Taxes, other than income taxes Generally, changes in taxes other than income taxes do not significantly affect earnings as they are substantially recovered in revenues. OTHER INCOME AND DEDUCTIONS: Other income, net The decrease in other income for the nine month period was primarily attributable to lower interest income of $14.7 million (pre-tax) resulting from 1994 refunds of previously paid federal income taxes related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. INTEREST CHARGES AND DIVIDENDS ON PREFERRED SECURITIES: Other interest Other interest expense for the nine month period decreased primarily from the recognition in the first quarter of 1994 of interest expense related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a $3.3 million (pre-tax) charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken. Dividends on subsidiary-obligated mandatorily redeemable preferred securities In the second quarter of 1995, the Company issued $125 million of monthly income preferred securities through a special-purpose finance subsidiary. Dividends on these securities are payable monthly. LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS: The Company's capital needs for the nine months ended September 30, 1995 consisted of cash construction expenditures of $158 million. Construction expenditures for the year are forecasted to be $226 million. Expenditures for securities maturing in 1995 will total $47 million. Management estimates that approximately two-thirds of the capital needs in 1995 will be satisfied through internally generated funds. FINANCING: GPU has regulatory authority to issue up to four million shares of additional common stock through 1996. GPU expects to use the proceeds from any sale of additional common stock to reduce GPU short-term debt and make capital contributions to the Company and its affiliates, and EI. The Company has regulatory authority to issue and sell first mortgage bonds (FMBs), which may be issued as secured medium-term notes, and preferred stock through June 1997. Under existing authorizations, the Company may issue such senior securities in the amount of $225 million, of which $100 million -22- 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. On November 1, 1995, the Company redeemed, at maturity, $17.4 million principal amount of FMBs. 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 dividend coverage ratios are currently in excess of indenture and charter restrictions. COMPETITIVE ENVIRONMENT: In September 1995, the Federal Energy Regulatory Commission (FERC) accepted for filing, subject to possible refund, the Company's proposed open access transmission tariffs. The tariffs were submitted to the FERC in March 1995, prior to the FERC's issuance of the Notice of Proposed Rulemaking on open access non-discriminatory transmission services. The FERC has ordered that hearings be held on a number of aspects of these tariffs, including whether they are consistent in certain respects with FERC policy on open access and comparability of service. The tariffs provide for both firm and interruptible service on a point-to-point basis. Network service, where requested, will be negotiated on a case by case basis. In August 1995, the New Jersey Board of Public Utilities (NJBPU) initiated Phase II of the Energy Master Plan on industry restructuring. The NJBPU Phase II Report, which is expected to address such items as retail and wholesale competition and divestiture of utility assets, is scheduled for release in March 1996. THE SUPPLY PLAN: Managing Nonutility Generation The Company and its affiliates are seeking to reduce the above market costs of nonutility generation agreements, including (1) attempting to convert must-run agreements to dispatchable agreements; (2) attempting to renegotiate prices of the agreements; (3) offering contract buy-outs while seeking to recover the costs through their energy clauses and (4) initiating proceedings before federal and state administrative agencies, and in the courts, where appropriate. In addition, the Company and its affiliates intend to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing, and are supporting legislative efforts to repeal the Public Utility Regulatory Policies Act of 1978 (PURPA). These efforts may result in claims against the Company and its affiliates for substantial damages. There can, however, be no assurance as to what extent the Company's and its affiliates' efforts will be successful in whole or in part. The following is a discussion of some major nonutility generation activities involving the Company. -23- In March 1995, the U.S. Court of Appeals denied petitions for rehearing filed by the Company, the NJBPU, and the New Jersey Division of Ratepayer Advocate, asking that the Court reconsider its January 1995 decision prohibiting the NJBPU from reexamining its order approving the rates payable to Freehold Cogeneration Associates under a long-term power purchase agreement entered into pursuant to PURPA. On October 5, 1995 the U. S. Supreme Court denied petitions for review, filed by the Company and the Ratepayer Advocate. The Company also petitioned the FERC to declare the agreement unlawful on the grounds that when it was approved by the NJBPU, the contract pricing violated PURPA, in that it requires the Company to purchase power at costs that were above its then avoided costs. On October 11, 1995, the FERC denied the Company's petition to void the agreement. The Company intends to seek rehearing by the FERC, and may pursue the case in federal court. In 1994, a nonutility generator requested that the NJBPU order the Company to enter into a long-term agreement to buy capacity and energy. The Company contested the request, and the NJBPU referred the matter to an Administrative Law Judge (ALJ) for hearings. In February 1995, the ALJ issued an initial decision stating that the nonutility generator had created a legally enforceable obligation, but the appropriate avoided cost to be used was still to be decided by the NJBPU. However, in April 1995, the NJBPU remanded the proceeding to the ALJ for fact finding. In October 1995, at the request of the nonutility generator, the NJBPU entered an order dismissing the