-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, GtPxiu1eXS8Dl/s15BI2m8M/AT5NiSlvGtE0ENStYLrzeTqWZ3Eyc4gcsyWuo27y eeBHiGvAP4LrMMiUG87w2g== 0000065350-95-000004.txt : 19950508 0000065350-95-000004.hdr.sgml : 19950508 ACCESSION NUMBER: 0000065350-95-000004 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19950331 FILED AS OF DATE: 19950505 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: METROPOLITAN EDISON CO CENTRAL INDEX KEY: 0000065350 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 230870160 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-00446 FILM NUMBER: 95534804 BUSINESS ADDRESS: STREET 1: 2800 POTTSVILLE PIKE STREET 2: MUHLENBERG TOWNSHIP CITY: BERKS COUNTY STATE: PA ZIP: 19605 BUSINESS PHONE: 2159293601 10-Q 1 ME 10Q WITH FDS, 95 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 March 31, 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 1-446 Metropolitan Edison Company (Exact name of registrant as specified in its charter) Pennsylvania 23-0870160 (State or other jurisdiction of (I.R.S. Employer) incorporation or organization) Identification No.) 2800 Pottsville Pike Reading, Pennsylvania 19605 (Address of principal executive offices) (Zip Code) (610) 929-3601 (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 voting stock, as of April 30, 1995, was as follows: Common stock, no par value: 859,500 shares outstanding. Metropolitan Edison Company Quarterly Report on Form 10-Q March 31, 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 18 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- METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES Consolidated Balance Sheets In Thousands March 31, December 31, 1995 1994 (Unaudited) ASSETS Utility Plant: In service, at original cost $2 157 914 $2 137 996 Less, accumulated depreciation 720 249 700 746 Net utility plant in service 1 437 665 1 437 250 Construction work in progress 109 267 105 035 Other, net 35 426 37 275 Net utility plant 1 582 358 1 579 560 Other Property and Investments: Nuclear decommissioning trusts 71 751 65 100 Other, net 9 578 9 567 Total other property and investments 81 329 74 667 Current Assets: Cash and temporary cash investments 1 717 9 246 Special deposits 1 121 1 896 Accounts receivable: Customers, net 55 711 53 421 Other 21 288 16 736 Unbilled revenues 20 694 25 112 Materials and supplies, at average cost or less: Construction and maintenance 40 939 39 365 Fuel 13 311 16 843 Deferred income taxes 4 245 4 720 Prepayments 24 275 7 522 Total current assets 183 301 174 861 Deferred Debits and Other Assets: Regulatory assets: Three Mile Island Unit 2 deferred costs 5 431 5 534 Income taxes recoverable through future rates 206 479 201 679 Other 42 526 41 668 Total regulatory assets 254 436 248 881 Deferred income taxes 148 881 149 892 Other 11 980 8 418 Total deferred debits and other assets 415 297 407 191 Total Assets $2 262 285 $2 236 279 The accompanying notes are an integral part of the consolidated financial statements. -3- METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES Consolidated Balance Sheets In Thousands March 31, December 31, 1995 1994 (Unaudited) LIABILITIES AND CAPITAL Capitalization: Common stock $ 66 273 $ 66 273 Capital surplus 345 200 341 616 Retained earnings 168 157 190 742 Total common stockholder's equity 579 630 598 631 Cumulative preferred stock 23 598 23 598 Preferred securities of subsidiary 100 000 100 000 Long-term debt 559 784 529 783 Total capitalization 1 263 012 1 252 012 Current Liabilities: Debt due within one year 40 517 40 517 Notes payable 57 421 - Obligations under capital leases 32 185 33 810 Accounts payable: Affiliates 8 057 14 571 Other 81 087 96 061 Taxes accrued 19 710 40 435 Deferred energy credits 827 1 950 Interest accrued 10 553 19 006 Other 22 561 21 636 Total current liabilities 272 918 267 986 Deferred Credits and Other Liabilities: Deferred income taxes 379 996 371 841 Unamortized investment tax credits 35 024 35 470 Three Mile Island Unit 2 future costs 172 281 170 593 Nuclear fuel disposal fee 26 221 25 836 Regulatory liabilities 33 494 37 534 Other 79 339 75 007 Total deferred credits and other liabilities 726 355 716 281 Commitments and Contingencies (Note 1) Total Liabilities and Capital $2 262 285 $2 236 279 The accompanying notes are an integral part of the consolidated financial statements. -4- METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES Consolidated Statements of Income (Unaudited) In Thousands Three Months Ended March 31, 1995 1994 Operating Revenues $205 749 $213 159 Operating Expenses: Fuel 22 392 26 964 Power purchased and interchanged: Affiliates 8 958 4 860 Others 43 514 45 477 Deferral of energy costs, net (1 105) (8 401) Other operation and maintenance 52 641 53 837 Depreciation and amortization 22 670 21 534 Taxes, other than income taxes 13 659 14 967 Total operating expenses 162 729 159 238 Operating Income Before Income Taxes 43 020 53 921 Income taxes 11 865 14 007 Operating Income 31 155 39 914 Other Income and Deductions: Allowance for other funds used during construction 455 174 Other income/(expense), net (2 161) 30 194 Income taxes 791 (12 672) Total other income and deductions (915) 17 696 Income Before Interest Charges and Dividends on Preferred Securities 30 240 57 610 Interest Charges and Dividends on on Preferred Securities: Interest on long-term debt 11 012 10 718 Other interest 989 9 496 Allowance for other funds used during construction (395) (406) Dividends on preferred securities of subsidiary 2 250 - Total interest charges and dividends on preferred securities 13 856 19 808 Net Income 16 384 37 802 Preferred stock dividends 236 908 Earnings Available for Common Stock $ 16 148 $ 36 894 The accompanying notes are an integral part of the consolidated financial statements. -5- -6- METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows (Unaudited) In Thousands Three Months Ended March 31, 1995 1994 Operating Activities: Income before preferred stock dividends $ 16 384 $ 37 802 Adjustments to reconcile income to cash provided: Depreciation and amortization 20 075 20 309 Amortization of property under capital leases 3 795 3 450 Nuclear outage maintenance costs, net 1 638 1 570 Deferred income taxes and investment tax credits, net (139) 11 388 Deferred energy costs, net (1 105) (8 401) Accretion income - (334) Allowance for other funds used during construction (455) (174) Changes in working capital: Receivables (2 424) (36 103) Materials and supplies 1 958 6 909 Special deposits and prepayments (16 758) (20 621) Payables and accrued liabilities (36 543) 1 568 Other, net 3 501 (5 068) Net cash provided (required) by operating activities (10 073) 12 295 Investing Activities: Cash construction expenditures (37 999) (30 421) Contributions to decommissioning trusts (2,550) (2 939) Other, net 41 40 Net cash used for investing activities (40 508) (33 320) Financing Activities: Issuance of long-term debt 29 820 49 687 Increase in notes payable, net 57 300 2 662 Retirement of long-term debt - (26 000) Capital lease principal payments (3 832) (4 276) Dividends paid on common stock (40 000) - Dividends paid on preferred stock (236) ( 908) Net cash provided by financing activities 43 052 21 165 Net increase (decrease) in cash and temporary cash investments from above activities (7 529) 140 Cash and temporary cash investments, beginning of period 9 246 938 Cash and temporary cash investments, end of period $ 1 717 $ 1 078 Supplemental Disclosure: Interest paid (net of amount capitalized) $ 24 329 $ 20 487 Income taxes paid $ 29 344 $ 4 606 New capital lease obligations incurred $ 1 858 $ 2 655 The accompanying notes are an integral part of the consolidated financial statements. -7- METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Metropolitan Edison Company (the Company), a Pennsylvania corporation incorporated in 1922, is a wholly-owned subsidiary of General Public Utilities Corporation (GPU), a holding company registered under the Public Utility Holding Company Act of 1935. The Company owns all of the common stock of York Haven Power Company, the owner of a small hydroelectric generating station, and Met-Ed Preferred Capital, Inc., which is the general partner of Met-Ed Capital L.P., a special purpose finance subsidiary. The Company's business is the generation, transmission, distribution and sale of electricity. The Company is affiliated with Jersey Central Power & Light Company (JCP&L) and Pennsylvania Electric Company (Penelec). The Company, JCP&L and Penelec are referred to herein as "the Company and its affiliates." The Company is also affiliated with GPU Service Corporation (GPUSC), a service company; GPU Nuclear Corporation (GPUN), which operates and maintains the nuclear units of the Subsidiaries; and Energy Initiatives, Inc. (EI) and EI Power, Inc., which develop, own and operate nonutility generating facilities. All of the Company's affiliates are wholly owned subsidiaries of GPU. The Company and its affiliates, GPUSC, GPUN, EI and EI Power, Inc. are referred to as the "GPU System". These notes should be read in conjunction with the notes to consolidated 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 were 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 two major nuclear projects--Three Mile Island Unit 1 (TMI-1), which is an operational generating facility, and Three Mile Island Unit 2 (TMI-2), which was damaged during a 1979 accident. TMI-1 and TMI-2 are jointly owned by the Company, JCP&L and Penelec in the percentages of 50%, 25% and 25%, respectively. At March 31, 1995 and December 31, 1994, the Company's net investment in TMI-1 and TMI-2, including nuclear fuel, was as follows: Net Investment (Millions) TMI-1 TMI-2 March 31, 1995 $307 $6 December 31, 1994 $311 $6 Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards and experience gained in the construction and operation of nuclear facilities. The Company and its affiliates may also incur costs and experience reduced output at its nuclear plants because of the prevailing design criteria at the time of construction -8- 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. If, notwithstanding the developments noted below, punitive damages are not covered by insurance and are not subject to the liability limitations of the federal Price-Anderson Act ($560 million at the time of the accident), punitive damage awards could have a material adverse effect on the financial position of the GPU System. At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the Company and its affiliates had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for premium charges deferred in whole or in major part under such plan, and (c) an indemnity agreement with the NRC, bringing their total primary and secondary insurance financial protection and indemnity agreement with the NRC up to an aggregate of $560 million. The insurers of TMI-2 had been providing a defense against all TMI-2 accident-related claims against GPU and the Company and its affiliates and their suppliers under a reservation of rights with respect to any award of punitive damages. However, in March 1994, the defendants in the TMI-2 litigation and the insurers agreed that the insurers would withdraw their reservation of rights, with respect to any award of punitive damages. In June 1993, the Court agreed to permit pre-trial discovery on the punitive damage claims to proceed. A trial of ten allegedly representative cases is not likely to begin before 1996. In