petition. In May 1995, the Appellate Division of the New Jersey Superior Court reversed NJBPU orders granting the developers of the Crown/Vista project in- service date extensions for their proposed 200 MW coal-fired facilities. In June 1995, the New Jersey Assembly passed a bill which, if enacted, would have the effect of nullifying the Court's decision by retroactively extending the in-service deadlines on the project for three years. In August 1995, the developers entered into a buy-out agreement under which the Company has purchased and terminated the agreements for $17 million. The Company intends to file with the NJBPU for recovery of the costs through the levelized energy adjustment clause. In August 1995, the Company and its affiliates entered into a three-year fuel management agreement with New Jersey Natural Energy Corporation, an affiliate of New Jersey Natural Gas Company, to manage the Company's and its affiliates' natural gas purchases and interstate pipeline capacity. It is intended that the Company's and its affiliates' gas-fired facilities, as well as up to approximately 1,100 MW of nonutility generation capacity, will be pooled and managed under this agreement, allowing the Company and its affiliates to reduce power purchase expenses. The Company has contracts and anticipated commitments with nonutility generation suppliers under which a total of 892 MW of capacity are currently in service and an additional 110 MW are currently scheduled or anticipated to be in service by 1999. -24- PART II ITEM 1 - LEGAL PROCEEDINGS Information concerning the current status of certain legal proceedings instituted against the Company and its affiliates as a result of the March 28, 1979 nuclear accident at Unit 2 of the Three Mile Island nuclear generating station discussed in Part I of this report in Notes to Consolidated Financial Statements is incorporated herein by reference and made a part hereof. ITEM 5 - OTHER EVENTS Management believes that the Oyster Creek nuclear station will require additional on-site storage capacity, beginning in 1996, in order to maintain its full core reserve margin, i.e. its ability, when necessary, to off-load the entire core to conduct certain maintenance or repairs in order to restore operation of the plant. In 1994, the Lacey Township Zoning Board of Adjustment issued a use variance for the on-site storage facility, but Berkeley Township and another party appealed to the New Jersey Superior Court to overturn the decision. The Superior Court then remanded the variance application to the Board of Adjustment for the limited purpose of permitting the plaintiffs to present expert testimony. In August 1995, the Board of Adjustment ruled in favor of the Company and reaffirmed its 1994 decision granting the Company the use variance. Construction of the facility is continuing, and is expected to be completed by early 1996. ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits (27) Financial Data Schedule (b) Reports on Form 8-K: For the month of October 1995, dated October 4, 1995, under Item 5 (Other Events) For the month of October 1995, dated October 20, 1995, under Item 5 (Other Events), as amended by Form 8-K/A No. 1, dated October 27, 1995 -25- Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. JERSEY CENTRAL POWER & LIGHT COMPANY November 8, 1995 By: /s/ D. Baldassari D. Baldassari, President November 8, 1995 By: /s/ D. W. Myers D. W. Myers, Vice President - Operations Support and Comptroller (Principal Accounting Officer) -26- EX-12 2 EXHIBIT 12 JCP&L Exhibit 12 Page 1 of 2 JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503 (In Thousands) UNAUDITED
Nine Months Ended September 30, 1995 September 30, 1994 OPERATING REVENUES $1 546 594 $1 513 634 OPERATING EXPENSES 1 228 111 1 254 597 Interest portion of rentals (A) 9 385 8 284 Net expense 1 218 726 1 246 313 OTHER INCOME: Allowance for funds used during construction 4 554 2 233 Other income, net 10 713 23 154 Total other income 15 267 25 387 EARNINGS AVAILABLE FOR FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (excluding taxes based on income) $ 343 135 $ 292 708 FIXED CHARGES: Interest on funded indebtedness $ 69 421 $ 70 981 Other interest (B) 11 637 12 011 Interest portion of rentals (A) 9 385 8 284 Total fixed charges $ 90 443 $ 91 276 RATIO OF EARNINGS TO FIXED CHARGES 3.79 3.21 Preferred stock dividend requirement 10 871 11 096 Ratio of income before provision for income taxes to net income (C) 150.0% 151.6% Preferred stock dividend requirement on a pre-tax basis 16 306 16 822 Fixed charges, as above 90 443 91 276 Total fixed charges and preferred stock dividends $ 106 749 $ 108 098 RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS 3.21 2.71
Exhibit 12 Page 2 of 2 JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARY COMPANY STATEMENTS SHOWING COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS BASED ON SEC REGULATION S-K, ITEM 503 (In Thousands) UNAUDITED NOTES: (A) The Company has included the equivalent of the interest portion of all rentals charged to income as fixed charges for this statement and has excluded such components from Operating Expenses. (B) Includes dividends on company-obligated mandatorily redeemable preferred securities of $3,953 for the nine months ended September 30, 1995 only. (C) Represents income before provision for income taxes of $252,692 and $201,432, for the nine months ended September 30, 1995 and September 30, 1994, respectively, divided by net income of $168,454 and $132,845, respectively. EX-27 3 EXHIBIT 27J
UT 0000053456 JERSEY CENTRAL POWER & LIGHT COMPANY 1,000 US DOLLARS 9-MOS DEC-31-1995 JAN-01-1995 SEP-30-1995 1 PER-BOOK 2,894,180 308,126 465,191 829,300 0 4,496,797 153,713 450,769 834,721 1,439,203 259,000 37,741 1,192,890 13,600 0 23,781 73,140 10,000 2,849 90,607 1,353,986 4,496,797 1,546,594 79,965 1,228,111 1,308,076 238,518 7,296 245,814 77,360 168,454 10,871 157,583 95,000 91,917 203,564 0 0 INCLUDES COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF $125,000. INCLUDES DIVIDENDS ON COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF $3,953. REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
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