February 1994, the Court held that the plaintiffs' claims for punitive damages are not barred by the Price- -9- 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. In July 1994, the Court granted defendants' motion for interlocutory appeal of these orders, stating that they raise questions of law that contain substantial grounds for differences of opinion. The issues are now before the United States Court of Appeals for the Third Circuit. In an order issued in April 1994, the Court: (1) noted that the plaintiffs have agreed to seek punitive damages only against GPU and the Company and its affiliates; and (2) stated in part that the Court is of the opinion that any punitive damages owed must be paid out of and limited to the amount of primary and secondary insurance under the Price-Anderson Act and, accordingly, evidence of the defendants' net worth is not relevant in the pending proceeding. NUCLEAR PLANT RETIREMENT COSTS Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the U.S. Department of Energy (DOE). In 1990, the Company and its affiliates submitted a report, in compliance with NRC regulations, setting forth a funding plan (employing the external sinking fund method) for the decommissioning of their nuclear reactors. Under this plan, the Company and its affiliates intend to complete the funding for TMI-1 by 2014, the end of the plant's license term. The TMI-2 funding completion date is 2014, consistent with TMI-2's remaining in long- term storage and being decommissioned at the same time as TMI-1. Under the NRC regulations, the funding target (in 1994 dollars) for TMI-1 is $157 million, of which the Company's share is $79 million. Based on NRC studies, a comparable funding target for TMI-2 has been developed which takes the accident into account (see TMI-2 Future Costs). The NRC continues to study the levels of these funding targets. Management cannot predict the effect that the results of this review will have on the funding targets. NRC regulations and a regulatory guide provide mechanisms, including exemptions, to adjust the funding targets over their collection periods to reflect increases or decreases due to inflation and changes in technology and regulatory requirements. The funding targets, while not considered cost estimates, are reference levels designed to assure that licensees demonstrate adequate financial responsibility for decommissioning. While the regulations address activities related to the removal of the radiological portions of the plants, they do not establish residual radioactivity limits nor do they address costs related to the removal of nonradiological structures and materials. In 1988, a consultant to GPUN performed a site-specific study of TMI-1 that considered various decommissioning plans and estimated the cost of -10- decommissioning the radiological portions of TMI-1 to range from approximately $225 to $309 million, of which the Company's share would range from $113 million to $155 million (in 1994 dollars). In addition, the study estimated the cost of removal of nonradiological structures and materials for TMI-1 at $74 million, of which the Company's share is $37 million (in 1994 dollars). The ultimate cost of retiring the Company and its affiliates' nuclear facilities may be materially different from the funding targets and the cost estimates contained in the site-specific studies. Such costs are subject to (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning. The Company and its affiliates charge to expense and contribute to external trusts amounts collected from customers for nuclear plant decommissioning and nonradiological costs. In addition, the Company has contributed amounts written off for TMI-2 nuclear plant decommissioning in 1991 to TMI-2's external trust and will await resolution of the case pending before the Pennsylvania Supreme Court before making any further contributions for amounts written off by the Company in 1994. Amounts deposited in external trusts, including the interest earned on these funds, are classified as Nuclear Decommissioning Trusts on the balance sheet. TMI-1: The Pennsylvania Public Utility Commission (PaPUC) previously granted the Company revenues for decommissioning costs of TMI-1 based on its share of the NRC funding target and nonradiological cost of removal as estimated in the site-specific study. Collections from customers for retirement expenditures are deposited in external trusts. Provision for the future expenditures of these funds has been made in accumulated depreciation, amounting to $25 million at March 31, 1995. TMI-1 retirement costs are charged to depreciation expense over the expected service life of each nuclear plant. Management believes that any TMI-1 retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable 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 nonradiological cost of removal consistent with the TMI-1 site-specific study and have spent $2 million, of which the Company's share is $1 million, as of March 31, 1995. Estimated TMI-2 Future Costs as of March 31, 1995 and December 31, 1994 for the Company are as follows: -11- March 31, 1995 December 31, 1994 (Millions) (Millions) Radiological Decommissioning $127 $125 Nonradiological Cost of Removal 36 36 Incremental Monitored Storage 9 9 Total $172 $170 The above amounts are reflected as Three Mile Island Unit 2 Future Costs on the balance sheet. At March 31, 1995, $44 million was in trust funds for TMI-2 and included in Nuclear Decommissioning Trusts on the balance sheet. In 1993, a PaPUC rate order for the Company allowed for the future recovery of certain TMI-2 retirement costs. The Pennsylvania Office of Consumer Advocate requested the Commonwealth Court to set aside the PaPUC's 1993 rate order and in 1994, the Commonwealth Court reversed the PaPUC order. In December 1994, the Pennsylvania Supreme Court granted Met-Ed's request to review that decision. Oral argument was held on April 27, 1995, and the matter is pending. As a consequence of the Commonwealth Court decision, the Company recorded pre-tax charges totaling $127.6 million during 1994. The Company will await resolution of the appeal pending before the Pennsylvania Supreme Court before making any nonrecoverable funding contributions to external trusts for their share of these costs. The Company will be similarly required to charge to expense its share of future increases in the estimate of the costs of retiring TMI-2 if the Pennsylvania Supreme Court does not reverse the Commonwealth Court's decision. Future earnings on trust fund deposits for the Company will be recorded as income. Prior to the Commonwealth Court's decision, the Company contributed $40 million to external trusts relating to its share of the accident-related portion of the decommissioning liability. This contribution was not recovered from customers and has been expensed. As a result of TMI-2's entering long-term monitored storage in late 1993, the Company and its affiliates are incurring incremental annual storage costs of approximately $1 million, of which the Company's share is $.50 million. The Company and its affiliates estimate that the remaining annual storage costs will total $19 million, of which the Company's share is $9 million, through 2014, the expected retirement date of TMI-1. INSURANCE The GPU System has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that the GPU System will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of the Company. The decontamination liability, premature decommissioning and property damage insurance coverage for the TMI station totals $2.7 billion. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs -12- and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station. The Price-Anderson Act limits the GPU System's liability to third parties for a nuclear incident at one of its sites to approximately $8.9 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including those owned by the GPU System, could result in assessments of up to $79 million per incident for each of the GPU System's two operating reactors (TMI-2 being excluded under an exemption received from the NRC in 1994), subject to an annual maximum payment of $10 million per incident per reactor. In addition to the retrospective premiums payable under Price-Anderson, the GPU System is also subject to retrospective premium assessments of up to $68 million, of which the Company's share is $18 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 $2.6 million per week for the first year, decreasing by 20 percent for years two and three. COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT Nonutility Generation Agreements: Pursuant to the requirements of the federal Public Utility Regulatory Policies Act (PURPA) and state regulatory directives, the 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 a few 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 March 31, 1995, facilities covered by these agreements having 239 MW of capacity were in service and 117 MW were scheduled to commence operation in 1995. Estimated payments to nonutility generators from 1995 through 1999, assuming all facilities which have existing agreements, or which have obtained orders granting them agreements enter service, are $114 million, $170 million, $280 million, $415 million and $418 million, respectively. These agreements, in the aggregate, will provide approximately 833 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 -13- 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, 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. 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 PaPUC and the New Jersey Board of Public Utilities (NJBPU), there can be no assurance that the Company and its affiliates will continue to be able to recover these costs throughout the term of the related agreements. The GPU System currently estimates that in 1998, when substantially all of these nonutility generation projects are scheduled to be in service, above market payments (benchmarked against the expected cost of electricity produced by a new gas-fired combined cycle facility) will range from $300 million to $450 million annually, of which the Company's share will range from $90 million to $140 million annually. 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 -14- 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 PaPUC and FERC and is recovering or expects to recover such costs in electric rates charged to customers. Regulatory assets are reflected in the Deferred Debits and Other Assets section of the Consolidated Balance Sheet, and regulatory liabilities are reflected in the Deferred Credits and Other Liabilities section of the Consolidated Balance Sheet. Regulatory assets and liabilities, as reflected in the March 31, 1995 Consolidated Balance Sheet, were as follows: (In thousands) Assets Liabilities Income taxes recoverable/refundable through future rates $ 206,479 $ 29,287 TMI-2 deferred costs 5,431 - TMI-2 tax refund - 4,207 Unamortized property losses 2,604 - Unamortized loss on reacquired debt 7,486 - DOE enrichment facility decommissioning 11,477 - Other postretirement benefits 20,656 - Other 303 - Total $ 254,436 $ 33,494 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 being recovered through retail rates for the remaining investment in the plant and fuel core. -15- TMI-2 tax refund: Represents the tax refund related to the tax abandonment of TMI-2. This balance is being amortized by the Company concurrent with its return to customers through a base rate credit. Unamortized property losses: The NRC has mandated that the design of nuclear reactors be documented. As a result, the Company's share of the costs incurred in documenting TMI-1 plant design, in addition to costs incurred in a study used to assess the vulnerability of nuclear reactors to severe accidents, are recorded in this account. The study costs are amortized over the life of the plant. Unamortized loss on reacquired debt: Represents premiums and expenses incurred in the redemption of long-term debt. In accordance with FERC regulations, reacquired debt costs are amortized over the remaining original life of the retired debt. 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 clauses. Other postretirement benefits: Includes costs associated with the adoption of FAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Recovery of these costs is subject to regulatory approval. Amounts related to the decommissioning of TMI-1, 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 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 $145 million for air pollution control equipment by the year 2000. In developing its least-cost plan to comply with the Clean Air Act, the GPU System will continue to evaluate major capital investments compared to participation in the emission allowance market and the use of low-sulfur fuel or retirement of facilities. In September 1994, the Ozone Transport Commission (OTC), consisting of representatives of 12 northeast states (including New Jersey and Pennsylvania) and the District -16- of Columbia, proposed reductions in nitrogen oxide (NOx) emissions it believes necessary to meet ambient air quality standards for ozone and the statutory deadlines set by the Clean Air Act. The Company expects that the U.S. Environmental Protection Agency (EPA) will approve the proposal, and that as a result, the Company will spend an estimated $10 million, beginning in 1997, to meet the reductions set by the OTC. The OTC requires additional NOx reductions to meet the Clean Air Act's 2005 National Ambient Air Quality Standards for ozone. However, the specific requirements that will have to be met, at that time, have not been finalized. The Company and its affiliates are unable to determine what, if any, additional costs will be incurred. The Company has been notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 4 hazardous and/or toxic waste sites. In addition, the Company has been requested to voluntarily participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which it has not yet been named as a PRP. The Company has also been named in lawsuits requesting damages for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the Company. The Company is unable to estimate the extent of possible remediation and associated costs of additional environmental matters. Also unknown are the consequences of environmental issues, which could cause the postponement or cancellation of either the installation or replacement of utility plant. OTHER COMMITMENTS AND CONTINGENCIES The Company's construction programs, for which substantial commitments have been incurred and which extend over several years, contemplate expenditures of $115 million during 1995. As a consequence of reliability, licensing, environmental and other requirements, additions to utility plant may be required relatively late in their expected service lives. If such additions are made, current depreciation allowance methodology may not make adequate provision for the recovery of such investments during their remaining lives. Management intends to seek recovery of such costs through the ratemaking process, but recognizes that recovery is not assured. The Company has entered into long-term contracts with nonaffiliated mining companies for the purchase of coal for certain generating stations in which it has ownership interests. The contracts, which expire between 1995 and the end of the expected service lives of the generating stations, require the purchase of either fixed or minimum amounts of the stations' coal requirements. The price of the coal under the contracts is based on adjustments of indexed cost components. The Company's share of the cost of coal purchased under these agreements is expected to aggregate $27 million for 1995. -17- At the request of the PaPUC, the Company, as well as other affected Pennsylvania electric utilities, have supplied to the PaPUC proposals for the establishment of a nuclear performance standard. The PaPUC has not yet acted on these proposals. During the normal course of the operation of its businesses, in addition to the matters described above, the Company is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. It is not expected that the outcome of these types of matters would have a material effect on the Company's financial position or results of operations. -18- Metropolitan Edison Company and Subsidiary Companies 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 available for common stock for the first quarter ended March 31, 1995 were $16.1 million compared to $36.9 million for the first quarter of 1994. The decrease in first quarter earnings was due primarily to lower interest income as compared to last year, when the Company recognized nonrecurring net interest income of $13 million after-tax which resulted from refunds of previously paid federal income taxes related to the tax retirement of Three Mile Island Unit 2 (TMI-2). Earnings were also negatively affected by lower sales due to warmer winter weather this year as compared to last year and higher reserve capacity expense. OPERATING REVENUES: Total revenues for the first quarter of 1995 decreased 3.5% to $205.7 million as compared to the first quarter of 1994. The components of the changes are as follows: (In Millions) Kilowatt-hour (KWH) revenues (excluding energy portion) $ (7.2) Energy revenues 1.7 Other revenues (1.9) Decrease in revenues $ (7.4) Kilowatt-hour revenues KWH revenues decreased due primarily to lower residential sales resulting from warmer winter temperatures this year as compared to last year. New customer additions in the residential and commercial sectors partially offset the decrease due to weather. Energy revenues Changes in energy revenues do not affect earnings as they reflect corresponding changes in the energy cost rates billed to customers and expensed. Energy revenues increased primarily as a result of increased sales to other utilities. -19- 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 first quarter were negatively impacted by higher reserve capacity expense resulting primarily from higher payments to the Pennsylvania-New Jersey-Maryland Interconnection and the buy-out of a nonutility generation power purchase agreement. Other operation and maintenance The decrease in other O&M expense included payroll and benefits savings resulting from a workforce reduction in 1994 and lower winter storm repair costs. Depreciation and amortization Depreciation and amortization expense increased primarily as a result of increases in depreciable plant. Additions to utility plant consisted primarily of additions to existing generating facilities to maintain system reliability and additions to the transmission and distribution system related to customer growth. 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/(expense), net The decrease was primarily attributable to lower interest income as compared to last year, when the Company recognized $29.8 million in interest income from refunds of previously paid federal income taxes related to the tax retirement of TMI-2. The tax retirement of TMI-2 resulted in a refund for the tax years after TMI-2 was retired. INTEREST CHARGES AND PREFERRED DIVIDENDS: Other interest Other interest expense decreased due to 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 $7 million pre-tax charge to interest expense on additional amounts owed for tax years in which depreciation deductions with respect to TMI-2 had been taken. -20- Dividends on preferred securities of subsidiary During the third quarter of 1994, the Company issued $100 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 first quarter of 1995 consisted of cash construction expenditures of $38 million. Construction expenditures for the year are forecasted to be $115 million. Expenditures for maturing debt are expected to be $41 million for 1995. Management estimates that approximately one-half of the capital needs in 1995 will be satisfied through internally generated funds. FINANCING: During the first quarter of 1995, the Company issued $30 million of long- term debt. The proceeds from the issuance were used to reduce short-term debt. GPU has obtained regulatory authorization from the Securities and Exchange Commission (SEC) to issue up to five million shares of additional common stock through 1996. The proceeds from any sale of such additional common stock are expected to be used to increase the Company and its affiliates' common equity ratios and reduce GPU short-term debt. GPU will monitor the capital markets as well as its capitalization ratios relative to its targets to determine whether, and when, to issue such shares. The Company has regulatory authority to issue and sell first mortgage bonds, which may be issued as secured medium-term notes, and preferred stock through 1995. Under existing authorization, the Company may issue senior securities in the amount of $220 million, of which $100 million may consist of preferred stock. The Company, through its special-purpose subsidiary, has remaining regulatory authority to issue an additional $25 million of monthly income preferred securities. The Company also has regulatory authority to incur short-term debt, a portion of which may be through the issuance of commercial paper. The Company's bond indentures and articles of incorporation include provisions that limit the amount of long-term debt, preferred stock and short- term debt the Company may issue. As a result of the second quarter 1994 write-off of TMI-2 retirement costs, together with certain other costs recognized in the same period, the Company will be unable to meet the interest and preferred dividend coverage requirements of its indenture and charter, respectively, until the third quarter of 1995. Therefore, the Company's ability to issue senior securities through June 1995 will be limited to the issuance of first mortgage bonds on the basis of $35 million of previously issued and retired bonds. The ability of the Company to issue, through its special-purpose subsidiary, its remaining authorized monthly income preferred securities, is not affected by these write-offs since these securities have no such coverage restrictions. -21- COMPETITIVE ENVIRONMENT: In March 1995, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on open access non-discriminatory transmission services by public utilities and transmitting utilities, and a supplemental NOPR on recovery of stranded costs superseding an earlier June 1994 NOPR, and other related NOPRs. The new rules, if adopted, would in essence provide open access to the interstate electric transmission network and thereby encourage a fully competitive wholesale electric power market. Among other things, the FERC's proposal would (a) require electric utilities to file non-discriminatory open access transmission tariffs for both network and point-to-point service which would be available to all wholesale sellers and buyers of electricity; (b) require utilities to accept service under these new tariffs for their own wholesale transactions and (c) permit utilities to recover their legitimate and verifiable "stranded costs" incurred when a franchise customer elects to purchase power from another supplier using the utility's transmission system. While the proposed rule does not provide for "corporate unbundling", which the FERC defines as the disposing of ancillary services or creating separate affiliates to manage transmission services, it does provide for "functional unbundling". In the NOPR, the FERC describes "functional unbundling" to mean that (a) the utility must make the same charges for transmission services to its new wholesale customers as are provided by the tariff under which it offers these services to others; (b) the tariff must include separate rates for transmission and ancillary services; and (c) the utility is restricted to using the same electronic network as is used by its customers to obtain system transmission information when engaging in wholesale transactions, and the utility may not have access to any internal system transmission data which is not otherwise available to non-affiliated third parties. With respect to stranded costs, the FERC proposed to provide recovery mechanisms where stranded costs result from municipalization or other instances where former retail customers become wholesale customers, as well as for wholesale stranded costs. The states would be expected to provide for recovery of stranded costs attributable to retail wheeling or direct access programs, and the FERC would intervene only when the state regulatory agency lacked necessary authority. Also in March 1995, prior to the FERC's issuance of the NOPR, the Company filed with the FERC proposed open access transmission tariffs. Such proposed tariffs provide for both firm and interruptible service on a point-to-point basis. Network service, where requested, would be negotiated on a case by case basis. While the Company believes that the proposed transmission tariffs are consistent with the FERC's previously issued Transmission Pricing Policy Statement, it does not know whether or to what extent the FERC will require modifications to any of the proposed terms and conditions of transmission tariffs. -22- In March 1994, GPU announced its intention to form a new subsidiary, GPU Generation Corporation (GPUGC), to operate, maintain and repair the non- nuclear generation facilities owned by the Company and its affiliates as well as undertake responsibility to construct any new non-nuclear generation facilities which the Company and its affiliates may need in the future. During 1994, the Company and its affiliates received regulatory approvals from the Pennsylvania Public Utility Commission (PaPUC) and New Jersey Board of Public Utilities to enter into an operating agreement with GPUGC. In June 1994, however, Allegheny Electric Cooperative (AEC), a wholesale customer of an affiliate, filed a request for evidentiary hearing in the application filed with the SEC to form GPUGC. The intervention does not challenge the formation of GPUGC, but purports to be concerned with costs that GPUGC will charge the Company and its affiliates, from which AEC ultimately purchases power. The Company and its affiliates have opposed AEC's request and the matter is pending before the SEC. In April 1995, legislation was introduced in the U.S. Senate that would repeal Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA). Under that section of PURPA, among other things, electric utilities are required to purchase power from certain qualifying nonutility generators. THE SUPPLY PLAN: Managing Nonutility Generation The Company is 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. In addition, the Company intends to avoid, to the maximum extent practicable, entering into any new nonutility generation agreements that are not needed or not consistent with current market pricing and are supporting legislative efforts to repeal PURPA. These efforts may result in claims against the Company for substantial damages. There can, however, be no assurance as to what extent the Company's efforts will be successful in whole or in part. The following is a discussion of some major nonutility generation activities involving the Company. In April 1995, the Company reached a buy-out agreement with the developer of a 13 MW nonutility generating facility. The Company estimates that the buy-out of the uneconomic power purchase contract will save its customers $16 million over 25 years. The Company has petitioned the PaPUC for approval to recover from customers the $1.65 million buy-out cost. In April 1995, the Company filed a petition with the PaPUC requesting that the PaPUC rescind its 1992 order directing the Company to enter into a long-term power purchase agreement with the developers of a proposed 100 MW nonutility generating facility in the City of Scranton, Pennsylvania. The Company is seeking relief from that order on the grounds that the project developers no longer plan to construct the project in the City of Scranton which was a principal reason for the PaPUC's order. The Company also contends that the rates payable under the contract, which is not in effect since the PaPUC has not granted the Company energy cost rate recovery, are $298 million in excess of the projected costs of alternative power. -23- In May 1995, the Company filed a petition for enforcement and declaratory order with the FERC requesting that the FERC declare the PaPUC's PURPA implementation procedures unlawful. Specifically, the Company contends that the PaPUC's procedures that result in orders to enter into contracts with qualifying facilities at prices based on the costs of a "coal proxy" plant violate PURPA and the FERC's implementing regulations. The Company has requested that the FERC declare void power purchase agreements and related obligations representing 327 MW of capacity and energy which the PaPUC has ordered the Company to enter into under this procedure. In 1994, a nonutility generator requested that the PaPUC order the Company to enter into a long-term agreement to buy capacity and energy. The Company sought to dismiss the request based on a May 1994 PaPUC order, which granted the Company permission to obtain additional nonutility purchases through competitive bidding until new PaPUC regulations have been adopted. In September 1994, the Pennsylvania Commonwealth Court granted the PaPUC's application to revise its May 1994 order for the purpose of reevaluating the nonutility generator's right to sell power to the Company. The PaPUC subsequently ordered that hearings be held in this matter. In March 1995, the Company filed a motion seeking to dismiss the nonutility generator's petition. The Company has contracts and anticipated commitments with nonutility generation suppliers under which a total of 239 MW of capacity are currently in service and an additional 594 MW are currently scheduled or anticipated to be in service by 1999. Conservation and Load Management In a December 1993 order, the PaPUC adopted guidelines for the recovery of demand side management (DSM) costs and directed utilities to implement DSM programs. The Company subsequently filed a DSM program that was expected to be approved by the PaPUC in the first quarter of 1995. However, an industrial intervenor had contested the PaPUC's guidelines and, in January 1995, the Commonwealth Court reversed the PaPUC order. The PaPUC is appealing that decision to the Pennsylvania Supreme Court. As a result, the nature and scope of the Company's DSM program is uncertain at this time. ACCOUNTING ISSUES: In March 1995, the Financial Accounting Standards Board (FASB) issued FAS 121, "Accounting for the Impairment of Long-Lived Assets", which is effective for fiscal years beginning after June 15, 1995. FAS 121 requires that long- lived assets, identifiable intangibles, capital leases and goodwill be reviewed for impairment whenever events occur or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In addition, FAS 121 requires that regulatory assets meet the recovery criteria of FAS 71, "Accounting for the Effects of Certain Types of Regulation", on an ongoing basis in order to avoid a writedown. -24- FAS 121 implementation in 1996 is not expected to have an impact on the Company since the carrying amount of all assets, including regulatory assets, is considered recoverable. However, as the Company enters a more competitive environment, some assets could potentially be subject to impairment, thereby necessitating writedowns or writeoffs, which could have a material adverse effect on the Company's results of operations and financial position. -25- 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 6 - EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits (12) Statements Showing Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends (27) Financial Data Schedule (b) Reports on Form 8-K: For the month of April 1995, dated April 20, 1995, under Item 5 (Other Events). -26- 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. METROPOLITAN EDISON COMPANY May 4, 1995 By: /s/ F. D. Hafer F. D. Hafer, President May 4, 1995 By: /s/ D. L. O'Brien D. L. O'Brien, Comptroller (Principal Accounting Officer) -27- EX-99 2 EXHIBIT 12 TO ME 95 10K Exhibit 12 METROPOLITAN EDISON COMPANY AND SUBSIDIARY COMPANIES 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 Three Months Ended March 31, March 31, 1995 1994 OPERATING REVENUES $205 749 $213 159 OPERATING EXPENSES (excluding taxes based on income) 162 729 159 238 Interest portion of rentals (A) 1 144 1 385 Net expense 163 873 157 853 OTHER INCOME: Allowance for funds used during construction 850 580 Other income, net (2 161) 30 194 Total other income (1 311) 30 774 EARNINGS AVAILABLE FOR FIXED CHARGES $ 40 565 $ 86 080 FIXED CHARGES: Interest on funded indebtedness $ 11 012 $ 10 718 Other interest (B) 3 239 9 496 Interest portion of rentals (A) 1 144 1 385 Total fixed charges $ 15 395 $ 21 599 RATIO OF EARNINGS TO FIXED CHARGES 2.63 3.99 Preferred stock dividend requirement $ 236 $ 908 Ratio of income before provision for income taxes to net income (C) 167.6% 170.6% Preferred stock dividend requirement on a pre-tax basis 396 1 549 Fixed Charges, as above 15 395 21 599 Total fixed charges and preferred stock dividends $ 15 791 $ 23 148 RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS 2.57 3.72 NOTES: (A)The Company included the equivalent of the interest portion of all rentals charged to income as fixed charges for this statement and excluded such components from Operating Expenses. (B)Includes dividends on preferred securities of subsidiary of $2,250 for 1995. (C)Represents income before provision of income taxes of $27,458 and $64,481 for 1995 and 1994, respectively, divided by income of $16,384 and $37,802. EX-27 3 ME FIN. DATA SCHEDULE TO 1995 10Q
UT 1,000 US DOLLARS 3-MOS DEC-31-1995 JAN-01-1995 MAR-31-1995 1 PER-BOOK 1,582,358 81,329 183,301 415,297 0 2,262,285 66,273 345,200 168,157 579,630 0 123,598 559,784 18,700 0 38,721 40,517 0 1,863 32,185 867,287 2,262,285 205,749 11,865 162,729 174,594 31,155 (915) 30,240 13,856 16,384 236 16,148 40,000 11,012 (10,073) 0 0 INCLUDES PREFERRED SECURITIES OF SUBSIDIARY OF $100,000. INCLUDES DIVIDENDS ON PREFERRED SECURITIES OF SUBSIDIARY OF $2,250. REPRESENTS COMMON STOCK DIVIDENDS PAID TO PARENT CORPORATION.
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